PEG: Turning PJM's Resource Crisis Into Regulated Growth and Nuclear Upside - PEG Stock Research Report

## Executive Summary / Key Takeaways * A Utility With a Nuclear Option: Public Service Enterprise Group combines a stable New Jersey regulated utility delivering 6-7.5% rate base growth with a carbon-free nuclear fleet that provides both downside protection through federal tax credits and upside optionality from potential long-term power contracts, creating a rare blend of predictability and growth leverage. * Resource Adequacy Crisis as Catalyst: The exploding supply-demand imbalance in PJM—exacerbated by a 9,400 MW pipeline of data center inquiries that grew 47% in a single quarter—is driving massive infrastructure investment opportunities while potentially forcing policy changes that could allow PSEG to build new generation, transforming a regional problem into a company-specific tailwind. * Capital Deployment Machine in Motion: PSE&G's $21-24 billion regulated capital plan through 2029, supported by new rate mechanisms and strong liquidity, is translating directly into earnings power, with Q3 2025 net income up 35.9% and management narrowing guidance to the upper half of its range despite rising cost pressures. * The Nuclear Renaissance's Quiet Winner: While the market focuses on merchant generators, PSEG's 3,758 MW nuclear fleet operates at 93.7% capacity factors with production tax credit protection through 2032, and management is actively exploring long-term contracts that could monetize the increasing scarcity value of 24/7 carbon-free baseload power. * Critical Juncture for Risk/Reward: The investment case hinges on two variables: whether New Jersey policymakers will allow regulated utilities to own new generation (legislation introduced February 2025) and what percentage of the massive data center pipeline converts to actual load, with each 1,000 MW of conversion potentially adding meaningful earnings power while spreading fixed costs across a broader rate base. ## Setting the Scene: The Regulated Utility That Prints Money While Solving a Regional Crisis Public Service Enterprise Group, founded in 1903 and headquartered in Newark, New Jersey, operates a business model that seems almost anachronistic in today's volatile energy markets: a regulated monopoly that delivers essential services with guaranteed returns, paired with a nuclear fleet that produces carbon-free power at marginal costs competitors cannot match. Yet this apparent simplicity masks a strategic positioning at the center of three converging forces reshaping the Eastern power grid. PSEG makes money through two distinct but synergistic segments. PSE&G, the regulated utility serving 2.4 million electric and 1.9 million gas customers in New Jersey, earns predictable returns on a rapidly growing rate base that reached $34 billion at year-end 2024. PSEG Power Other operates the company's merchant nuclear assets and manages the Long Island Power Authority's grid under a contract recently extended through 2030. This structure creates a natural hedge: the regulated business provides stable cash flows that fund massive capital investments, while the nuclear segment offers exposure to rising power prices and potential long-term contracts with data centers seeking clean energy. The industry structure has fundamentally shifted. PJM, the 13-state grid operator serving 65 million people, faces a resource adequacy crisis of unprecedented severity. Growing demand from data centers, electrification, and reshoring has collided with retiring fossil plants and slow new supply response, eroding reserve margins and driving capacity auction prices to multi-year highs. New Jersey, a net power importer that sourced nearly half its electricity from out-of-state during June's heat storm, sits at the epicenter of this imbalance. This transforms PSEG from a passive utility into an essential solution provider—whether through transmission investments, potential new generation, or nuclear power sales. PSEG's competitive positioning within this landscape reveals several moats. As New Jersey's largest investor-owned utility, PSE&G benefits from deep regulatory relationships forged over 118 consecutive years of dividend payments and a demonstrated commitment to operational excellence. The utility's reliability metrics and customer satisfaction rankings—second to none among large Eastern peers—provide political capital during rate cases. More importantly, the nuclear fleet's 93.7% capacity factor and sub-$30/MWh production costs create a structural advantage in PJM's capacity markets, where less efficient gas plants set marginal prices. This cost advantage isn't temporary; it's embedded in decades of operational expertise and fully depreciated assets. ## Technology, Products, and Strategic Differentiation: The Nuclear Edge and Grid Modernization PSEG's technological differentiation begins with its nuclear fleet—three units at Salem and Hope Creek that generated 23.8 terawatt-hours of carbon-free power through the first nine months of 2025. These aren't aging liabilities but optimized assets. The recent completion of work to extend Hope Creek's fuel cycle from 18 to 24 months, achieved during a scheduled refueling outage, will increase annual megawatt-hour production while reducing outage frequency. The planned Salem uprate project, adding 200 megawatts between 2027 and 2029, represents a 5% capacity expansion at a fraction of new-build costs. This increases the fleet's already industry-leading capacity factors, and the Inflation Reduction Act's production tax credit provides $15/MWh of downside protection through 2032, effectively creating a price floor that shields earnings during