PEG Public Service Enterprise Group 10-Q 2026-06-30 section summaries

Business profile and segment performance

PSEG is primarily a regulated utility. PSE&G operates New Jersey electric transmission and electric and gas distribution, with transmission rates regulated by FERC and distribution rates by the BPU. PSEG Power & Other includes merchant nuclear generation, gas supply and portfolio optimization, as well as PSEG LI and other businesses.

• Consolidated operating revenue: Q2 2026 was $2.554B, down from $2.805B in Q2 2025; H1 2026 was $6.402B, up from $6.027B in H1 2025.
• PSE&G revenue: Q2 was $2.137B from $2.031B; H1 was $5.222B from $4.695B.
• PSEG Power & Other revenue: Q2 was approximately $534M from $920M; H1 was $1.950B from $2.012B. Intersegment eliminations were $(117)M from $(146)M in Q2 and $(770)M from $(680)M in H1.
• Consolidated energy costs: H1 2026 were $2.373B from $2.012B; PSE&G costs were $2.134B from $1.854B, and PSEG Power & Other costs were $1.009B from approximately $838M, before eliminations.
• Consolidated net income: H1 was $1.075B from $1.174B. Segment-level profit figures were not legible in the supplied material.
• Gross additions to long-lived assets: H1 were $1.459B from $1.415B; PSE&G additions were $1.252B from $1.279B.

PSE&G’s H1 electric distribution revenue rose to $2.424B from $2.118B, while gas distribution revenue was $1.700B from $1.460B. Consolidated revenue from customer contracts was $6.885B from $5.947B; revenues outside customer contracts were negative $483M in H1 2026. These include regulatory alternative-revenue mechanisms, derivatives and leases.

PSEG Power & Other earnings were affected by non-trading commodity mark-to-market losses of $185M after tax in Q2 and $215M after tax in H1, compared with gains of $136M and $1M in the respective 2025 periods. Separately, derivatives not designated as hedges produced pre-tax net losses of $185M in Q2 and $538M in H1, versus an $11M loss in H1 2025; H1 losses primarily reflected energy-related contracts.

Regulation and commercial developments

The BPU approved PSE&G’s gas supply rate of approximately $0.36 per therm in May 2026, effective since December 2025; a request to maintain it from October 2026 remained pending. Other rate proceedings include approved recovery of approximately $65M annually of deficient electric revenues and $89M of deficient gas revenues, with additional gas recovery sought. The BPU approved a $23M annual gas base-rate increase for GSMP II Extension; further program recovery requests include $4M annually for GSMP, $8M for CEF-EV and $10M electric / $4M gas for IAP. A July 2026 GPRC filing sought annual increases of $316M electric and $52M gas; approval and recovery timing remain uncertain.

Following a BPU order concerning 2024 ZECs and federal production tax credits, PSEG Power refunded New Jersey electric distribution companies approximately $207M in May 2026. A separate BPU order provided for $166M, including interest, in customer refunds over approximately 12 months beginning June 1, 2026. ZEC sales ended in 2025 and PSE&G’s ZEC tariff was eliminated effective February 2026; the final payment under the program was settled in August 2025. Final tax-credit calculations could require further revenue adjustments.

PSEG LI’s LIPA operating-services agreement extension runs through 2030. Its fixed fee is approximately $43M annually in 2026 and 2027, rising to approximately $47M in 2028. Servco’s reimbursed operating and maintenance costs, matched by revenue, were $166M in Q2 from $155M and $317M in H1 from $307M.

Financial position, funding and market exposure

Consolidated assets were $58.813B at June 30, 2026, compared with $57.576B at year-end 2025. Total long-term debt carrying amount was $23.591B, versus $22.545B; estimated fair value was $22.134B, versus $21.364B. PSEG issued $500M of 4.80% senior notes due 2031 in H1. PSE&G issued $500M of 4.20% secured notes due 2031 and $500M of 5.63% secured notes due 2056, and retired $450M of 0.95% secured notes at maturity. PSEG’s $500M variable-rate term loan was prepaid in June.

Committed credit facilities totaled $3.825B, of which $3.210B was available; facilities were extended through March 2031. PSEG had $450M of commercial paper outstanding at a weighted-average 3.94% rate. Management expects liquidity and financing access to cover stressed needs for the next 12 months.

