New Jersey Resources Corp: Form 10-Q for the period ended Jun 30, 2025

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, 2024. Our critical accounting policies have not changed from those reported in the 2024 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 2024 Annual Report on Form 10-K.

Reporting Segments

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

In addition to our four reporting segments above, we have nonutility operations that either provide corporate support services or do not meet the criteria to be treated as a separate reporting 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 (loss) income by reporting segment and other business operations, which are discussed in more detail within the operating results sections of each reporting segment and other business operations, are as follows:

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

Consolidated net loss increased approximately $3.5M during the three months ended June 30, 2025, compared with the three months ended June 30, 2024, due primarily to the following factors:

• $20.1M increase in net loss at ES due primarily to lower operating revenues related to the AMAs along with higher natural gas purchase prices; partially offset by
• $16.2M increase in earnings at NJNG due primarily to an increase in base rates, effective November 21, 2024.

Consolidated net income increased approximately $121.9M during the nine months ended June 30, 2025, compared with the nine months ended June 30, 2024, due primarily to the following factors:

• $69.1M increase in earnings at NJNG due primarily to an increase in base rates;
• $39.1M increase at CEV due primarily to the gain on the sale of the residential solar asset portfolio; and
• $10.5M increase at ES due primarily to higher operating revenues related to increased natural gas prices, partially offset by decreased AMA revenues along with higher natural gas purchase prices.

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

Assets by reporting segment and operations are as follows:

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

Consolidated assets increased approximately $292.5M as of June 30, 2025, compared with September 30, 2024, due primarily to a $209.3M increase in utility plant expenditures, net and an $80.8M increase in customer receivables at NJNG.

Non-GAAP Financial Measures

Our management uses 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 reporting segment and other business operations, which are discussed in more detail within the operating results sections of each reporting segment and other business operations, is summarized as follows:

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

Consolidated NFE increased approximately $15.1M during the three months ended June 30, 2025, compared with the three months ended June 30, 2024, due primarily to a $16.2M increase in earnings at NJNG due to the increase in base rates, as previously discussed.

Consolidated NFE increased approximately $111.3M during the nine months ended June 30, 2025, compared with the nine months ended June 30, 2024, due primarily to the following factors:

• $69.1M increase at NJNG, as previously discussed; and
• $39.1M increase at CEV, as previously discussed.

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 and customer conservation efforts. 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

In January 2024, NJNG filed a base rate case with the BPU requesting a natural gas revenue increase of approximately $222.6M including a recovery of infrastructure investments, a change in the Company’s overall rate of return on rate base to 7.57% and a change in the return on common equity to 10.42%. On November 21, 2024, the BPU issued an order adopting a stipulation of settlement approving a $157.0M increase to base rates, effective November 21, 2024. 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 nine months ended June 30, 2025, and estimates of expected investments for fiscal 2025 and 2026:

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.

NJNG continues to implement BPU-approved infrastructure projects that are designed to enhance the reliability and integrity of NJNG’s natural gas distribution system.

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 will be recovered through annual filings to adjust base rates. On July 25, 2025, NJNG submitted a filing with the BPU to extend the IIP through June 30, 2026.

In September 2024, the BPU approved NJNG's annual IIP filing, which requested a rate increase for capital expenditures of approximately $41.2M through June 30, 2024, which resulted in a revenue increase of approximately $4.7M, effective October 1, 2024.

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:

During the nine months ended June 30, 2025, NJNG added 5,659 new customers. NJNG expects new customer additions, and those customers who added additional natural gas services to their premises to contribute approximately $6.7M 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. On October 30, 2024, the BPU approved a settlement of the 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, which totals approximately $385.6M, with expected recoveries through September 30, 2025, of approximately $12.3M.

On December 18, 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 May 30, 2025, NJNG's annual SAVEGREEN cost recovery filing was submitted to the BPU, requesting an increase to annual recoveries of approximately $17.3M, effective October 1, 2025.

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

Program recoveries from customers during the nine months ended June 30, 2025 and 2024, were approximately $13.0M and $22.6M, respectively. The recovery includes a weighted average cost of capital that ranges from 6.9% to 7.08%, with a return on equity of 9.6%.

