New Jersey Resources Corp: Form 10-Q for the period ended Mar 31, 2026

OPERATIONS

Critical Accounting Estimates

A summary of our critical accounting policies is included in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations of our Annual Report on Form 10-K for the period ended September 30, 2025. Our critical accounting policies have not changed from those reported in the 2025 Annual Report on Form 10-K.

Recently Issued Accounting Standards

Refer to Note 2. Summary of Significant Accounting Policies for discussion of recently issued accounting standards.

Management's Overview

Consolidated

NJR is a diversified energy services holding company providing retail natural gas service in New Jersey and wholesale natural gas and related energy services to customers in the U.S. In addition, we invest in clean energy projects, storage and transportation assets and provide various repair, sales and installation services. A more detailed description of our organizational structure can be found in Item 1. Business of our 2025 Annual Report on Form 10-K.

Reportable Segments

We have four primary reportable segments as presented in the chart below:

In addition to our four reportable segments above, we have nonutility operations that either provide corporate support services or do not meet the criteria to be treated as a separate reportable segment. These operations, which comprise HSO, include: appliance repair services, sales and installations at NJRHS and commercial real estate holdings at Commercial Realty & Resources Corp.

Operating Results

Net income by reportable segment and other business operations, which are discussed in more detail within the operating results sections of each reportable segment and other business operations, are as follows:

Consolidated net income increased approximately $14.6M during the three months ended March 31, 2026, compared with the three months ended March 31, 2025, due primarily to the following factors:

• $8.4M increase at ES related to market volatility due to the colder weather;
• $5.4M increase at S&T due to higher rates at Adelphia; and
• $4.0M increase at NJNG due to higher BGSS incentives and customer growth.

Consolidated net income increased approximately $5.8M during the six months ended March 31, 2026, compared with the six months ended March 31, 2025, due primarily to the following factors:

• $20.9M increase at NJNG due to higher base rates and BGSS incentives, along with customer growth;
• $18.8M increase at ES as previously discussed; and
• $7.1M increase at S&T as previously discussed, partially offset by;
• $39.8M decrease at CEV due to the gain on sale of the residential solar portfolio in the prior period.

The primary drivers of the changes noted above are described in more detail in the individual reportable segment and other business operations discussions.

Assets by reportable segment and operations are as follows:

(1) Consists of transactions between subsidiaries that are eliminated in consolidation.

Consolidated assets increased approximately $364.5M as of March 31, 2026, compared with September 30, 2025, due primarily to the following factors:

• $350.0M increase in cash and customer receivables at NJNG, due to seasonality;
• $146.4M increase in utility plant expenditures, net at NJNG; and
• $112.1M increase in nonutility plant and equipment, net at CEV due primarily to additional capital expenditures for commercial solar projects; partially offset by
• $155.3M decrease in gas in storage mainly at NJNG, due to seasonality; and
• $40.6M decrease in prepaid taxes mainly at NJNG, due to timing of payments.

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Non-GAAP Financial Measures

Our management uses net income and NFE, a non-GAAP financial measure, when evaluating our operating results. ES economically hedges its natural gas inventory with financial derivative instruments. NFE is a measure of the earnings based on eliminating timing differences surrounding the recognition of certain gains or losses, to effectively match the earnings effects of the economic hedges with the physical sale of natural gas and, therefore, eliminates the impact of volatility to GAAP earnings associated with the derivative instruments. To the extent we utilize forwards, futures, or other derivatives to hedge forecasted SREC production, unrealized gains and losses are also eliminated from NFE. Included in the tax effects are current and deferred income tax expense corresponding with the components of NFE.

GAAP requires us, during the interim periods, to estimate our annual effective tax rate and use this rate to calculate the year-to-date tax provision. We also determine an annual estimated effective tax rate for NFE purposes and calculate a quarterly tax adjustment based on the differences between our forecasted net income and our forecasted NFE for the fiscal year. Since the annual estimated effective tax rate is based on certain forecasted assumptions, the rate and resulting NFE are subject to change. No adjustment is needed during the fourth quarter, since the actual effective tax rate is calculated at year end.

Non-GAAP financial measures are not in accordance with, or an alternative to, GAAP and should be considered in addition to, and not as a substitute for or a replacement of, the comparable GAAP measure and should be read in conjunction with those GAAP results. Below is a reconciliation of consolidated net income, the most directly comparable GAAP measure, to NFE:

(Thousands, except per share data)

(1) Effects of hedging natural gas inventory transactions where the economic impact is realized in a future period.

NFE by reportable segment and other business operations, which are discussed in more detail within the operating results sections of each reportable segment and other business operations, is summarized as follows:

(1) Consists of transactions between subsidiaries that are eliminated in consolidation.

Consolidated NFE increased approximately $43.2M during the three months ended March 31, 2026, compared with the three months ended March 31, 2025, due primarily to the following factors:

• $37.0M increase at ES due to higher Financial Margin related to market volatility due to the colder weather;
• $5.4M increase at S&T due to higher rates at Adelphia; and
• $4.0M increase at NJNG due to higher BGSS incentives and customer growth.

Consolidated NFE increased approximately $32.4M during the six months ended March 31, 2026, compared with the six months ended March 31, 2025, due primarily to the following factors:

• $45.4M increase at ES, as previously discussed;
• $20.9M increase at NJNG due to higher base rates and BGSS incentives, along with customer growth;
• $7.1M increase at S&T as previously discussed; partially offset by
• $39.8M decrease at CEV, due to the gain on sale of the residential solar portfolio in the prior period.

Natural Gas Distribution

Overview

Natural Gas Distribution is comprised of NJNG, a natural gas utility that provides regulated natural gas service to residential and commercial customers throughout Burlington, Middlesex, Monmouth, Morris, Ocean, and Sussex counties in New Jersey and also participates in the off-system sales and capacity release markets. The business is subject to various risks, which may include but are not limited to impacts to customer growth and customer usage, customer collections, the timing and costs of capital expenditures and construction of infrastructure projects, operating and financing costs, fluctuations in commodity prices, customer conservation efforts and changes in how customers consume energy. In addition, NJNG may be subject to adverse economic conditions such as inflation and rising natural gas costs, certain regulatory actions, environmental remediation and severe weather conditions. It is often difficult to predict the impact of events or trends associated with these risks.

NJNG’s business is seasonal by nature, as weather conditions directly influence the volume of natural gas delivered to customers on an annual basis. Specifically, customer demand substantially increases during the winter months when natural gas is used for heating purposes. As a result, NJNG generates most of its natural gas distribution revenues during the first and second fiscal quarters and is subject to variations in earnings and working capital during the fiscal year.

As a regulated company, NJNG is required to recognize the impact of regulatory decisions on its financial statements. See Note 4. Regulation in the accompanying Unaudited Condensed Consolidated Financial Statements for a more detailed discussion of regulatory actions, including filings related to programs and associated expenditures, as well as rate requests related to recovery of capital investments and operating costs.

NJNG’s operations are managed with the goal of providing safe and reliable service, growing its customer base, diversifying its Utility Gross Margin, promoting clean energy programs and mitigating the risks discussed above.

Base Rate Case

On November 21, 2024, the BPU issued an order adopting a stipulation of settlement approving a $157.0M increase to base rates, effective as of the date of the order. The increase includes an overall rate of return on rate base of 7.08%, return on common equity of 9.6%, a common equity ratio of 54.0% and a composite depreciation rate of 3.21%.

Infrastructure Projects

NJNG has significant annual capital expenditures associated with the management of its natural gas distribution and transmission system, including new utility plant expenditures associated with customer growth and its associated pipeline integrity management and infrastructure programs.

