PEG Public Service Enterprise Group 10-Q 2026-09-30 section summaries

PSEG — Section Summary

Business profile and results

PSEG is primarily a regulated New Jersey electric and gas utility, with merchant nuclear generation and other businesses. PSE&G operates regulated distribution and transmission networks and energy-efficiency and solar programs. PSEG Power sells nuclear-generated energy and capacity; PSEG LI operates LIPA’s Long Island system under contract.

Nine-month earnings fell principally because PSEG Power & Other recorded after-tax non-trading commodity mark-to-market losses of $395M, compared with gains of $16M in 9M 2025, on positions with future delivery dates. The comparable Q3 mark-to-market results were a $180M loss versus a $15M gain. These volatile results contrast with growth in PSE&G’s regulated business.

PSE&G’s 9M revenue growth came from electric distribution ($4.206B, up from $3.929B), gas distribution ($1.856B, up from $1.621B), and transmission ($1.378B, up from $1.331B). PSEG Power & Other third-party electricity and related-product sales were $1.535B, up from $1.135B, even as total segment revenue declined. PSE&G’s controllable O&M was $1.054B versus $1.035B, and gross additions to long-lived assets were $1.947B versus $1.893B. Consolidated gross additions were $2.302B versus $2.143B. Consolidated assets were $60.317B at September 30, 2026, compared with $57.576B at December 31, 2025.

Regulation, rates and operating exposures

PSE&G continues to seek or receive rate recovery for infrastructure, programs and supply costs; several approvals are provisional or pending. Recent approvals include annual gas-rate increases of $23M and $4M under GSMP II extensions, and annual electric and gas increases of approximately $10M and $4M under the IAP. Pending filings seek annual increases of $316M electric and $52M gas for GPRC, and $49M electric and $75M gas for TAC. The BPU also provisionally approved maintaining the BGSS rate at approximately $0.36 per therm from October 2026. PSE&G’s October 2026 FERC update is expected to increase annual transmission revenue by approximately $60M beginning January 2027, subject to true-up.

Following federal production tax credits received by nuclear owners, the BPU approved a $166M customer refund, including interest; PSE&G had refunded approximately $62M by September 30, 2026. Separately, PSEG Power refunded approximately $207M related to 2024 ZEC value. Final PTC calculations could still change amounts materially. The Salem and Hope Creek ZEC program ended in 2025.

PSEG Power’s commodity-contract guarantees had a face value of $1.180B. Derivative losses and collateral needs can shift with commodity prices: non-designated energy derivatives generated pre-tax losses of $267M in Q3 and $805M in 9M 2026, primarily in operating revenues. Consolidated net mark-to-market derivative liabilities were $291M, up from $69M at year-end 2025. After offsets and collateral, a downgrade below investment grade would have triggered an additional $298M collateral obligation, versus $85M at year-end. PSEG Power’s wholesale net credit exposure was 98% to investment-grade counterparties, though one unaffiliated counterparty represented more than 10% of exposure. PSE&G had $275M of unsecured mark-to-market exposure to BGS suppliers, mitigated by collateral and tariff recovery.

Financing, investments and tax

During 9M 2026, PSEG issued $500M of 4.80% senior notes due 2031; PSE&G issued $2.0B of secured notes with coupons of 4.20%–6.05% and maturities from 2031 to 2056; and PSEG Power issued $400M of 5.55% notes due 2031. PSE&G retired $875M of notes at maturity. At September 30, committed credit facilities totaled $3.825B, with $3.083B available; PSEG had $575M of commercial paper outstanding at a 4.13% weighted-average rate. Long-term debt carrying amount was $24.559B and fair value $21.839B, versus $22.545B and $21.364B at December 31, 2025. Management said available liquidity and access to external financing were sufficient for projected stressed needs over 12 months.

Nuclear decommissioning trust investments had fair value of $2.877B at September 30, down from $2.914B at year-end; reported cost was $2.577B versus $2.426B. Available-for-sale debt securities had $1.445B cost, $126M gross unrealized losses and $1.319B fair value. Management attributed losses to market and interest-rate changes, reported no credit losses, and did not expect or intend to sell before recovery of amortized cost. PSEG’s recurring fair-value net assets were $2.8B, versus $3.2B a year earlier; $320M of NDT commingled equity funds used the NAV practical expedient.

PSEG’s effective tax rate was 0.8% in Q3 and 10.7% in 9M, compared with 13.6% and 12.9%; pre-tax hedge losses contributed to the decline. PSEG recorded approximately $52M of cumulative CAMT liabilities and $207M of uncertain tax positions; PSE&G recorded $2M and $185M, respectively. CAMT rule uncertainty could affect future results.

Material contingencies

PSEG accrued $66M for the Lower Passaic River matter, including $53M at PSE&G supported by an expected regulatory asset and $13M at PSEG Power. EPA cleanup estimates are $2.3B for the Lower 8.3 miles and $550M for the Upper 9 miles; the remedy, responsible-party shares and recovery remain uncertain. PSE&G identified 38 former manufactured-gas-plant sites and recorded a $193M liability, matching regulatory asset, within an estimated $193M–$208M undiscounted remediation range. PSEG Power’s former-site obligations and other river matters remain unquantified; coal-ash regulatory changes could materially affect results and cash flows. Other litigation includes a $68M remaining Sewaren 7 claim and an amended nuclear-worker antitrust class action. The BPU has yet to determine which recommendations from its completed PSE&G management audit must be implemented.