Conservation Incentive Program/BGSS

The CIP facilitates normalizing NJNG’s Utility Gross Margin for variances not only due to weather but also for 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 17.8% and 4.9% warmer-than-normal during the three and nine months ended June 30, 2025, respectively, and 12.6% and 11.0% warmer-than-normal during the three and nine months ended June 30, 2024, respectively.

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 May 21, 2025, the BPU approved on a final basis, NJNG’s 2025 BGSS/CIP filing, which included a decrease of approximately $31.0M to the annual revenues credited to BGSS, an annual increase of approximately $40.3M related to its balancing charge and a decrease of approximately $0.8M to CIP rates, effective October 1, 2024.

On May 30, 2025, the 2026 BGSS/CIP filing was submitted to the BPU requesting an increase of approximately $63.3M to annual revenues related to BGSS, an annual increase of approximately $6.1M related to its balancing charge and a decrease of approximately $25.5M to CIP rates, effective October 1, 2025. 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 $3.9M and $2.9M during the three months ended June 30, 2025 and 2024, respectively, and approximately $14.5M and $16.2M during the nine months ended June 30, 2025 and 2024, 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 $40.02 and $20.98 and the minimum price was $1.05 and $0.89 for the nine months ended June 30, 2025 and 2024, respectively. 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

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 March 2024, the BPU approved NJNG's annual SBC filing of RAC expenditures through June 30, 2023, which included an increase to the RAC annual recoveries of approximately $2.4M and an increase to the NJCEP annual recoveries of approximately $5.5M, effective April 1, 2024.

In June 2024, NJNG submitted its annual USF filing to the BPU requesting an increase to the statewide USF rate. In September 2024, the BPU approved the filing, which resulted in an increase to annual recoveries of approximately $6.8M, effective October 1, 2024.

On April 23, 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.

On June 27, 2025, NJNG submitted its annual USF filing to the BPU requesting a decrease to annual recoveries of approximately $0.5M, effective October 1, 2025.

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 $155.9M as of June 30, 2025, a decrease of approximately $5.8M compared with September 30, 2024. See Note 13. Commitments and Contingent Liabilities for more details.

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 nonutility revenue of approximately $0.2M and $0.3M during the three months ended June 30, 2025 and 2024, respectively, and $0.9M and $1.0M for the nine months ended June 30, 2025 and 2024, respectively, 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 June 30, 2025 and 2024, respectively, and $6.3M and $7.0M during nine months ended June 30, 2025 and 2024, 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 29.7% and natural gas purchases increased 34.5% during the three months ended June 30, 2025, compared with the three months ended June 30, 2024. Operating revenues increased 26.5% and natural gas purchases increased 26.1% during the nine months ended June 30, 2025, compared with the nine months ended June 30, 2024.

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 Energy Efficiency, 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. Management believes 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 $27.1M and $28.8M for the three months ended June 30, 2025 and 2024, respectively, and $85.0M and $87.7M for the nine months ended June 30, 2025 and 2024, 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 customers, as well as 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 $23.7M and $119.2M during the three and nine months ended June 30, 2025, compared with the three and nine months ended June 30, 2024, respectively, due primarily to an increase in base rates, effective November 21, 2024.

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 June 30, 2025, compared with the three months ended June 30, 2024, due primarily to increased margins from storage and off-system sales. BGSS incentive programs decreased during the nine months ended June 30, 2025, compared with the nine months ended June 30, 2024, due primarily to decreased margins from storage due to timing differences.

Net Income

Net income increased approximately $16.2M during the three months ended June 30, 2025, compared with the three months ended June 30, 2024, due primarily to the following factors:

• $25.0M increase in Utility Gross Margin, as previously discussed; partially offset by
• $7.5M increase in depreciation expense as a result of additional utility plant being placed into service.

Net income increased approximately $69.1M during the nine months ended June 30, 2025, compared with the nine months ended June 30, 2024, due primarily to the following factors:

• $118.1M increase in Utility Gross Margin, as previously discussed; partially offset by
• $20.9M increase in depreciation expense, as previously discussed; and
• $30.0M increase in income tax expense related to higher operating income.