Below is a summary of NJNG’s capital expenditures, including accruals, for the six months ended March 31, 2026, and estimates of expected investments for fiscal 2026 and 2027:

Estimated capital expenditures are reviewed on a regular basis and may vary based on the ongoing effects of regulatory oversight, environmental regulations, unforeseen events and the ability to access capital.

Infrastructure Investment Program

In October 2020, the BPU approved NJNG’s five-year IIP filing for $150.0M of transmission and distribution investments, effective November 1, 2020, which were recovered through annual filings to adjust base rates.

In July 2025, NJNG submitted a filing with the BPU to extend the IIP through June 30, 2026.

On December 17, 2025, the BPU approved NJNG's final IIP filing, which requested a rate increase for capital expenditures of approximately $33.1M through October 31, 2025, resulting in a revenue increase of approximately $3.3M, effective January 1, 2026. In conjunction with this filing, NJNG notified the BPU that it was withdrawing its July 2025 request to extend the program. Any recovery of future infrastructure investments will be requested through a NJNG base rate case.

Natural Gas Customers

In conducting NJNG's business, management focuses on factors it believes may have significant influence on its future financial results. NJNG's policy is to work with all stakeholders, including customers, regulators and policymakers, to achieve favorable results. These factors include the rate of NJNG's customer growth in its service territory, which can be influenced by political and regulatory policies, the delivered cost of natural gas compared with competing fuels, interest rates and general economic and business conditions.

NJNG's total customers include the following:

NJNG expects new customer additions during the six months ended March 31, 2026, and those customers who added additional natural gas services to their premises, to contribute approximately $4.0M of incremental Utility Gross Margin on an annualized basis.

Energy Efficiency Programs

SAVEGREEN conducts home energy audits and provides various grants, incentives and financing alternatives designed to encourage the installation of high-efficiency heating and cooling equipment and other energy efficiency upgrades. Depending on the specific incentive or approval, NJNG recovers costs associated with the programs over a three- to 10-year period through a tariff rider mechanism.

In March 2021, the BPU approved a three-year SAVEGREEN program consisting of approximately $126.1M of direct investment, $109.4M in financing options, and $23.4M in O&M. In April 2024, the BPU approved NJNG’s $76.9M extension to this SAVEGREEN program through December 2024.

In October 2024, the BPU approved a new SAVEGREEN program effective from January 1, 2025 to June 30, 2027, consisting of $205.0M of direct investment, $160.5M in financing options and $20.1M in O&M. Recoveries include a weighted average cost of capital that ranges from 6.9% to 7.08%, with a return on equity of 9.6%.

In December 2024, the BPU approved NJNG's annual SAVEGREEN filing for the recovery of costs, which increased annual recoveries by approximately $3.1M, effective January 1, 2025.

On December 17, 2025, the BPU approved NJNG's annual SAVEGREEN filing for the recovery of costs, which will increase annual recoveries by approximately $13.3M, effective January 1, 2026.

The following table summarizes loans, grants, rebates and related investments through:

(1) Amounts have been updated to correct the prior year presentation.

Conservation Incentive Program/BGSS

The CIP facilitates normalizing NJNG’s Utility Gross Margin for variances due not only to weather but also other factors affecting customer usage, such as conservation and energy efficiency. Recovery of Utility Gross Margin for the non-weather variance through the CIP is limited to the amount of certain natural gas supply cost savings achieved and is subject to a variable margin revenue test. Additionally, recovery of the CIP Utility Gross Margin is subject to an annual earnings test. An annual review of the CIP must be filed by June 1, coincident with NJNG’s annual BGSS filing, during which NJNG can request rate changes to the CIP.

NJNG's total utility firm gross margin includes the following adjustments related to the CIP mechanism:

(1) Compared with the 20-year average, weather was 4.6% and 6.5% colder-than-normal during the three and six months ended March 31, 2026, and 0.4% and 3.4% warmer-than-normal during the three and six months ended March 31, 2025.

Recovery of Natural Gas Costs

NJNG’s cost of natural gas is passed through to our customers, without markup, by applying NJNG’s authorized BGSS rate to actual therms delivered. There is no Utility Gross Margin associated with BGSS costs; therefore, changes in such costs do not impact NJNG’s earnings. NJNG monitors its actual natural gas costs in comparison to its BGSS rates to manage its cash flows associated with its allowed recovery of natural gas costs, which is facilitated through BPU-approved deferred accounting and the BGSS pricing mechanism. Accordingly, NJNG occasionally adjusts its periodic BGSS rates or can issue credits or refunds, as appropriate, for its residential and small commercial customers when the commodity cost varies from the existing BGSS rate. BGSS rates for its large commercial customers are adjusted monthly based on NYMEX prices.

NJNG’s residential and commercial markets are currently open to competition, and its rates are segregated between BGSS (i.e., natural gas commodity) and delivery (i.e., transportation) components. NJNG earns Utility Gross Margin through the delivery of natural gas to its customers and, therefore, is not negatively affected by customers who use its transportation service and purchase natural gas from another supplier. Under an existing order from the BPU, BGSS can be provided by suppliers other than the state’s natural gas utilities; however, customers who purchase natural gas from another supplier continue to use NJNG for transportation service.

On October 31, 2025, NJNG notified the BPU that it intended to self-implement an increase to its BGSS rate, effective December 1, 2025 through September 30, 2026, which will result in an increase of approximately $38.1M in revenues related to BGSS.

On December 17, 2025, the BPU approved, on a provisional basis, NJNG's annual BGSS/CIP filing, which included an increase of approximately $6.1M related to its balancing charge and a decrease of approximately $26.2M to CIP rates, effective January 1, 2026. The balancing charge rate includes the cost of balancing natural gas deliveries with customer usage for sales and transportation customers, and balancing charge revenues are credited to BGSS.

BGSS Incentive Programs

NJNG is eligible to receive financial incentives for reducing BGSS costs through a series of Utility Gross Margin-sharing programs that include off-system sales, capacity release and storage incentive programs. These programs are designed to encourage better utilization and hedging of NJNG’s natural gas supply and transportation and storage assets. Depending on the program, NJNG shares 80% or 85% of Utility Gross Margin generated by these programs with firm customers. Utility Gross Margin from incentive programs was approximately $11.7M and $7.4M during the three months ended March 31, 2026 and 2025, respectively, and approximately $17.3M and $10.6M during the six months ended March 31, 2026 and 2025, respectively.

Hedging

In order to provide relative price stability to its natural gas supply portfolio, NJNG employs a hedging strategy with the goal of having at least 75% of the Company's projected winter periodic BGSS natural gas sales volumes hedged by each November 1 and at least 25% of the projected periodic BGSS natural gas sales hedged for the following April through March period. The hedging goal is typically achieved with gas in storage and the use of financial instruments to hedge storage injections. NJNG may also use various financial instruments including futures, swaps, options and weather related products to hedge its future delivery obligations.

Commodity Prices

NJNG is affected by the price of natural gas, which can have a significant impact on our cash flows and short-term financing costs, the price of natural gas charged to our customers through the BGSS clause, our ability to collect accounts receivable, which impacts our bad debt expense, and our ability to maintain a competitive advantage over other energy sources. Natural gas commodity prices are shown in the graph below, which illustrates the daily natural gas prices per MMBtu*(1)* in the Northeast market region, also known as TETCO M-3.

(1) Data sourced from Standard & Poor's Financial Services, LLC Global Platts.