At June 30, PSEG Power’s outstanding commodity guarantees had $1.154B face value; actual exposure depends on net positions and collateral, and can change with commodity prices. Net collateral under derivative arrangements was reported at $414M, versus $222M at year-end. A downgrade below investment grade would have triggered an additional $250M net collateral obligation, up from $85M at year-end. Wholesale exposure was entirely with investment-grade counterparties, though two counterparties each exceeded 10% of exposure, including one unaffiliated party.

Principal risks and shareholder items

The largest quantified environmental accrual is $66M for the Lower Passaic River matter—$53M at PSE&G, with an offsetting 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; PSEG says additional costs beyond its accrual could be material but cannot estimate a range. For 38 former manufactured-gas sites, PSE&G estimated undiscounted remediation costs of $172M–$189M, recorded the $172M low end ($20M current; $152M noncurrent) and a matching regulatory asset. Other site, natural-resource-damage and coal-ash exposures remain uncertain.

The nuclear decommissioning trust had $2.994B fair value versus $2.581B amortized cost at June 30, 2026, compared with $2.914B versus $2.426B at year-end 2025. PSEG may contribute up to $100M to its pension plan in 2026. PSE&G’s allowance for credit losses was approximately 12% of receivables, including unbilled revenue, at both June 30 and year-end; PSEG Power reported no allowance on energy-market receivables.

Basic and diluted EPS were $0.67 in Q2, unchanged year over year, and $2.15 in H1, versus $2.35. Dividends were $0.67 per share in Q2 from $0.63 and $1.34 in H1 from $1.26; the board approved a $0.67-per-share Q3 dividend.

PSEG (PEG) — Six months ended June 30, 2026

Results and business drivers

PSEG’s two reportable segments are regulated utility PSE&G and PSEG Power & Other, which includes merchant nuclear generation and other businesses. Consolidated operating revenue was $2.554 billion in Q2 2026, down $251 million (9%) from $2.805 billion, and $6.402 billion in H1 2026, up $375 million (6.2%) from $6.027 billion. PSEG reported H1 net income of $1.075 billion, versus $1.174 billion in H1 2025; diluted EPS was $2.15 versus $2.35. Q2 diluted EPS was $0.67 versus $1.17. Management attributed the earnings decline mainly to non-trading mark-to-market losses in 2026 versus gains in 2025, partly offset by growth in utility clause-program revenue and higher Power capacity revenue and gas sales. Segment operating-profit figures were not legible in the supplied summaries.

• PSE&G revenue: $2.137 billion in Q2, versus $2.031 billion (+$106 million, 5.2%); $5.222 billion in H1, versus $4.695 billion (+$527 million, 11.2%). Q2 delivery revenue rose $40 million (volumes +$17 million, GPRC +$13 million, transmission +$10 million); clause revenue rose $50 million; commodity revenue rose $64 million; and other operating revenue fell $48 million. H1 delivery revenue rose $130 million (volumes +$67 million, GPRC +$42 million, transmission +$28 million, partly offset by $7 million of additional customer credits); clause revenue rose $114 million; commodity revenue rose $371 million, including electric BGS +$267 million and gas BGSS +$104 million, mainly from higher prices; other operating revenue fell $88 million, primarily because ZEC collections ended May 31, 2025. Commodity and clause revenue changes are generally passed through and have no margin.
• PSEG Power & Other revenue: declined $386 million (42%) in Q2 and $62 million (3%) in H1. Generation revenue fell $387 million in Q2, including a $450 million adverse mark-to-market swing ($370 million from forward-price changes and $80 million from positions reclassified as realized upon settlement), plus $25 million from ended ZEC sales. Offsets included $51 million of higher capacity revenue and $37 million from higher realized prices and volumes. H1 generation revenue fell $241 million, including a $300 million adverse mark-to-market swing and an $81 million reduction from ended ZEC sales; higher capacity revenue (+$115 million) and realized prices (+$24 million) partly offset the decline. H1 gas-supply revenue rose $180 million, while gas costs rose $166 million.

PSE&G energy costs increased $16 million in Q2 and $280 million in H1, offset by commodity and other operating revenue changes. PSE&G O&M increased $41 million and $102 million, respectively, largely with clause and renewable expenditures; depreciation and amortization rose $11 million and $26 million, and interest expense rose $13 million and $31 million, respectively. For PSEG Power & Other, H1 O&M decreased $32 million, while interest expense increased $19 million. Trust-investment gains increased $24 million in H1; 2026 included $170 million of net realized gains and $78 million of net unrealized losses on equity securities, versus $69 million of net unrealized gains in 2025.