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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, such as timing of construction schedules, the permitting and regulatory process, any delays related to electric grid interconnection, economic trends, changes in law, governmental policies, or incentives that support clean energy projects, including 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, 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.

On July 4, 2025, OBBBA was signed into law, which modifies several pre-existing provisions of the Inflation Reduction Act, including the phase-out of certain clean energy tax credits. 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.

On July 7, 2025, a federal executive order was issued directing the Secretary of the Treasury to release guidance that could potentially modify the beginning of construction requirements for solar facilities.

The Company continues to evaluate the provisions of OBBBA, as well as the foregoing federal executive order, on its business. There has been no material impact on CEV’s operations or financial position as a result of these developments to date. The Company will continue to assess these and further developments for potential impacts in future periods.

CEV placed two commercial solar projects in service totaling 19.3 MWs during the three months ended June 30, 2025, with related expenditures of approximately $55.0M. CEV placed five commercial solar projects in service totaling 32.0 MWs during the nine months ended June 30, 2025, with related expenditures of approximately $83.7M. CEV placed one commercial solar project in service totaling 2.3 MWs during the three months ended June 30, 2024, with related expenditures of approximately $10.9M. CEV placed two commercial solar projects in service totaling 5.1 MWs during the nine months ended June 30, 2024, with related expenditures of approximately $18.8M. These projects are subject to sale leaseback arrangements.

CEV has approximately 418 MW of commercial solar capacity in service. Projects that were placed in service through December 31, 2019, qualified for a 30% federal ITC. The credit declined to 26% for property under construction during 2020 through the end of 2022. In August 2022, the federal ITC was restored to 30% through the end of 2032. There are additional opportunities to increase the credit amount for certain facilities that are placed in service after December 31, 2022, based upon the type of project and location.

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 $74.5M during the three months ended June 30, 2025, and approximately $100.3M and $24.4M during the nine months ended June 30, 2025 and 2024, respectively, in connection with the sale leaseback of commercial solar assets. There were no proceeds received during the three months ended June 30, 2024.

CEV operated a residential solar program, as part of The Sunlight Advantage®, which provided qualifying homeowners with the opportunity to have a solar system installed at their home with no installation or maintenance expenses. CEV owned, operated and maintained the system over the life of the lease in exchange for monthly lease payments. On November 25, 2024, CEV completed the sale of its 91 MW residential solar portfolio, and related assets and liabilities included in The Sunlight Advantage® program 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 during the nine 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 June 30, 2025:

(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 remained relatively consistent during the three months ended June 30, 2025, compared with the three months ended June 30, 2024.

Net income increased approximately $39.1M during the nine months ended June 30, 2025, compared with the nine months ended June 30, 2024, due primarily to the following factors:

• $56.1M gain on the sale of the residential solar asset portfolio; partially offset by
• $12.9M decrease in operating revenues due to the timing of SREC sales and the sale of the residential solar assets; and
• $11.5M increase in income tax expense related to higher operating income.

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.

During December 2020, ES entered into a series of AMAs with an investment grade public utility to release pipeline capacity associated with certain natural gas transportation contracts. The utility provides certain asset management services and ES may deliver natural gas to the utility in exchange for aggregate net proceeds of approximately $500M, payable through November 1, 2030. The AMAs include a series of initial and permanent releases, which commenced in November 2021. NJR received a total of approximately $260M in cash from fiscal 2022 through fiscal 2024 and will receive approximately $34M per year from fiscal 2025 through fiscal 2031 under the agreements. ES recognized approximately $4.9M and $9.5M during the three months ended June 30, 2025 and 2024, respectively, and approximately $14.8M and $28.5M during the nine months ended June 30, 2025 and 2024, respectively, of operating revenue related to the AMAs on the Unaudited Condensed Consolidated Statements of Operations. Amounts received in excess of revenue totaling approximately $41.8M and $22.3M as of June 30, 2025 and September 30, 2024, respectively, are included in deferred revenue on the Unaudited Condensed Consolidated Balance Sheets.