The maximum price per MMBtu was $122.84 and $40.02 and the minimum price was $1.42 and $1.05 for the six months ended March 31, 2026 and 2025, respectively. As a result of NJNG's hedging strategy as previously discussed, customers are protected from much of the short-term price volatility during the winter months. A more detailed discussion of the impacts of the price of natural gas on operating revenues, natural gas purchases and cash flows can be found in the Operating Results and Cash Flow sections of Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.

Societal Benefits Charge

The SBC is comprised of three primary riders that allow NJNG to recover costs associated with USF, MGP remediation, and the NJCEP. NJNG’s qualifying customers are eligible for the USF program, which is administered by the New Jersey Department of Community Affairs, to help make energy bills more affordable.

In April 2025, the BPU approved NJNG's annual SBC filing of RAC expenditures through June 30, 2024, which included an increase to the RAC annual recoveries of approximately $2.4M and an increase to the NJCEP annual recoveries of approximately $1.6M, effective May 1, 2025.

In September 2025, the BPU approved NJNG's annual USF filing, which resulted in a decrease to annual recoveries of approximately $1.0M, effective October 1, 2025.

In September 2025, NJNG submitted its annual SBC filing to the BPU requesting approval of RAC expenditures through June 2025, which included a decrease to the RAC annual recoveries of approximately $0.9M and a decrease to the NJCEP annual recoveries of approximately $5.0M, which would be effective April 1, 2026.

On March 18, 2026, the BPU approved NJNG's annual SBC filing of RAC expenditures through June 30, 2025, which included a decrease to the RAC annual recoveries of approximately $0.8M and a decrease to the NJCEP annual recoveries of approximately $5.2M, effective April 1, 2026.

Environmental Remediation

NJNG is responsible for the environmental remediation of former MGP sites, which contain contaminated residues from former gas manufacturing operations that ceased operating at these sites by the mid-1950s and, in some cases, had been discontinued many years earlier. Actual MGP remediation costs may vary from management’s estimates due to the developing nature of remediation requirements, regulatory decisions by the NJDEP and related litigation. NJNG reviews these costs periodically, and at least annually, and adjusts its liability and corresponding regulatory asset as necessary to reflect its expected future remediation obligation. Accordingly, NJNG recognized a regulatory asset and an obligation of approximately $166.1M as of March 31, 2026, a decrease of approximately $0.9M compared with September 30, 2025. See Note 13. Commitments and Contingent Liabilities for a more detailed description of MGP expenditures.

Other regulatory filings and a more detailed discussion of the filings in this section can be found in Note 4. Regulation in the accompanying Unaudited Condensed Consolidated Financial Statements.

Operating Results

NJNG's operating results are as follows:

(1) Includes immaterial nonutility revenue for lease agreements with various NJR subsidiaries leasing office space from NJNG at the Company’s headquarters, which are eliminated in consolidation.

(2) Includes the purchased cost of the natural gas, fees paid to pipelines and storage facilities, adjustments as a result of BGSS incentive programs and hedging transactions. These expenses are passed through to customers and are offset by corresponding revenues.

(3) Includes related party transactions of approximately $1.6M and $2.3M during the three months ended March 31, 2026 and 2025, respectively, and $3.2M and $4.7M during the six months ended March 31, 2026 and 2025, respectively, a portion of which is eliminated in consolidation.

(4) Consists of expenses associated with state-mandated programs, the RAC and energy efficiency programs, which are calculated on a per-therm basis. These expenses are passed through to customers and are offset by corresponding revenues.

Operating Revenues and Natural Gas Purchases

Operating revenues increased 3.6% and natural gas purchases increased 0.5% during the three months ended March 31, 2026, compared with the three months ended March 31, 2025. Operating revenues increased 10.4% and natural gas purchases increased 10.4% during the six months ended March 31, 2026, compared with the six months ended March 31, 2025.

The factors contributing to the increases and decreases in operating revenues and natural gas purchases are as follows:

(1) Riders and other includes changes in rider rates, including those related to SAVEGREEN, NJCEP and other programs, which is offset in regulatory rider expense.

Non-GAAP Financial Measures

Management uses Utility Gross Margin, a non-GAAP financial measure, when evaluating the operating results of NJNG. NJNG's Utility Gross Margin is defined as operating revenues less natural gas purchases, sales tax, and regulatory rider expenses. This measure differs from gross margin as presented on a GAAP basis as it excludes certain operations and maintenance expense and depreciation and amortization. Utility Gross Margin may also not be comparable to the definition of gross margin used by others in the natural gas distribution business and other industries. We believe that Utility Gross Margin provides a meaningful basis for evaluating utility operations since natural gas costs, sales tax and regulatory rider expenses are included in operating revenues and passed through to customers and, therefore, have no effect on Utility Gross Margin. Non-GAAP financial measures are not in accordance with, or an alternative to, GAAP and should be considered in addition to, and not as a substitute for, the comparable GAAP measure.

Utility Gross Margin

A reconciliation of gross margin, the closest GAAP financial measure to NJNG's Utility Gross Margin, is as follows:

(1) Excludes SG&A of approximately $51.0M and $31.7M for the three months ended March 31, 2026 and 2025, respectively, and $55.1M and $57.8M for the six months ended March 31, 2026 and 2025, respectively.

Utility Gross Margin consists of three components:

• Utility firm gross margin generated from only the delivery component of either a sales tariff or a transportation tariff from residential and commercial customers who receive natural gas service from NJNG;
• BGSS incentive programs, where revenues generated or savings achieved from BPU-approved off-system sales, capacity release or storage incentive programs are shared between customers and NJNG; and
• Utility Gross Margin generated from off-tariff and interruptible customers.

The following provides more information on the components of Utility Gross Margin and associated throughput (Bcf) of natural gas delivered to customers:

($ in thousands)

Utility Firm Gross Margin

Utility firm gross margin increased approximately $6.1M during the three months ended March 31, 2026, compared with the three months ended March 31, 2025, due primarily to customer growth. Utility firm gross margin increased $28.7M during the six months ended March 31, 2026, compared with the six months ended March 31, 2025, due primarily to an increase in base rates, effective November 21, 2024, along with customer growth.

BGSS Incentive Programs

The factors contributing to the change in Utility Gross Margin generated by BGSS incentive programs are as follows:

BGSS incentive programs increased during the three months ended March 31, 2026, compared with the three months ended March 31, 2025, due primarily to higher margins from off-system sales and capacity release, related to market volatility due to colder weather. BGSS incentive programs increased during the six months ended March 31, 2026, compared with the six months ended March 31, 2025, due primarily to higher margins from off-system sales and storage.

Net Income

Net income increased approximately $4.0M during the three months ended March 31, 2026, compared with the three months ended March 31, 2025, due primarily to the following factors:

• $10.3M increase in Utility Gross Margin, as previously discussed; partially offset by
• $4.5M increase in O&M due to higher employee expenses.

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OPERATIONS (Continued)

Net income increased approximately $20.9M during the six months ended March 31, 2026, compared with the six months ended March 31, 2025, due primarily to the following factors:

• $35.3M increase in Utility Gross Margin, as previously discussed; partially offset by
• $6.7M increase in depreciation expense as a result of additional utility plant being placed into service;
• $3.8M increase in interest expense due to higher outstanding long-term debt; and
• $3.4M increase in income tax expense related to higher operating income.

Clean Energy Ventures

Overview

CEV actively pursues opportunities in the renewable energy markets, which includes the development, construction and operation of net metered and grid-connected commercial solar projects. In addition, CEV enters into various long-term agreements, including PPAs, to supply energy from commercial solar projects.