Investment, operations, and strategy

PSE&G’s regulated rate base was approximately $36 billion at December 31, 2025, up from approximately $34 billion a year earlier. PSEG forecasts $22.5–$25.5 billion of regulated investment within a $24–$28 billion total capital program for 2026–2030, and expects regulated rate base to compound 6.0%–7.5% annually through year-end 2030. The range depends in part on extensions of gas-modernization and energy-efficiency programs and possible investments for demand growth and clean-energy goals.

H1 PSE&G capital expenditures were $1.252 billion, primarily for transmission and distribution reliability; this excludes $86 million for CEF-EE II on-bill repayment, $74 million of net cost of removal, and $263 million of energy-efficiency expenditures. PSEG Power & Other capital expenditures were $134 million, excluding $73 million for nuclear fuel. Prior-period capital expenditure comparisons were not provided.

The BPU authorized approximately $2.9 billion for CEF-EE II projects committed from January 2025 through June 2027, including a $1.9 billion program investment budget and approximately $1 billion for customer on-bill repayment. It also approved $1.05 billion under GSMP III to replace 525 miles of gas mains, with periodic rate adjustments as assets enter service, plus $360 million for another 75 miles, for which recovery will be sought in a future base-rate case. PSE&G expects to file a base-rate case by year-end 2026.

PSEG Power generated approximately 15.8 TWh in H1 at a 93.7% capacity factor. The nuclear production tax credit (PTC) is available from 2024 through 2032 at an expected rate of up to $15/MWh, subject to phaseouts and other adjustments. PSEG did not seek the 2025-starting ZEC eligibility period following the PTC’s introduction. PTC value remains uncertain due to market prices, generation, and pending guidance; as of June 30, 2026, the company expected realized nuclear output value to exceed the level at which PTCs would be received. Salem and Hope Creek life estimates were extended based on an expected 20-year license extension; Hope Creek’s refueling cycle was extended from 18 to 24 months, and uprates are planned at Salem Units 1 and 2.

Cash flow, funding, and risks

Consolidated operating cash flow increased $294 million year over year, mainly from higher tax refunds and a net change at PSE&G, partly offset by $179 million of higher net cash-collateral postings at PSEG Power. PSE&G operating cash flow rose to $1.166 billion from $954 million. Management expects operating cash flow, cash on hand, and financing to fund capital expenditures and dividends.

At June 30, 2026, committed facilities totaled $3.825 billion, of which $3.210 billion was available. In March 2026, PSEG, PSEG Power, and PSE&G extended their $3.75 billion revolving facilities through March 2031. PSEG borrowed $500 million under a 364-day variable-rate term loan in February and prepaid it in June; PSEG Power increased its 364-day term loan from $400 million to $500 million, extending maturity to December 2026. A two-level downgrade of PSEG Power below investment grade could increase collateral needs; estimated potential collateral was $705 million, versus $703 million at year-end 2025. PSE&G has $425 million of 2.25% secured notes due September 2026 and $425 million of 3.00% secured notes due May 2027. Ratings outlooks were stable. The board approved a $0.67 per-share Q3 2026 dividend, equivalent to an indicated annual rate of $2.68.

A New Jersey law enacted in June 2026 requires transmission owners to belong to an FERC-approved RTO beginning January 1, 2027. This could remove PSE&G’s 50-basis-point ROE adder, reducing annual net income and cash inflows by approximately $40 million. PJM capacity prices have risen sharply amid demand growth and limited new generation; proposed reliability procurement, large-load interconnection rules, and transmission-cost allocation remain uncertain. Other risks include affordability measures and potentially higher bad debt, financing costs, supply-chain effects from tariffs, environmental liabilities, and evolving tax and clean-energy policies. PSEG’s strategy remains centered on regulated-grid investment, reliability and resilience, cost control, preserving nuclear generation’s value, and pursuing generation, storage, and transmission opportunities; regulatory approvals and expected benefits are not assured.

Market Risk

PEG uses forwards, futures, swaps, options, and supply contracts to manage commodity-price exposure and optimize the value of its owned generation capacity. Commodity prices may be affected by weather, supply and demand, environmental policies, regulation, and changes to market rules. An executive-officer Risk Management Committee oversees compliance with risk-management policies.

For Q2 2026, commodity mark-to-market (MTM) value-at-risk (VaR), calculated using variance/covariance models and a one-day holding period, ranged from $53 million to $92 million at the 95% confidence level. The filing says this range was narrower than in FY 2025. A 95% confidence level means losses could exceed VaR one day in 20; at 99.5%, they could exceed VaR one day in 200. The filing provides no populated period-end, average, high, or low VaR values at either confidence level beyond the stated 95% range.