Operating Results

ES’s financial results are summarized as follows:

(1) Includes related party transactions of approximately $(4.9)M during the nine months ended June 30, 2024, which are eliminated in consolidation. There were no related party transactions during the three and nine months ended June 30, 2025 and the three months ended June 30, 2024.

(2) 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.

(3) Includes related party transactions of approximately $0.3M during both the three months ended June 30, 2025 and 2024, and $0.9M during both the nine months ended June 30, 2025 and 2024, a portion of which is eliminated in consolidation.

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

During the nine months ended June 30, 2025 and 2024, the net short position resulted in unrealized gains of approximately $3.8M and $1.3M, respectively.

Operating revenues decreased approximately $23.6M during the three months ended June 30, 2025, compared with the three months ended June 30, 2024, due primarily to a 21% decrease in both natural gas prices and volumes along with a decrease in revenue related to the AMAs. Operating revenues increased approximately $64.6M during the nine months ended June 30, 2025, compared with the nine months ended June 30, 2024, due primarily to a 35% increase in natural gas prices, partially offset by a decrease in revenue related to the AMAs and a 11% decrease in volumes. Natural gas purchases increased approximately $6.7M and $60.7M during the three and nine months ended June 30, 2025, compared with the three and nine months ended June 30, 2024, respectively, due primarily to a 42% and 41% increase in natural gas purchase prices, respectively.

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 loss increased approximately $20.1M during the three months ended June 30, 2025, compared with the three months ended June 30, 2024, due primarily to the following factors:

• $23.6M decrease in operating revenues, as previously discussed; and
• $6.7M increase in natural gas purchases, as previously discussed; partially offset by
• $2.9M decrease in O&M due to lower employee related expenses; and
• $6.2M decrease in income tax expense related to lower operating income.

Net income increased approximately $10.5M during the nine months ended June 30, 2025, compared with the nine months ended June 30, 2024, due primarily to the following factors:

• $64.6M increase in operating revenues, as previously discussed; and
• $8.6M decrease in O&M due to lower employee related expenses; partially offset by
• $60.7M increase in natural gas purchases, as previously discussed; and
• $2.8M increase in income tax expense related to higher operating income.

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) Includes unrealized gains related to intercompany transactions between NJNG and ES that have been eliminated in consolidation of approximately $4.9M during the three and nine months ended June 30, 2024, respectively. There were no unrealized gains related to intercompany transactions between NJNG and ES during the three and nine months ended June 30, 2025.

(2) Excludes SG&A of approximately $0.3M and $0.4M during the three months ended June 30, 2025 and 2024, respectively, and $0.9M and $1.3M during the nine months ended June 30, 2025 and 2024, respectively.

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

Financial Margin decreased approximately $6.1M and $14.7M during the three and nine months ended June 30, 2025, compared with the three and nine months ended June 30, 2024, respectively, due primarily to lower AMA related revenue.

Net Financial Earnings

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

(1) Includes taxes related to intercompany transactions between NJNG and ES that have been eliminated in consolidation of approximately $1.2M during the nine months ended June 30, 2024. There were no taxes related to intercompany transactions for the three and nine months ended June 30, 2025, and the three months ended June 30, 2024.

NFE decreased approximately $1.5M and $3.8M during the three and nine months ended June 30, 2025, compared with the three and nine months ended June 30, 2024, respectively due primarily to lower AMA related revenue, partially offset by lower O&M 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 Dekatherms 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.

On September 30, 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. On June 26, 2025, Adelphia reached a settlement in principle with customers participating in the rate case. Adelphia and the rate case participants plan to file an offer of settlement with the FERC during the fourth quarter of fiscal 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 June 30, 2025, our investment in Steckman Ridge was $101.0M.

Operating Results

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

(1) Includes related party transactions of approximately $1.3M during the nine months ended June 30, 2024, which are eliminated in consolidation. There were no related party transactions during the three and nine months ended June 30, 2025, and the three months ended June 30, 2024.

Net income remained relatively consistent during the three months ended June 30, 2025, compared with the three months ended June 30, 2024.