Capital expenditures related to clean energy projects are subject to change due to a variety of factors that may affect our ability to commence operations at these projects on a timely basis or at all, including logistics associated with the start-up of commercial solar projects, changes to U.S. trade policy and the impact tariffs and other costs and assessments may have on equipment used to construct, generate, and deliver clean energy, such as timing of construction schedules, the permitting and regulatory process, any delays related to electric grid interconnection. Other factors include economic trends, changes in law, governmental policies, or incentives that support clean energy projects, unforeseen events and the ability to access capital or allocation of capital to other investments or business opportunities. CEV is also subject to various risks, which may include our ability to identify and develop commercial solar asset investments, impacts to our supply chain and our ability to source materials for construction.

The primary contributors toward the value of qualifying clean energy projects are tax incentives, RECs and electricity sales. Changes in the laws and regulations related to the ITC and/or relevant state legislation and regulatory policies affecting the market for solar renewable energy credits could significantly affect future results.

In July 2025, OBBBA was signed into law, which modifies several pre-existing provisions of the Inflation Reduction Act and other laws, including the phase-out of certain clean energy tax credits. In order to be eligible for ITCs, solar facilities must be placed in service by December 31, 2027, unless construction begins before July 4, 2026, and must satisfy the prohibited foreign entity material assistance requirements, unless construction begins before December 31, 2025.

In July 2025, the President of the U.S. issued a federal executive order directing the Secretary of the Treasury to provide revised guidance on determining the beginning of construction for renewable energy projects for purposes of claiming ITCs. In August 2025, the IRS released further guidance to clarify the beginning of construction for renewable energy projects deemed to have started construction on or after September 2, 2025.

While there have been no material impacts to the Company’s financial position or results of operations as of March 31, 2026, resulting from the change in law and revised IRS guidance, these changes may impact our ability to identify, develop and source materials to construct future projects in a way that meets the new requirements established for the ITC framework.

CEV placed one commercial solar project in service, totaling 3.7 MWs, during the three months ended March 31, 2026, with related expenditures of approximately $9.3M. CEV placed three commercial solar projects in service totaling 13.4 MWs during the six months ended March 31, 2026, with related expenditures of approximately $30.2M. CEV placed one commercial solar project in service totaling 2.2 MWs during the three months ended March 31, 2025, with related expenditures of approximately $8.3M. CEV placed three commercial solar projects in service totaling 12.7 MWs during the six months ended March 31, 2025, with related expenditures of approximately $28.7M. CEV has approximately 493 MW of commercial solar capacity in service.

CEV may enter into transactions to sell certain of its commercial solar assets concurrent with agreements to lease the assets back over a period of five to seven years. The Company will continue to operate the solar assets and is responsible for related expenses and entitled to retain the revenue generated from RECs and energy sales. ITCs and other tax attributes associated with these solar projects transfer to the buyer if applicable; however, the lease payments are structured so that CEV is compensated for the transfer of the related tax incentives. Accordingly, for solar projects financed under sale leasebacks for which the assets were sold during the first five years of in-service life, CEV recognizes the equivalent value of the ITC in other income on the Unaudited Condensed Consolidated Statements of Operations over the respective five-year ITC recapture periods, starting with the second year of the lease. CEV received proceeds of approximately $26.0M and $13.2M during the three months ended March 31, 2026 and 2025, and approximately $49.3M and $25.7M during the six months ended March 31, 2026 and 2025, respectively, in connection with the sale leaseback of commercial solar assets. As an alternative, CEV may evaluate other structures to monetize the value of ITCs, such as the direct transfer of ITCs to a third party in exchange for cash.

CEV operated a residential solar portfolio, which provided qualifying homeowners with the opportunity to have a solar system installed at their home in exchange for monthly lease payments and with no installation or maintenance expenses. In November 2024, CEV completed the sale of its residential solar portfolio, and related assets and liabilities to a third party for a purchase price of $132.5M. See Note 16. Dispositions for more details.

For solar installations placed in-service in New Jersey prior to April 30, 2020, each MWh of electricity produced creates an SREC that represents the renewable energy attribute of the solar-electricity generated that can be sold to third parties, predominantly load-serving entities that are required to comply with the solar requirements under New Jersey's renewable portfolio standard.

Following the close of the SREC market in New Jersey, the BPU established the TREC as the successor program to the SREC program. TRECs provide a fixed compensation base multiplied by an assigned project factor in order to determine their value. The project factor is determined by the type and location of the project, as defined. All TRECs generated are required to be purchased monthly by a TREC program administrator as appointed by the BPU.

In July 2021, the BPU established a new successor solar incentive program. This ADI Program provides administratively set incentives for net metered projects of 5 MW or less. RECs generated through the production of electricity under this program are known as SREC IIs.

In December 2022, the BPU established the CSI program, which provides incentives to larger solar facilities. It is open to qualifying grid supply solar facilities, non-residential net metered solar installations with a capacity greater than 5 MW, and eligible grid supply solar facilities installed in combination with energy storage. Pricing is determined based on a competitive bid solicitation process.

REC activity for the six months ended, consisted of the following:

(1) TREC and SREC II inventory balances are due primarily to the timing of generation and when RECs are delivered to the state administrator.

CEV hedges its expected SREC production through the use of forward sales contracts. The following table reflects the hedged percentage of our projected inventory of SRECs related to CEV's in-service solar assets at March 31, 2026:

(1) Energy years are compliance periods for New Jersey's renewable portfolio standard that run from June 1 to May 31.

There are no direct costs associated with the production of RECs by our solar assets. All related costs are included as a component of O&M on the Unaudited Condensed Consolidated Statements of Operations, including such expenses as facility maintenance and broker fees.

Operating Results

CEV’s financial results are summarized as follows:

Net loss increased approximately $1.3M during the three months ended March 31, 2026, compared with the three months ended March 31, 2025, due primarily to the following factors:

• $2.2M increase in interest expense, net of capitalized interest due to higher outstanding long-term debt; and
• $1.6M increase in depreciation expense as a result of additional capital expenditures for commercial solar projects; partially offset by
• $2.0M increase in operating revenues due to higher REC sales.

Net income decreased approximately $39.8M during the six months ended March 31, 2026, compared with the six months ended March 31, 2025, due primarily to the following factors:

• $55.5M decrease due to the gain on the sale of the residential solar portfolio in the prior period; and
• $4.2M increase in interest expense, net of capitalized interest due to higher outstanding long-term debt; partially offset by
• $12.2M decrease in income tax expense related to lower operating income; and
• $7.3M increase in operating revenues due to higher REC sales.

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Energy Services

Overview

ES markets and sells natural gas to wholesale and retail customers and manages natural gas transportation and storage assets throughout major market areas across North America. ES maintains a strategic portfolio of natural gas transportation and storage contracts that it utilizes in conjunction with its market expertise to provide service and value to its customers. Availability of these transportation and storage contracts allows ES to generate market opportunities by capturing price differentials over specific time horizons and between geographic market locations.

ES also provides management of transportation and storage assets for natural gas producers and regulated utilities. These management transactions typically involve the release of producer/utility-owned storage and/or transportation capacity in combination with an obligation to purchase and/or deliver physical natural gas. In addition to the contractual purchase and/or sale of physical natural gas, ES generates or pays fee-based margin in exchange for its active management and may provide the producer and/or utility with additional margin based on actual results.

In conjunction with the active management of these contracts, ES generates Financial Margin by identifying market opportunities and simultaneously entering into natural gas purchase/sale, storage or transportation contracts and financial derivative contracts. In cases where storage is utilized to fulfill these contracts, these forecast sales and/or purchases are economically hedged through the use of financial derivative contracts. The financial derivative contracts consist primarily of exchange-traded futures, options and swap contracts, and are frequently used to lock in anticipated transactional cash flows and to help manage volatility in natural gas market prices. Generally, when its transportation and storage contracts are exposed to periods of increased market volatility, ES is able to implement strategies that allow it to capture margin by improving the respective time or geographic spreads on a forward basis.