VaR covers MTM economic-hedge derivatives, but excludes market risks from accrual-accounted activities, primarily generating facilities and some load-serving activities. The models assume no new positions during the holding period, whereas PEG actively manages its portfolio.

Counterparty nonperformance or nonpayment—including a major counterparty default—could materially adversely affect PEG’s financial condition, results, or net cash flows. PEG describes procedures to assess, monitor, and mitigate credit exposure and refers readers to Note 10 for further credit-risk discussion.

Disclosure Controls and Internal Control Over Financial Reporting

As of the end of Q2 2026, management of both PSEG and PSE&G concluded that their disclosure controls and procedures were effective at a reasonable-assurance level. Neither company reported any Q2 2026 change in internal control over financial reporting that materially affected, or was reasonably likely to materially affect, those controls. This section reports no financial results, business developments, or additional risks.

Risk Factors

The company directs investors to the risk factors in Part I, Item 1A of its Form 10-K. It cautions that risks and uncertainties could materially adversely affect its business, prospects, financial position, results of operations, or cash flows, and could cause actual results to differ materially from statements elsewhere in the 10-Q. This section provides no specific risk factors or financial metrics and does not identify changes in risk since the 10-K.

Subsequent developments

Transmission returns and cost allocation

New Jersey legislation enacted in June 2026 requires transmission owners to join a FERC-approved regional transmission organization (RTO) beginning January 1, 2027. PSE&G currently receives a 50-basis-point return-on-equity adder for voluntary PJM membership. Mandatory membership could eliminate the adder, reducing annual net income and cash inflows by approximately $40 million; the outcome and impact remain under assessment.

Transmission cost allocation is also contested. In March 2026, FERC rejected a proposed PJM settlement that would have shifted significant transmission-project costs to PSE&G transmission customers. FERC directed PJM to recalculate allocations and resettle billings dating to 2015. Related FERC and D.C. Circuit proceedings remain ongoing, with an uncertain outcome.

Large loads and capacity adequacy

In June 2026, FERC directed PJM and transmission customers to show cause regarding the absence of tariff provisions addressing large-load transmission applications, protections against cost shifting, transparency, and co-located or behind-the-meter generation.

Separately, PJM proposed a “Reliability Backstop Procurement” to address a 6.8 GW resource shortfall for the 2028/2029 delivery year. The proposal would seek 15-year commitments from new generation, with costs passed to load-serving entities and end-use customers, including data centers.

Energy efficiency and electricity procurement

Rather than issuing the anticipated framework for the third energy-efficiency triennium, BPU Staff proposed a one-year extension of the second triennium; BPU issued the final extension framework in July 2026. The framework changes budget calculations to use gross instead of net energy savings, adjusts achievable-performance ROE, and replaces the existing method for recovering foregone revenue. Utilities may propose alternatives, with extension petitions due September 30, 2026. The third-cycle framework is expected later in 2026.

The February 2025 Basic Generation Service (BGS) auction produced a significant supply-cost increase, reflected in customer rates beginning June 1, 2025, largely because of higher PJM capacity prices. The February 2026 auction resulted in a slight cost decrease effective June 1, 2026. New Jersey electric distribution companies filed a joint proposal in July 2026 for the February 2027 auction, covering energy years 2028–2030; resulting rates are expected to take effect June 1, 2027.

New Jersey legislation

The July 2026 Advance Grid Technologies Act expands BPU oversight. Supplemental transmission projects of at least 100 kV require a certificate before construction, while projects using qualifying advanced grid technologies receive an expedited approval path.

The Data Center Fair Share Act creates a separate rate class and tailored requirements intended to make qualifying large data centers bear the full costs of their electricity infrastructure and grid upgrades. It also provides for demand reduction during grid stress and a retail program under which new large loads can offset capacity obligations by funding demand reductions elsewhere. BPU proceedings are expected, but implementation remains uncertain.

The Power NJ Act establishes a competitive procurement framework for at least 1,100 MW of new nuclear generation, including advanced and small modular reactors, and a Reliable Capacity Certificate mechanism intended to support financing for qualifying projects.

Insider trading plans

During Q2 2026, no directors or officers adopted, terminated, or modified Rule 10b5-1 or non-Rule 10b5-1 trading arrangements.

Overall, these developments leave uncertainty around PSE&G’s transmission returns and cost allocations as New Jersey and PJM respond to growing large-load demand, capacity adequacy, customer cost allocation, and the need for prospective clean-generation supply.