Net income increased approximately $4.1M during the nine months ended June 30, 2025, compared with the nine months ended June 30, 2024, due primarily to the following factors:

• $7.7M increase in operating revenues due to higher hub services at Leaf River; partially offset by
• $3.7M increase in O&M due to higher legal and consulting expenses.

52

Home Services and Other

Overview

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.

Operating Results

The condensed financial results of HSO are summarized as follows:

Net income remained relatively consistent during the three and nine months ended June 30, 2025, compared with the three and nine months ended June 30, 2024.

Liquidity and Capital Resources

Our objective is to maintain an efficient consolidated capital structure that reflects the different characteristics of each reporting 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 $3.6M of equity through the DRP during both the three months ended June 30, 2025 and 2024, and $11.2M and $11.1M during the nine months ended June 30, 2025 and 2024, respectively.

During the three months ended June 30, 2024, we raised approximately $11.4M of equity by issuing approximately 262,000 shares through the waiver discount feature of the DRP. During the nine months ended June 30, 2025 and 2024, we raised approximately $19.9M and $47.3M of equity by issuing approximately 418,000 shares and 1,107,000 shares through the waiver discount feature of the DRP, respectively. There were no shares issued through the waiver discount feature during the three months ended June 30, 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 nine months ended June 30, 2025 and 2024.

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 June 30, 2025, NJR and NJNG were, and currently are, in compliance with all existing debt covenants, both financial and non-financial.

Short-Term Debt

We use our 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 June 30, 2025, NJR had a revolving credit facility totaling $575M, with $353.7M 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 June 30, 2025, there was $142.6M 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 June 30, 2025, NJR had 24 letters of credit outstanding totaling $21.4M, 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 fiscal 2025, NJR’s average interest rate was 5.68%, resulting in interest expense of approximately $8.8M. Based on average borrowings of $203.5M during the period, a 100 basis point change in the underlying average interest rate would have caused a change in interest expense of approximately $1.5M during fiscal 2025.

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 June 30, 2025, 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 fiscal 2025, NJNG’s average interest rate was 4.67%, resulting in interest expense of $2.3M. Based on average borrowings of $63.9M during the period, a 100 basis point change in the underlying average interest rate would have caused a change in interest expense of approximately $0.5M during fiscal 2025.

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 June 30, 2025, NJR's long-term debt consisted of approximately $1.1B in fixed-rate unsecured debt issuances, with maturities ranging from 2026 to 2034.

On November 7, 2024, NJR entered into a Note Purchase Agreement under which NJR issued $100M senior notes at a fixed interest rate of 5.55%, maturing in 2034.

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

NJNG

As of June 30, 2025, NJNG's long-term debt consisted of approximately $1.6B in fixed-rate debt issuances secured by the Mortgage Indenture, with maturities ranging from 2028 to 2061, and approximately $35.4M in sale leasebacks of natural gas meters with various maturities ranging from 2025 to 2031.

On April 15, 2025, NJNG's 10-year 2.82% $50M senior notes matured.

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 $11.7M and $8.8M during the nine months ended June 30, 2025 and 2024, 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 nine months ended June 30, 2025 and 2024, CEV received proceeds of approximately $100.3M and $24.4M, 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 June 30, 2025, the Company had 26 outstanding letters of credit totaling approximately $22.1M, as previously mentioned and there were NJR guarantees covering approximately $133.5M 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 are projected to be between $375M and $420M during fiscal 2025. Total capital expenditures spent or accrued during the nine months ended June 30, 2025, were approximately $310.1M. 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 June 30, 2025, NJNG's future MGP expenditures are estimated to be approximately $155.9M. 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 nine months ended June 30, 2025, S&T had capital expenditures spent or accrued for Adelphia totaling approximately $5.4M and capital expenditures spent or accrued for Leaf River totaling approximately $11.0M. During fiscal 2025, we expect expenditures related to Adelphia to be between $5M and $15M and expenditures related to Leaf River to be between $15M and $20M.

During the nine months ended June 30, 2025, total capital expenditures spent or accrued related to the purchase and installation of solar equipment were approximately $129.9M. 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 2025 to be between $165M and $220M.