ES accounts for its physical commodity contracts and its financial derivative instruments at fair value on the Unaudited Condensed Consolidated Balance Sheets. Changes in the fair value of physical commodity contracts and financial derivative instruments are included in earnings as a component of operating revenues or natural gas purchases on the Unaudited Condensed Consolidated Statements of Operations. Volatility in reported net income at ES can occur over periods of time due to changes in the fair value of derivatives, as well as timing differences related to certain transactions. Unrealized gains and losses can fluctuate as a result of changes in the price of natural gas and SRECs from the original transaction price. Volatility in earnings can also occur as a result of timing differences between the settlement of financial derivatives and the sale of the underlying physical commodity. For example, when a financial instrument settles and the physical natural gas is injected into inventory, the realized gains and losses associated with the financial instrument are recognized in earnings. However, the gains and losses associated with the physical natural gas are not recognized in earnings until the natural gas inventory is withdrawn from storage and sold, at which time ES realizes the entire margin on the transaction.

ES has a series of AMAs with an investment grade public utility to release pipeline capacity associated with certain natural gas transportation contracts. The AMAs include a series of temporary and permanent releases, and revenue under these agreements is recognized as the performance obligations are satisfied. For temporary releases of pipeline capacity, revenue is recognized on a straight-line basis over the agreed-upon term. For permanent releases of pipeline capacity, which represent a transfer of contractual rights for such capacity, revenue is recognized upon the transfer of the underlying contractual rights. ES recognized approximately $4.9M of operating revenue related to the AMAs on the Unaudited Condensed Consolidated Statements of Operations during both the three months ended March 31, 2026 and 2025, and $9.9M during both the six months ended March 31, 2026 and 2025. Amounts received in excess of revenue recognized totaling approximately $61.3M and $36.8M are included in deferred revenue on the Unaudited Condensed Consolidated Balance Sheets as of March 31, 2026 and September 30, 2025, respectively.

Operating Results

ES’s financial results are summarized as follows:

(1) Costs associated with pipeline and storage capacity are expensed over the term of the related contracts, which generally varies from less than one year to 10 years.

(2) Includes related party transactions of approximately $0.3M during both the three months ended March 31, 2026 and 2025, and $0.6M during both the six months ended March 31, 2026 and 2025, a portion of which is eliminated in consolidation.

ES's portfolio of financial derivative instruments is composed of:

During the six months ended March 31, 2026 and 2025, the net short position resulted in unrealized gains (losses) of approximately $3.0M and $(8.2)M, respectively.

Operating revenues decreased approximately $2.2M during the three months ended March 31, 2026, compared with the three months ended March 31, 2025, due primarily to a 19% decrease in volumes of natural gas sold, partially offset by a 23% increase in natural gas prices. Natural gas purchases decreased approximately $11.9M during the three months ended March 31, 2026, compared with the three months ended March 31, 2025, due primarily to a 19% decrease in volumes of natural gas purchased, partially offset by a 15% increase in natural gas purchase prices.

Operating revenues increased approximately $30.6M during the six months ended March 31, 2026, compared with the six months ended March 31, 2025, due primarily to a 22% increase in natural gas prices, partially offset by a 10% decrease in volumes of natural gas sold. Natural gas purchases increased approximately $6.0M during the six months ended March 31, 2026, compared with the six months ended March 31, 2025, respectively, due primarily to a 16% increase in natural gas purchase prices, partially offset by a 10% decrease in volumes of natural gas purchased.

Future results at ES are contingent upon natural gas market price volatility driven by variations in both the supply and demand balances caused by weather and other factors. As a result, variations in weather patterns in the key market areas served may affect earnings during the fiscal year. Changes in market fundamentals, such as an increase in supply and decrease in demand due to warmer temperatures, and reduced volatility can negatively impact ES's earnings. See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Natural Gas Distribution for TETCO M-3 Daily Prices, which illustrates the daily natural gas prices in the Northeast market region.

Net income increased approximately $8.4M and $18.8M during the three and six months ended March 31, 2026, compared with the three and six months ended March 31, 2025, respectively, due primarily to the colder weather, which led to increased natural gas price volatility and favorable pricing spreads that resulted in additional earnings.

Non-GAAP Financial Measures

Management uses Financial Margin and NFE, non-GAAP financial measures, when evaluating the operating results of ES. Financial Margin and NFE are based on removing timing differences associated with certain derivative instruments. GAAP also requires us, during the interim periods, to estimate our annual effective tax rate and use this rate to calculate the year-to-date tax provision. We also determine an annual estimated effective tax rate for NFE purposes and calculate a quarterly tax adjustment based on the differences between our forecasted net income and our forecasted NFE for the fiscal year. This adjustment is applied to ES, as the adjustment primarily relates to timing differences associated with certain derivative instruments that impacts the estimate of the annual effective tax rate for NFE. No adjustment is needed during the fourth quarter, since the actual effective tax rate is calculated at year end.

Management views these measures as representative of the overall expected economic result and uses these measures to compare ES's results against established benchmarks and earnings targets as these measures eliminate the impact of volatility on GAAP earnings as a result of timing differences associated with the settlement of derivative instruments. To the extent that there are unanticipated impacts from changes in the market value related to the effectiveness of economic hedges, ES's actual non-GAAP results can differ from the results anticipated at the outset of the transaction. Non-GAAP financial measures are not in accordance with, or an alternative to, GAAP and should be considered in addition to, and not as a substitute for, the comparable GAAP measure.

When ES reconciles the most directly comparable GAAP measure to both Financial Margin and NFE, the current period unrealized gains and losses on derivatives are excluded as a reconciling item. Financial Margin and NFE also exclude the effects of economic hedging of the value of our natural gas in storage and, therefore, only include realized gains and losses related to natural gas withdrawn from storage, effectively matching the full earnings effects of the derivatives with realized margins on the related physical natural gas flows. To the extent we utilize forwards, futures or other derivatives to hedge natural gas transactions and forecasted SREC production, the resulting unrealized gains and losses are also eliminated from NFE. Financial Margin differs from gross margin as defined on a GAAP basis as it excludes certain operations and maintenance expense and depreciation and amortization as well as the effects of derivatives as discussed above.

Financial Margin

A reconciliation of gross margin, the closest GAAP financial measure, to ES's Financial Margin is as follows:

(1) Excludes SG&A of approximately $0.2M and $0.3M during the three months ended March 31, 2026 and 2025, respectively, and $0.5M and $0.6M during the six months ended March 31, 2026 and 2025, respectively.

(2) Effects of hedging natural gas inventory transactions where the economic impact is realized in a future period.

Financial Margin increased approximately $46.8M and $59.3M during the three and six months ended March 31, 2026, respectively, compared with the three and six months ended March 31, 2025, respectively, due primarily to the colder weather, as previously discussed.

Net Financial Earnings

A reconciliation of ES's net income, the most directly comparable GAAP financial measure, to NFE is as follows:

NFE increased approximately $37.0M and $45.4M during the three and six months ended March 31, 2026, compared with the three and six months ended March 31, 2025, respectively, due primarily to higher Financial Margin, as previously discussed.

Future results are subject to the ability of ES to expand its wholesale sales and service activities and are contingent upon many other factors, including an adequate number of appropriate and credit qualified counterparties in an active and liquid natural marketplace; volatility in the natural gas market due to weather or other fundamental market factors impacting supply and/or demand; transportation, storage and/or other market arbitrage opportunities, sufficient liquidity in the overall energy trading market; and continued access to liquidity in the capital markets.