weak power markets while allowing full participation in price spikes. The regulated utility's technology investments tell a parallel story of efficiency and customer value. PSE&G's $2.9 billion Clean Energy Future-Energy Efficiency II program, approved in October 2024, authorizes six years of investments including $1 billion for on-bill repayment options that improve customer affordability while earning regulated returns. The completed Advanced Metering Infrastructure program, installing 2.2 million smart meters on time and on budget, provides real-time data that enhances outage management and enables demand response programs. This transforms traditional cost recovery into a growth driver: each efficiency dollar invested earns a return while reducing system peak loads, deferring more expensive infrastructure upgrades. Grid modernization extends beyond meters. PSE&G's $3.8 billion planned capital spending for 2025 includes transmission and distribution infrastructure hardened against increasingly frequent extreme weather events. The utility successfully operated through three consecutive days of 100-degree temperatures in late June 2025, setting a summer peak load of 10,229 megawatts, the highest since 2013, without major outages. This operational resilience translates directly into regulatory goodwill, as evidenced by the October 2024 rate case settlement that granted new base rates representing a modest 1% annual increase since 2018 while approving new deferral mechanisms for pension and storm costs. The settlement's structure enhances financial predictability while demonstrating that PSEG can manage costs effectively enough to keep rate increases below inflation, a critical advantage in a state where 36% of voters cite taxes as the top problem. ## Financial Performance & Segment Dynamics: Capital Deployment Translating to Earnings Power PSEG's third quarter 2025 results provide compelling evidence that the capital deployment strategy is converting investments into earnings. PSE&G's operating revenues surged 19% year-over-year to $2.535 billion, while net income jumped 35.9% to $515 million. The driver wasn't weather or one-time adjustments but the full-quarter impact of new distribution rates effective October 2024, which recovered returns on over $3 billion of prior capital investments. This demonstrates the regulatory compact is functioning—ratepayers are paying for reliability improvements while shareholders earn predictable returns, creating a self-reinforcing cycle where higher earnings fund future investments that support further rate base growth.

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The segment dynamics reveal a deliberate mix shift toward regulated earnings. PSE&G's nine-month net income of $1.393 billion represents the vast majority of consolidated earnings, with the utility's return on equity improving as rate base expands. Capital expenditures of $1.893 billion in the first nine months of 2025, on track for the full-year $3.8 billion target, are building rate base that will generate returns for decades. The 6% to 7.5% rate base CAGR through 2029 isn't an aspiration but a mathematical outcome of the $21-24 billion capital plan, with each dollar invested earning either explicit returns in base rates or clause-based recoveries for specific programs. For valuation, this converts abstract capital spending into visible earnings growth—at a 7% rate base CAGR and typical utility returns, PSE&G alone could drive mid-single-digit EPS growth even without any Power segment contribution.

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PSEG Power Other's performance illustrates the nuclear fleet's earnings stability. Despite a scheduled Hope Creek refueling outage that reduced Q3 generation to 7.9 terawatt-hours from 8.1 terawatt-hours year-over-year, the segment's net energy margin {{EXPLANATION: net energy margin,In the context of power generation, net energy margin refers to the revenue generated from selling electricity and capacity, minus the direct costs of fuel and purchased power. It indicates the profitability of the generation assets before other operating expenses.}} rose $0.01 per share due to higher power pricing and market revenues. Nine-month net income increased 27.1% to $403 million, driven by consistent nuclear performance and the production tax credit. The segment's 93.7% capacity factor through September 2025, well above industry averages, translates into more megawatt-hours sold at PJM's locational marginal prices {{EXPLANATION: locational marginal prices,In electricity markets, locational marginal prices (LMPs) represent the cost of supplying the next megawatt-hour of electricity at a specific location on the grid. LMPs reflect generation costs, transmission congestion, and losses, influencing how generators are paid and how demand is priced.}}. This shows the nuclear fleet can maintain profitability even during outage quarters, while the PTC ensures a $15/MWh floor that protects against price collapses. Cash flow dynamics support the capital plan without strain. Operating cash flow for the nine months ended September 30, 2025, increased $811 million compared to 2024, driven by higher earnings and improved working capital management. The company ended September with $3.6 billion of total available liquidity, including $330 million of cash, after issuing $450 million of 4.9% secured notes in August. Variable-rate debt represents just 4% of total debt, insulating the company from interest rate volatility. This confirms management's assertion that the five-year capital plan can be executed without equity issuance or asset sales, preserving shareholder value while funding growth.