Results

PSEG’s results reflected growth in regulated utility activity but weaker merchant-generation and investment results. For the first nine months of 2026, net income and diluted EPS declined, primarily because non-trading commodity mark-to-market results shifted from gains to losses and nuclear decommissioning trust (NDT) investment gains were lower. Continued PSE&G transmission and distribution (T&D) investment and higher PSEG Power capacity revenues partly offset those pressures.

Quarterly revenue decreased 6.4%, while nine-month revenue increased 1.8%. After-tax non-trading mark-to-market losses were $180M in Q3 and $395M for 9M 2026.

Segment performance

PSE&G’s nine-month revenue rose 7.2%; most distribution delivery revenue is recovered through regulated rates, and decoupling limits the effect of sales volumes on most delivery revenue. Nine-month delivery revenue increased $142M, including $79M from higher delivery volumes, $41M from GPRC revenue and $29M from transmission revenue, primarily reflecting higher rate-base investment. Pass-through clause revenue increased $141M in 9M, with no margin, while commodity revenue rose $362M, mainly on higher BGS and BGSS prices; corresponding energy costs offset these pass-through movements. Other operating revenue fell $127M in 9M, mainly because ZEC collections ended in 2025. In Q3, PSEG Power & Other revenue declined $217M.

PSEG Power’s nine-month generation revenue decreased $466M. A $571M unfavorable mark-to-market change—principally from forward-price movements—and the $84M reduction following the conclusion of ZEC sales in May 2025 were partly offset by $134M higher capacity revenue and $53M from higher realized prices and sales volumes. Gas Supply revenue increased $189M, including $156M from BGSS contract sales ($134M from higher prices and $22M from higher volumes) and $37M from third-party sales.

Across PSEG Power & Other, energy costs rose $190M, including $171M of higher gas costs, while O&M declined $41M, reflecting the absence of a Hope Creek refueling outage and an indirect-tax adjustment, partly offset by Salem 1 outage costs. Net gains on trust investments decreased $66M: equity securities had $134M of net unrealized losses in 2026 versus $108M of net unrealized gains in 2025, partly offset by $174M more net realized gains on NDT investments. Interest expense increased $24M; income-tax expense decreased $137M, primarily due to lower pretax income.

Investment, operations and outlook

PSEG’s strategy prioritizes regulated investment, infrastructure modernization, reliability and resilience, energy efficiency, and preserving the value of carbon-free nuclear generation. Regulated rate base reached approximately $36B at December 31, 2025, up from approximately $34B a year earlier. For 2026–2030, the company expects $22.5B–$25.5B of regulated capital investment within a $24B–$28B total capital program, supporting a projected 6.0%–7.5% regulated rate-base CAGR. The lower investment case assumes extensions of GSMP and CEF-EE; the higher case includes potential spending for demand growth, infrastructure needs and New Jersey clean-energy goals.

PSE&G’s approved CEF-EE II authorizes approximately $2.9B for projects committed from January 2025 through June 2027, including approximately $1.9B for the program budget net of administrative expenses and approximately $1.0B for customer on-bill repayment. Approved in November 2025, GSMP III authorizes $1.05B to replace 525 miles of gas mains, plus $360M to replace another 75 miles. PSE&G began work in 2026 and expects it to continue through 2028, with trailing costs into 2029; it anticipates filing a distribution rate case by year-end 2026.

Nuclear units generated approximately 23.9 TWh at a 94.3% capacity factor during 9M 2026. Salem 1, Salem 2 and Hope Creek useful lives were revised in 2025 based on an expected 20-year license extension, and Hope Creek’s refueling cycle was extended from 18 to 24 months. However, thermal-shield degradation found during Salem 1’s October 2026 refueling outage is expected to extend the outage; the impact depends on further inspection and repair timing. PSEG’s nuclear fleet supplies over 80% of New Jersey’s carbon-free energy. The federal nuclear production tax credit applies from 2024 through 2032 at an expected rate of up to $15/MWh, subject to phaseout and annual inflation adjustments. PSEG did not seek the new ZEC eligibility period beginning June 2025. PTC amounts and related guidance remain uncertain; as of September 30, 2026, the company expected nuclear output’s realized value to exceed the level at which it would receive PTCs.

Cash flow, capital and liquidity

Consolidated operating cash flow for 9M 2026 decreased $40M year over year, pressured by $388M of net cash collateral postings versus a $137M net inflow in 2025, and payment of the PSEG Power ZEC refund. PSE&G operating cash flow improved on higher earnings, lower net regulatory deferrals, lower receivables and unbilled revenue, and increased obligations to return cash collateral.