Storage and Transportation

Overview

S&T invests in natural gas assets, such as natural gas transportation and storage facilities. We believe that acquiring, owning and developing these storage and transportation assets, which operate under a tariff structure that has either cost- or market-based rates, can provide us organic growth opportunities. S&T is subject to various risks, including the construction, development and operation of our transportation and storage assets, as well as our ability to obtain necessary governmental, environmental and regulatory approvals, property rights and financing at reasonable costs for the construction, operation and maintenance of our assets.

S&T is comprised of Leaf River, a 32.2M Dths salt dome natural gas storage facility that operates under market-based rates, and Adelphia, a FERC-regulated interstate pipeline in southeastern Pennsylvania that operates under cost-of-service rates but can enter into negotiated rates with counterparties.

In September 2024, Adelphia filed a Section 4 rate case with the FERC seeking approval to revise its transportation cost-of-service rates to reflect investments made in its pipeline system. In June 2025, Adelphia reached a settlement in principle with customers participating in the rate case. In August 2025, Adelphia and the rate case participants filed an offer of settlement with the FERC, which was approved on November 4, 2025, the results of which are considered immaterial to the Company’s Unaudited Condensed Consolidated Financial Statements.

S&T has a 50% ownership interest in Steckman Ridge, a storage facility located in western Pennsylvania that operates under market-based rates. As of March 31, 2026, our investment in Steckman Ridge was $102.8M.

Operating Results

The financial results of S&T are summarized as follows:

(1) Includes related party transactions that were immaterial during the three and six months ended March 31, 2026 and 2025.

Net income increased approximately $5.4M and $7.1M during the three and six months ended March 31, 2026, compared with the three and six months ended March 31, 2025, respectively, due primarily to higher operating income at Adelphia due to the impact of its recent rate case settlement, as previously discussed along with lower depreciation expense.

Non-GAAP Financial Measures

Management uses Adjusted EBITDA, a non-GAAP financial measure, when evaluating the operating results of S&T. Adjusted EBITDA is net income before interest, income taxes, depreciation and amortization, corporate overhead and other income, net. Non-GAAP financial measures are not in accordance with, or an alternative to, GAAP and should be considered in addition to, and not as a substitute for, the comparable GAAP measure.

Adjusted EBITDA

A reconciliation of S&T's net income, the most directly comparable GAAP financial measure, to Adjusted EBITDA is as follows:

(1) Consists primarily of interest income.

Adjusted EBITDA increased approximately $5.9M and $7.3M during the three and six months ended March 31, 2026 compared with the three and six months ended March 31, 2025, respectively, due primarily to higher net income, as previously discussed.

Home Services and Other

The financial results of HSO consist primarily of the operating results of NJRHS. NJRHS provides service, sales and installation of appliances to service contract customers and has been focused on growing its installation business and expanding its service contract customer base. HSO also includes organizational expenses incurred at NJR. Net (loss) was $(0.2)M and $(0.7)M for the three months ended March 31, 2026 and 2025, respectively. Net income (loss) was $0.3M and $(0.1)M for the six months ended March 31, 2026 and 2025, respectively.

Liquidity and Capital Resources

Our objective is to maintain an efficient consolidated capital structure that reflects the different characteristics of each reportable segment and other business operations and provides adequate financial flexibility for accessing capital markets as required. Our consolidated capital structure was as follows:

Common Stock Equity

We satisfy our external common equity requirements, if any, through issuances of our common stock, including the proceeds from stock issuances under our DRP. The DRP allows us, at our option, to use treasury shares or newly issued shares to raise capital. NJR raised approximately $3.8M of equity through the DRP during both the three months ended March 31, 2026 and 2025, and $7.6M during both the six months ended March 31, 2026 and 2025.

During the six months ended March 31, 2025, we raised approximately $19.9M of equity by issuing approximately 418,000 shares through the waiver discount feature of the DRP. We did not issue shares through the waiver discount feature of the DRP during the three and six months ended March 31, 2026 or during the three months ended March 31, 2025.

In 1996, the Board of Directors authorized us to implement a share repurchase program, which was expanded seven times since the inception of the program, authorizing a total of 19.5M shares of common stock for repurchase. Since inception, we repurchased a total of approximately 17.8M of those shares and may repurchase an additional 1.7M shares under the approved program. There were no shares repurchased during the three and six months ended March 31, 2026 and 2025.

Debt

NJR and its unregulated subsidiaries generally rely on cash flows generated from operating activities and the utilization of committed credit facilities to provide liquidity to meet working capital and short-term debt financing requirements. NJNG also relies on the issuance of commercial paper for short-term funding. NJR and NJNG, as borrowers, periodically access the capital markets to fund long-life assets through the issuance of long-term debt securities.

We believe that our existing borrowing availability, equity proceeds and cash flows from operations will be sufficient to satisfy our working capital, capital expenditures and dividend requirements for at least the next 12 months. NJR, NJNG, CEV, S&T and ES currently anticipate that each of their financing requirements for the next 12 months will be met primarily through the issuance of short- and long-term debt, and meter or solar asset sale leasebacks.

We believe that as of March 31, 2026, NJR and NJNG were, and currently are, in compliance with all existing debt covenants, both financial and non-financial.

Short-Term Debt

NJR uses short-term borrowings primarily to finance ES's short-term liquidity needs, share repurchases and, on an initial basis, CEV's investments. ES's use of high-volume storage facilities and anticipated pipeline park-and-loan arrangements, combined with related economic hedging activities in the volatile wholesale natural gas market, create significant short-term cash requirements.

As of March 31, 2026, NJR had a revolving credit facility totaling $575M, with approximately $399.7M available under the facility.

NJNG satisfies its debt needs by issuing short-term and long-term debt based on its financial profile. The seasonal nature of NJNG's operations creates large short-term cash requirements, primarily to finance natural gas purchases and customer accounts receivable. NJNG obtains working capital for these requirements and for the temporary financing of construction and MGP remediation expenditures and energy tax payments, based on its financial profile, through the issuance of commercial paper supported by the NJNG Credit Facility or through short-term bank loans under the NJNG Credit Facility.

NJNG’s commercial paper is sold through several commercial banks under an issuing and paying agency agreement and is supported by the $250M NJNG Credit Facility. As of March 31, 2026, there was $249.3M available under the NJNG Credit Facility, including amounts allocated to the backstop under the commercial paper program, as applicable, and the issuance of letters of credit. Short-term borrowings were as follows:

Due to the seasonal nature of natural gas prices and demand, and because inventory levels are built up during its natural gas injection season (April through October), NJR and NJNG's short-term borrowings tend to peak in the November through January time frame.

NJR

During fiscal 2024, NJR entered into a second amendment to NJR’s Second Amended and Restated Credit Agreement, governing a $575M NJR Credit Facility maturing on August 7, 2029, with an option to extend the maturity date up to two times for an additional period of one year each. The NJR Credit Facility includes an accordion feature, which allows NJR, in the absence of a default or event of default, to increase from time to time, with the existing or new lenders, the revolving credit commitments under the NJR Credit Facility in increments of at least $50M with the total revolving credit commitments not exceeding $750M. The NJR Credit Facility also permits the borrowing of revolving loans and swingline loans, as well as a $75M sublimit for the issuance of letters of credit. Certain of NJR’s unregulated subsidiaries have guaranteed all of NJR’s obligations under the NJR Credit Facility. The credit facility is used primarily to finance its share repurchases, to satisfy ES’s short-term liquidity needs and to finance, on an initial basis, unregulated investments.