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## Outlook, Management Guidance, and Execution Risk Management's guidance narrative centers on converting capital investments into predictable earnings growth. The narrowing of 2025 non-GAAP operating earnings guidance to $4.00-$4.06 per share from the prior $3.94-$4.06 range, announced after nine-month results, signals confidence that Q4 will deliver despite the Hope Creek refueling outage. The reaffirmed 5% to 7% long-term CAGR through 2029, with 2025 as the new base year, implies earnings power of $5.10-$5.40 per share by 2029 if executed successfully. This frames expectations around capital deployment execution rather than commodity price speculation, a more controllable variable for management. The data center pipeline represents the largest swing factor to this guidance. The 9,400 megawatts of large load inquiries as of June 2025, up from 6,400 megawatts in March and under 400 megawatts in early 2024, includes approximately 2,600 megawatts of mature applications. Management's historical conversion rate of 10-20% suggests 940-1,880 megawatts could eventually interconnect, representing load growth of 5-10% above current system peak. Each megawatt of new load spreads fixed costs across a larger base, potentially lowering rates for existing customers while creating new revenue streams. If New Jersey succeeds in attracting AI hubs, PSEG's engineering assessment turnaround averaging four months could make it the utility of choice, accelerating conversion. Nuclear contract opportunities provide another potential upside driver. Management is exploring long-term agreements for power and/or emission credits from nuclear facilities, similar to deals hyperscalers have signed with other generators at premiums of $30-$50 per megawatt-hour. While PSEG has stated it is "not interested in moving back into the merchant generation business," contracting a portion of nuclear output under multi-year agreements would reduce earnings volatility while capturing scarcity premiums. The Salem uprate project, adding 200 megawatts between 2027-2029, positions the fleet to serve this demand. This could lift the long-term earnings CAGR above the stated 5-7% range without increasing merchant risk, as contracted revenue would be as stable as regulated returns. Execution risks center on external factors rather than operational competence. The PJM capacity market's governance challenges, which caused three years of auctions to pile up and spike customer bills, remain unresolved. Management's frustration is evident: "This governance process is the core problem here right now," noting that governors need a member committee vote just to get a seat at the table. Delayed capacity market reforms could prolong price volatility, impacting both customer affordability and generator margins. However, it also increases pressure for state-level solutions, potentially including legislation introduced in February 2025 that would allow regulated utilities to build and own new generation—a policy shift PSEG explicitly supports. ## Risks and Asymmetries: When Regional Challenges Become Company-Specific Threats The most material risk to the thesis is New Jersey's affordability crisis colliding with necessary infrastructure investment. With 36% of likely voters citing taxes as the state's top problem and 21% citing affordability, regulators face intense pressure to limit rate increases. The Basic Generation Service default rate's 17% increase starting June 1, 2025, driven by PJM capacity auction results, creates political headwinds. This could pressure regulators to reject future rate increases or claw back previously approved returns, compressing PSE&G's earned ROE below authorized levels. The company's response—working with regulators on summer relief initiatives and emphasizing that PSE&G's combined bill remains favorable versus other New Jersey utilities—demonstrates proactive management but cannot eliminate political risk. PJM's governance dysfunction creates a binary outcome. If the market cannot attract new generation in a timely fashion, as CEO Ralph LaRossa questioned—"I don't know if there is a PJM market anymore"—New Jersey may implement a separate capacity mechanism or allow utility-owned generation. This would be positive for PSEG, as it has sites with grid connection capability, pipeline supplies, and in-house expertise to build new supply using prevailing wage labor. However, if PJM reforms successfully attract merchant generation, it could depress capacity prices and limit PSEG's ability to contract its nuclear output at premium rates. This creates a "heads I win, tails I don't lose much" asymmetry: either PJM fixes its market and PSEG's nuclear fleet earns market rates, or it doesn't and PSEG becomes the state's preferred builder of new generation. The data center pipeline, while promising, carries conversion risk. Approximately 25% of the 4,700 megawatts of new business leads have been incorporated into PJM's 2025 system peak load forecast, but the remaining 75% may never materialize. Hyperscalers are increasingly demanding flexibility in interconnection rules, and uncertainty around PJM's large load interconnection process creates friction. As CFO Dan Cregg noted, "trying to strike a commercial deal when there is uncertainty around