For 9M 2026, PSE&G capital expenditures were $1.947B, primarily for T&D reliability; it also incurred $135M for CEF-EE II on-bill repayment in investing cash flows, $118M of net cost of removal in operating cash flows, and $473M of energy-efficiency program expenditures in operating cash flows. PSEG Power & Other capital expenditures were $203M, excluding $152M for nuclear fuel.

In March 2026, PSEG, PSEG Power and PSE&G extended their existing $3.75B revolving credit facilities to March 2031; PSEG Power’s $75M letter-of-credit facility was extended to March 2028. At September 30, 2026, total committed facilities were $3.825B and available liquidity was $3.083B. PSEG Power also had $425M of uncommitted letter-of-credit facilities, with $350M outstanding. A $500M 364-day variable-rate PSEG term loan borrowed in February 2026 was prepaid in June. Potential collateral following a two-level downgrade that caused PSEG Power to lose investment-grade ratings was estimated at approximately $682M, versus $703M at December 31, 2025. Management expects liquidity, including access to external financing, to cover stressed needs over a 12-month planning horizon. The Board approved a Q3 2026 dividend of $0.67 per share, equivalent to an annual rate of $2.68 per share.

Regulatory and other risks

New Jersey legislation requires transmission owners to belong to a FERC-approved RTO beginning January 1, 2027. If PSE&G loses its 50-basis-point PJM ROE adder, annual net income and cash inflows could each decline approximately $40M. PJM resource-adequacy concerns, large-load connection rules, and affordability pressures create uncertainty; state affordability measures, including extended deferred-payment arrangements and summer disconnection protections for certain customers, have increased PSE&G bad-debt expense. Federal orders concerning retiring generators, import tariffs and IRA tax guidance also create potential reliability, supply-chain and financial uncertainty.

PSEG also faces cybersecurity and physical-security risks, energy-price volatility, interest-rate and financing risks, and environmental remediation exposure, including Newark Bay Complex Superfund sites. Its gas modernization program aims to improve safety and reduce methane leaks; system-wide methane emissions declined by over 34% from 2018 through 2025.

Market risk and counterparty exposure

PEG manages energy-price risk and seeks to optimize the value of its owned generation capacity through physical supply contracts and commodity derivatives, including forwards, futures, swaps and options. Commodity prices and availability are exposed to weather, supply-demand shifts, environmental policies, regulation and market rules.

The company’s mark-to-market (MTM) value-at-risk (VaR) measure covers economic-hedge derivatives, but excludes market risk from accrual-accounted activities, primarily generating facilities and some load-serving activities. For the three months ended September 30, 2026, MTM VaR at a 95% confidence level ranged from $49 million to $116 million, a wider range than in FY2025. VaR models use a one-day holding period and 95% and 99.5% confidence levels, assume no new positions during the holding period, and apply to portfolios that PEG actively manages.

PEG is also exposed to counterparty credit risk: non-performance or non-payment by a major counterparty could materially adversely affect its financial condition, results of operations or net cash flows. Management’s credit process assesses, monitors and mitigates exposure, with executive oversight from a Risk Management Committee.

Disclosure controls and internal control. PSEG’s and PSE&G’s CEOs and CFOs concluded that disclosure controls and procedures were effective at a reasonable-assurance level as of the end of Q3 2026. Neither registrant reported changes during the quarter that materially affected, or were reasonably likely to materially affect, internal control over financial reporting. This section reported no financial results or business developments.

The company reported no new or updated risk factors in this section. It refers readers to the risk factors in its Form 10-K, which could materially adversely affect its business, prospects, financial position, results of operations, or cash flows, and could cause actual results to differ materially from reported expectations.

Trading Plans

No directors or executive officers adopted, terminated, or modified Rule 10b5-1 or non-Rule 10b5-1 trading plans during Q3 2026.

PJM Capacity and Large-Load Proposals

PJM proposed a Reliability Backstop Procurement (RBP) to address a projected 6.8 GW resource shortfall for the 2028/2029 delivery year. The proposal would seek 15-year commitments from new generation resources, with costs passed to load-serving entities and end-use customers, including data centers. In September 2026, FERC found key components just and reasonable but rejected others and directed PJM to revise its filing. PJM submitted a revision in late October and is seeking FERC approval by January 29, 2027; if approved, PJM plans to hold an RBP auction on March 1, 2027. The proposal’s outcome and implementation remain subject to FERC action.

Separately, PJM sought FERC approval in August 2026 for rules that would allow curtailment of new large-load customers, including data centers, during peak demand if they lacked committed new generation to serve their load. In October, FERC rejected the principal components, citing significant deficiencies and finding key provisions outside its Federal Power Act jurisdiction. The proposed curtailment mechanism therefore remains unresolved as PJM addresses the region’s capacity shortfall and growth in large-load demand.

New Jersey Energy-Efficiency Programs

BPU Staff proposed a one-year extension of the second triennium of energy-efficiency programs while the BPU develops the third-triennium framework. The BPU’s July 2026 final extension framework permits utilities to submit alternatives, including proposals concerning return on equity (ROE) and savings targets. PSE&G filed its proposed extension and alternatives in September 2026; the company said the outcome cannot currently be predicted.