As of March 31, 2026, NJR had 29 letters of credit outstanding totaling approximately $25.3M, which reduced the amount available under the NJR Credit Facility by the same amount. NJR does not anticipate that these letters of credit will be drawn upon by the counterparties.

Based on its average borrowings during the six months ended March 31, 2026, NJR’s average interest rate was 5.10%, resulting in interest expense of approximately $5.7M. Based on average borrowings of $222.3M during the period, a 100 basis point change in the underlying average interest rate would have caused a change in interest expense of approximately $1.1M during the six months ended March 31, 2026.

Neither NJNG nor its assets are obligated or pledged to support the NJR Credit Facility.

NJNG

During fiscal 2024, NJNG entered into a second amendment to NJNG’s Second Amended and Restated Credit Agreement governing a $250M NJNG Credit Facility, maturing on August 7, 2029, with an option to extend the maturity date up to two times for an additional period of one year each. The NJNG Credit Facility includes an accordion feature, which would allow NJNG, in the absence of a default or event of default, to increase from time to time, with the existing or new lenders, the revolving credit commitments under the NJNG Credit Facility in increments of at least $50M with total revolving credit commitments not exceeding $350M. The NJNG Credit Facility also permits the borrowing of revolving loans and swingline loans, as well as a $30M sublimit for the issuance of letters of credit.

As of March 31, 2026, NJNG had two letters of credit outstanding for $0.7M, which reduced the amount available under the NJNG Credit Facility by the same amount. NJNG does not anticipate that these letters of credit will be drawn upon by the counterparties.

Based on its average borrowings during the six months ended March 31, 2026, NJNG’s average interest rate was 3.98%, resulting in interest expense of $1.5M. Based on average borrowings of $76.2M during the period, a 100 basis point change in the underlying average interest rate would have caused a change in interest expense of approximately $0.4M during the six months ended March 31, 2026.

Short-Term Debt Covenants

Borrowings under the NJR Credit Facility and NJNG Credit Facility are conditioned upon compliance with a maximum leverage ratio (consolidated total indebtedness to consolidated total capitalization as defined in the applicable agreements) of not more than .70 to 1.00 for NJR and .65 to 1.00 for NJNG. These revolving credit facilities contain customary representations and warranties for transactions of this type. They also contain customary events of default and certain covenants that will limit NJR's or NJNG's ability, beyond agreed upon thresholds, to, among other things:

• incur additional debt;
• incur liens and encumbrances;
• make dispositions of assets;
• enter into transactions with affiliates; and
• merge, consolidate, transfer, sell or lease all or substantially all of the borrower's or guarantors' assets.

These covenants are subject to a number of exceptions and qualifications set forth in the applicable agreements.

Default Provisions

The agreements governing our long-term and short-term debt obligations include provisions that, if not complied with, could require early payment or similar actions. Default events include, but are not limited to, the following:

• defaults for non-payment;
• defaults for breach of representations and warranties;
• defaults for insolvency;
• defaults for non-performance of covenants;
• cross-defaults to other debt obligations of the borrower; and
• guarantor defaults.

The occurrence of an event of default under these agreements could result in all loans and other obligations of the borrower becoming immediately due and payable and the termination of the credit facilities.

Long-Term Debt

NJR

As of March 31, 2026, NJR's long-term debt consisted of approximately $1.1B in fixed-rate unsecured debt issuances, with maturities ranging from 2026 to 2034.

Neither NJNG nor its assets are obligated or pledged to support NJR's long-term debt.

NJNG

As of March 31, 2026, NJNG's long-term debt consisted of approximately $1.8B in fixed-rate debt issuances secured by the Mortgage Indenture, with maturities ranging from 2028 to 2061, and approximately $43.6M in sale leasebacks of natural gas meters with various maturities ranging from 2026 to 2031.

On April 1, 2026, NJNG remarketed a $15.0M FMB, with an interest rate of 3.75% and a maturity date of April 1, 2059.

Senior notes are secured by an equal principal amount of NJNG’s FMBs issued under NJNG’s Mortgage Indenture.

NJR is not obligated directly nor contingently with respect to NJNG’s fixed-rate debt issuances.

Long-Term Debt Covenants and Default Provisions

The NJR and NJNG long-term debt instruments contain customary representations and warranties for transactions of their type. They also contain customary events of default and certain covenants that will limit NJR or NJNG's ability beyond agreed upon thresholds to, among other things:

• incur additional debt (including a covenant that limits the amount of consolidated total debt of the borrower at the end of a fiscal quarter to 70% for NJR and 65% for NJNG of the consolidated total capitalization of the borrower, as those terms are defined in the applicable agreements, and a covenant limiting priority debt to 20% of the borrower's consolidated total capitalization, as those terms are defined in the applicable agreements);
• incur liens and encumbrances;
• make loans and investments;
• make dispositions of assets;
• make dividends or restricted payments;
• enter into transactions with affiliates; and
• merge, consolidate, transfer, sell or lease substantially all of the borrower's assets.

The aforementioned covenants are subject to a number of exceptions and qualifications set forth in the applicable note purchase agreements.

In addition, the FMBs issued by NJNG under the Mortgage Indenture are subject to certain default provisions. Events of Default, as defined in the Mortgage Indenture, consist mainly of:

• failure for 30 days to pay interest when due;
• failure to pay principal or premium when due and payable;
• failure to make sinking fund payments when due;
• failure to comply with any other covenants of the Mortgage Indenture after 30 days' written notice from the Trustee;
• failure to pay or provide for judgments in excess of $30M in aggregate amount within 60 days of the entry thereof; or
• certain events that are or could be the basis of a bankruptcy, reorganization, insolvency or receivership proceeding.

Upon the occurrence and continuance of such an Event of Default, the Mortgage Indenture, subject to any provisions of law applicable thereto, provides that the Trustee may take possession and conduct the business of NJNG, may sell the trust estate, or proceed to foreclose the lien of the Mortgage Indenture. The interest rate on defaulted principal and interest, to the extent permitted by law, on the FMBs issued under the Mortgage Indenture is the rate stated in the applicable supplement or, if no such rate is stated, 6% per annum.

Sale Leaseback

NJNG received approximately $15.0M and $11.7M during the six months ended March 31, 2026 and 2025, respectively, in connection with the sale leaseback of its natural gas meters. NJNG utilizes sale leaseback arrangements as a financing mechanism to fund certain of its capital expenditures related to natural gas meters, whereby the physical asset is sold concurrent with an agreement to lease the asset back. These agreements include options to repurchase the assets sold or renew the lease at the end of the term. As NJNG retains control of the natural gas meters, these arrangements do not qualify as a sale. NJNG uses the financing method to account for the transactions. NJNG continues to evaluate this sale leaseback program based on current market conditions. Natural gas meters are excluded from the lien on NJNG property under the Mortgage Indenture.

CEV enters into transactions to sell the commercial solar assets concurrent with agreements to lease the assets back over a period of five to seven years. The Company has concluded that these arrangements do not qualify as a sale for accounting purposes, as the Company retains control of the underlying assets, and are therefore treated as financing obligations, which are typically secured by the renewable energy facility asset and its future cash flows from RECs and energy sales. ITCs and other tax benefits associated with these solar projects are transferred to the buyer, if applicable; however, the lease payments are structured so that CEV is compensated for the transfer of the related tax incentives. CEV continues to operate the solar assets, including related expenses, and retain the revenue generated from RECs and energy sales, and has the option to renew the lease or repurchase the assets sold at the end of the lease term. During the six months ended March 31, 2026 and 2025, CEV received proceeds of approximately $49.3M and $25.7M, respectively, in connection with the sale leaseback of commercial solar projects. The proceeds received were recognized as a financing obligation on the Unaudited Condensed Consolidated Balance Sheets.