rules" complicates negotiations. Investors are implicitly pricing in some conversion of this pipeline; if conversion rates fall below the historical 10-20% range, growth expectations would need to reset lower. Nuclear operational risk, while low, cannot be ignored. The Hope Creek unit's 499-day continuous run demonstrates exceptional reliability, but any unplanned outage during peak summer months could cost millions in lost energy margins. The NRC's September 2025 reinstatement of Peach Bottom's license expiration dates to 2053 and 2054 removes regulatory uncertainty, but the industry-wide challenge of spent fuel storage and potential regulatory changes post-2032 when PTCs expire create long-term questions. Nuclear represents the primary differentiation from pure-play utilities; any operational or regulatory setback would eliminate the upside optionality that justifies PSEG's valuation premium to traditional peers. ## Valuation Context: Pricing the Nuclear Option At $83.52 per share, PSEG trades at 20.1 times trailing earnings and 20.5 times forward earnings, roughly in line with utility peers but below its earnings growth rate. The enterprise value of $64.86 billion represents 14.6 times EBITDA and 5.5 times revenue, modest premiums to Consolidated Edison (TICKER:ED) (EV/EBITDA 10.5x) and Exelon (TICKER:EXC) (11.9x) but justified by superior growth. The 3.02% dividend yield, while below FirstEnergy (TICKER:FE)'s 3.73% and Eversource (TICKER:ES)'s 4.48%, is supported by a conservative 59.9% payout ratio and backed by 118 consecutive years of payments. This suggests the market is valuing PSEG as a traditional utility while largely ignoring the nuclear fleet's optionality and the data center pipeline's potential.

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Peer comparisons highlight PSEG's unique positioning. Consolidated Edison (TICKER:ED) trades at similar P/E multiples but lacks nuclear generation, offering only regulated utility growth. Exelon (TICKER:EXC), with a larger customer base, carries higher debt-to-equity (1.78 vs. 1.38) and lower ROE (10.3% vs. 12.6%). FirstEnergy (TICKER:FE)'s scandal-tainted governance and higher payout ratio (75.7%) contrast with PSEG's fourteen consecutive annual dividend increases. Eversource (TICKER:ES)'s focus on offshore wind has created execution challenges, while PSEG's nuclear fleet provides immediate, proven carbon-free power. PSEG's valuation does not reflect its scarcity value: it is one of few utilities with both regulated growth visibility and merchant nuclear upside in the highest-demand region of the country. The balance sheet supports continued capital deployment without dilution. Debt-to-equity of 1.38x is moderate for a capital-intensive utility, and the $3.6 billion liquidity position provides flexibility to fund the $3.8 billion 2025 capex plan. The recent extension of $3.75 billion revolving credit facilities to March 2029 and the August 2025 issuance of 4.9% notes due 2035 demonstrate continued access to attractively priced capital. This validates management's commitment to funding growth internally, preserving per-share value while rate base compounds at 6-7.5% annually. ## Conclusion: A Defensive Growth Story at an Inflection Point Public Service Enterprise Group has engineered a strategic position that turns regional energy challenges into shareholder value. The regulated utility provides a foundation of predictable earnings growth driven by $21-24 billion of capital investments that expand rate base at 6-7.5% annually, while the nuclear fleet offers a call option on the increasing scarcity value of 24/7 carbon-free power. This combination delivers utility-like downside protection with growth equity upside, a rare profile in an industry typically bifurcated between stodgy wires-and-pipes companies and volatile merchant generators. The investment thesis faces a critical test over the next 18 months. New Jersey's policy response to the resource adequacy crisis—whether embracing utility-owned generation or relying on flawed PJM markets—will determine PSEG's strategic options. The conversion of 9,400 megawatts of data center inquiries into actual load will dictate whether growth exceeds the guided 5-7% CAGR. And management's ability to contract nuclear output at premium rates will reveal if the nuclear renaissance translates to tangible earnings upside. These variables separate PSEG from traditional utilities: success on any front could drive earnings materially above guidance, while failure would still leave investors with a quality regulated utility yielding 3% and growing earnings mid-single digits. For investors, the risk/reward asymmetry is compelling. Downside is limited by the regulated utility's earnings floor and nuclear PTC protection, while upside includes data center load conversion, potential long-term nuclear contracts, and policy-driven generation opportunities. The stock's valuation at 20x earnings does not reflect these options, suggesting the market still views PSEG as a conventional utility rather than a strategic player in the AI-driven energy transition. As management noted, "the need for our investment in leadership has never been more evident"—and for investors willing to look beyond traditional utility metrics, that leadership is being priced at a discount to its true strategic value.