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.

ES does not currently anticipate any significant capital expenditures during fiscal 2025 and 2026.

During December 2020, ES entered into a series of AMAs with an investment grade public utility to release pipeline capacity associated with certain natural gas transportation contracts. The utility provides certain asset management services and ES may deliver natural gas to the utility in exchange for aggregate net proceeds of approximately $500M, payable through November 1, 2030. The AMAs include a series of initial and permanent releases, which commenced in November 2021. NJR received a total of approximately $260M in cash from fiscal 2022 through fiscal 2024 and will receive approximately $34M per year from fiscal 2025 through fiscal 2031 under the agreements. ES recognized approximately $14.8M and $28.5M during the nine months ended June 30, 2025 and 2024, respectively, of operating revenue related to the AMAs on the Unaudited Condensed Consolidated Statements of Operations. Amounts received in excess of revenue totaling approximately $41.8M and $22.3M as of June 30, 2025 and September 30, 2024, respectively, are included in deferred revenue on the Unaudited Condensed Consolidated Balance Sheets.

Cash Flows

Operating Activities

Cash flows from operating activities during the nine months ended June 30, 2025, totaled approximately $385.2M, compared with approximately $362.9M during the nine months ended June 30, 2024. 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 $22.3M during the nine months ended June 30, 2025, compared with the nine months ended June 30, 2024, due primarily to higher base rates along with the changes in the mix of working capital components.

Investing Activities

Cash flows used in investing activities decreased approximately $86.7M during the nine months ended June 30, 2025, compared with the nine months ended June 30, 2024, due primarily to proceeds from the sale of the CEV's residential solar asset portfolio, partially offset by increased utility plant and 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) from financing activities increased approximately $130.2M during the nine months ended June 30, 2025, compared with the nine months ended June 30, 2024, due primarily to increased payments of long-term debt of approximately $100.8M, along with lower proceeds from long-term debt and the waiver discount feature of the DRP of approximately $75M and $27.4M, respectively, partially offset by higher proceeds from solar sale leasebacks and net short-term debt of $75.9M and $12.2M, respectively.

Credit Ratings

The table below summarizes NJNG's credit ratings as of June 30, 2025, issued by two rating entities, Moody's and Fitch:

The Moody's ratings and outlook were reaffirmed on June 27, 2025. The Fitch ratings and outlook were reaffirmed on April 4, 2025. 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.

Wholesale Credit Risk

The following is a summary of gross and net credit exposures, grouped by investment and non-investment grade counterparties, as of June 30, 2025. 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 June 30, 2025, is as follows:

NJNG's counterparty credit exposure as of June 30, 2025, is as follows:

Due to the inherent volatility in the market price for natural gas, electricity and SRECs, the market value of contractual positions with individual counterparties could exceed established credit limits or collateral provided by those counterparties. If a counterparty failed to perform the obligations under its contract (for example, failed to make payment for natural gas received), we could sustain a loss. This loss would comprise the loss on natural gas delivered but not paid for and/or the cost of replacing natural gas not delivered or received at a price that exceeds the original contract price. Any such loss could have a material impact on our financial condition, results of operations or cash flows.

Effects of Interest Rate Fluctuations

We are also exposed to changes in interest rates on our debt hedges and variable rate debt. We do not believe an immediate 10% increase or decrease in interest rates would have a material effect on our operating results or cash flows.

Information regarding NJR's interest rate risk can be found in Item 3. Quantitative and Qualitative Disclosures About Market Risks and the Liquidity and Capital Resources - Debt section of Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.

Effects of Inflation

Any change in price levels has an effect on operating results due to the capital-intensive and regulated nature of our utility subsidiary. The Company’s operations are sensitive to increases in the rate of inflation because of its operational and capital spending requirements in both its regulated and non-regulated businesses. We attempt to minimize the effects of inflation through cost control, productivity improvements and regulatory actions, when appropriate. See Item 1A. Risk Factors of our 2024 Annual Report on Form 10-K for additional information related to the impact of recent increases in inflation rates.

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 June 30, 2025, 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 2024 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 2024 Annual Report on Form 10-K.