Contractual Obligations and Capital Expenditures

As of March 31, 2026, the Company had 31 outstanding letters of credit totaling approximately $26.0M, as previously mentioned and there were NJR guarantees covering approximately $151.5M of natural gas purchases and ES demand fee commitments, not yet reflected in accounts payable on the Unaudited Condensed Consolidated Balance Sheets.

Estimated capital expenditures are reviewed on a regular basis and may vary based on the ongoing effects of regulatory constraints, environmental regulations, unforeseen events, and the ability to access capital.

NJNG's total capital expenditures spent or accrued during the six months ended March 31, 2026, were approximately $218.9M. During fiscal 2026, total capital expenditures are projected to be between $430M and $480M. NJNG expects to fund its obligations with a combination of cash flows from operations, cash on hand, issuance of commercial paper, available capacity under its revolving credit facility and the issuance of long-term debt. As of March 31, 2026, NJNG's future MGP expenditures are estimated to be approximately $166.1M. For a more detailed description of MGP expenditures see Note 13. Commitments and Contingent Liabilities in the accompanying Unaudited Condensed Consolidated Financial Statements.

During the six months ended March 31, 2026, total capital expenditures spent or accrued related to the purchase and installation of solar equipment were approximately $109.2M. CEV's expenditures include clean energy projects that support our goal to promote renewable energy. Accordingly, CEV enters into agreements to install solar equipment for commercial projects. We estimate solar-related capital expenditures during fiscal 2026 to be between $210M and $290M.

Capital expenditures related to clean energy projects are subject to change due to a variety of factors that may affect our ability to commence operations at these projects on a timely basis or at all, including sourcing projects that meet our investment criteria, logistics associated with the start-up of commercial solar projects, such as timing of construction schedules, the permitting and regulatory process, any delays related to electric grid interconnection, economic trends or unforeseen events and the ability to access capital or allocation of capital to other investments or business opportunities.

During the six months ended March 31, 2026, S&T had capital expenditures spent or accrued for Adelphia totaling approximately $2.4M and capital expenditures spent or accrued for Leaf River totaling approximately $22.1M. During fiscal 2026, we expect expenditures related to Adelphia to be between $5M and $10M and expenditures related to Leaf River to be between $40M and $50M.

ES does not currently anticipate any significant capital expenditures during fiscal 2026 and 2027.

Cash Flows

Operating Activities

Cash flows from operating activities during the six months ended March 31, 2026, totaled approximately $589.3M, compared with approximately $414.1M during the six months ended March 31, 2025. Operating cash flows are primarily affected by variations in working capital, which can be impacted by several factors, including:

• seasonality of our business;
• fluctuations in wholesale natural gas prices and other energy prices, including changes in derivative asset and liability values;
• timing of storage injections and withdrawals;
• deferral and recovery of natural gas costs;
• changes in contractual assets utilized to optimize margins related to natural gas transactions;
• broker margin requirements;
• impact of unusual weather patterns on our wholesale business;
• timing of the collections of receivables and payments of current liabilities;
• volumes of natural gas purchased and sold; and
• timing of SREC deliveries.

Cash flows from operating activities increased approximately $175.2M during the six months ended March 31, 2026, compared with the six months ended March 31, 2025, due primarily to higher base rates and ES Financial Margin, along with the changes in the mix of working capital components.

Investing Activities

Cash flows used in investing activities increased approximately $223.5M during the six months ended March 31, 2026, compared with the six months ended March 31, 2025, due primarily to the receipt of proceeds resulting from CEV's sale of the residential solar portfolio in the prior period, along with increased solar asset expenditures.

Financing Activities

Financing cash flows generally are seasonal in nature and are impacted by the volatility in pricing in the natural gas and other energy markets. NJNG's inventory levels are built up during its natural gas injection season (April through October) and reduced during withdrawal season (November through March) in response to the supply requirements of its customers. Changes in financing cash flows can also be impacted by natural gas management and marketing activities at ES and clean energy investments at CEV.

Cash flows used in financing activities decreased approximately $89.9M during the six months ended March 31, 2026, compared with the six months ended March 31, 2025, due primarily to lower payments of short-term and long-term debt and higher proceeds from solar sale leasebacks, partially offset by lower proceeds from the waiver discount feature of the DRP and long-term debt.

Credit Ratings

The table below summarizes NJNG's credit ratings as of March 31, 2026, issued by two rating entities, Moody's and Fitch:

The Moody's ratings and outlook were reaffirmed in June 2025. The Fitch ratings and outlook were reaffirmed in March 2026. NJNG's Moody's and Fitch ratings are investment-grade ratings. NJR is not rated by Moody’s or Fitch.

Although NJNG is not party to any lending agreements that would accelerate the maturity date of any obligation caused by a failure to maintain any specific credit rating, if such ratings are downgraded below investment grade, borrowing costs could increase, as would the costs of maintaining certain contractual relationships and future financing and our access to capital markets would be reduced. Even if ratings are downgraded without falling below investment grade, NJR and NJNG could face increased borrowing costs under their credit facilities. A rating set forth above is not a recommendation to buy, sell or hold NJR's or NJNG's securities and may be subject to revision or withdrawal at any time. Each rating set forth above should be evaluated independently of any other rating.

The timing and mix of any external financings will target a common equity ratio that is consistent with maintaining NJNG's current short-term and long-term credit ratings.

The following table reflects the changes in the fair market value of physical commodity contracts:

Our market price risk is predominately linked with changes in the price of natural gas at the Henry Hub, the delivery point for the NYMEX natural gas futures contracts. Based on price sensitivity analysis, an illustrative 10% movement in the natural gas futures contract price, for example, increases (decreases) the reported derivative fair value of all open, unadjusted Henry Hub natural gas futures and fixed price swap positions by approximately $1.0M. This analysis does not include potential changes to reported credit adjustments embedded in the $2.7M reported fair value.

Wholesale Credit Risk

The following is a summary of gross and net credit exposures, grouped by investment and non-investment grade counterparties, as of March 31, 2026. Gross credit exposure for ES is defined as the unrealized fair value of derivative and energy trading contracts plus any outstanding wholesale receivable for the value of natural gas or power delivered and/or financial derivative commodity contract that has settled for which payment has not yet been received. Gross credit exposure for S&T is defined as demand and estimated usage fees for contracted services and/or market value of loan balances for which payment has not yet been received. Net credit exposure is defined as gross credit exposure reduced by collateral received from counterparties and/or payables, where netting agreements exist. The amounts presented below exclude accounts receivable for NJNG retail natural gas sales and services.

ES's, CEV's and S&T's counterparty credit exposure as of March 31, 2026, is as follows:

NJNG's counterparty credit exposure as of March 31, 2026, is as follows:

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Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of the end of the period covered by this report. Based on this evaluation, our principal executive officer and principal financial officer concluded that, as of end of the period covered by this report, our disclosure controls and procedures are effective, to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act, is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

There has been no change in internal control over financial reporting (as such term is defined in Exchange Act Rule 13a-15(f)) that occurred during the quarter ended March 31, 2026, that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

While we attempt to identify, manage and mitigate risks and uncertainties associated with our business to the extent practical, under the circumstances, some level of risk and uncertainty will always be present. Part I, Item 1A. Risk Factors of our 2025 Annual Report on Form 10-K includes a detailed discussion of our risk factors. Those risks and uncertainties have the potential to materially affect our financial condition and results of operations. There have been no material changes in our risk factors from those previously disclosed in Part I, Item 1A, of our 2025 Annual Report on Form 10-K.