# The Great Inversion: complete compendium Cheap supply, scarce connection. The full series and its supporting products. Assembled 2026-08-28 from https://greatinversion.info. \pagebreak # The Great Inversion ## Executive summary of a series on rebuilding America's electricity institutions **Problem.** Electricity has never been cheaper to produce, but American electric bills are rising faster than inflation and becoming a top-tier political issue. **Cause.** Institutions built for scarce, central generation now govern abundant, distributed generation. Connection is still governed by substantial project-specific study and discretionary cost allocation, even as FERC has begun reforming the bulk interconnection process. Utilities also remain primarily compensated through capital-based ratemaking. **Solution.** Five principles that finish the unbundling America began in the 1990s and stopped at the substation: a utility should earn on outcomes delivered, not capital deployed; the access decision should sit apart from the wires owner’s commercial interest; where and when a resource operates should affect what it earns; access should follow published rules, not case-by-case permission; and incremental system costs should sit with those who create them, socialized transparently where attribution fails. Each principle carries a menu of mechanisms with a stated, deliberately contestable preference, and every preferred mechanism already operates somewhere. **Cost to the public.** Direct public expenditure is limited, but implementation is not costless. Transition costs include regulatory staff, data systems, metering, and IT and should be judged against the capital and operating spending the program avoids. Scenario aggregation puts that comparison near ten to one. **Expected outcomes.** Faster and more predictable connection; better use of existing network capacity; lower long-run system cost; stronger cost attribution for incremental large loads; and potentially substantial avoided generation investment where flexible load can use existing headroom. **First actions.** Governors call for a performance-regulation docket and for published interconnection metrics, by direction where commissions are appointed and by public case where they are elected. Commissioners open that docket and require machine-readable grid data. Legislators authorize performance regulation, a right to connect, and a standard value-stack tariff. FERC makes connect-and-manage the interconnection default where technically feasible and sets Order 2222 deadlines with consequences. --- America has more generating capacity waiting in interconnection queues than it currently operates: 2,061 gigawatts against roughly 1,400 gigawatts in service, much of it financed, engineered, and sited. The typical project waits more than five years, and historically about 13 percent of that capacity ever connects. At the same time, data-center campuses that would pay a premium for power cannot buy it, gas turbine order books stretch toward five years, PJM's capacity charges have climbed from $2.2 billion to $16.4 billion a year, and retail electricity prices are rising fast enough to decide governors' races. The grid no longer suffers from scarce electricity. It suffers from scarce permission. **The inversion.** Every assumption the grid's institutions were built on has flipped. Generation was scarce and central; it is now cheap and everywhere. Storage was impossible; it is a manufactured product on a falling cost curve. Demand was passive; it is growing, flexible, and increasingly brings its own supply. Connection, once trivial, is the binding constraint on everything from AI capacity to reshored factories. The institutions absorbed every reform: process changed five times since 1978, and the payoff and the gate did not. Paper I traces how they formed (1907 compact, 1935 federal-state seam, 1990s wholesale unbundling that stopped at the substation). Paper II documents five institutional failures: ratemaking that pays utilities for capital rather than outcomes, access administered by the party being competed with, durable rules denied to the fastest-connecting resources, connection rationed by discretionary process, and a capacity auction that has hit administrative price caps in four consecutive auctions while attracting almost no new entry. **The thesis.** The monopoly has narrowed. Wires remain a natural monopoly. Generation, storage, demand flexibility, interconnection, and grid data do not, yet the rules governing all of them still assume they do. The remedy completes the unbundling the United States started in the 1990s: separate the monopoly platform from everything contestable, this time at the distribution level, and make access to the network a matter of published rules at every voltage level. ### Unbundling unfinished: five principles to complete the job Each principle is stated here by its preferred mechanism. Paper III carries the full menu of options under each, with a stance and an evidence tier for every mechanism evaluated, including the ones we set aside and the ones we reject. - **Pay for performance.** Total expenditure (Totex) revenue caps and yardstick benchmarking on the British and Hawaiian models replace cost-of-service ratemaking. This reform comes first because it changes the utility's economic payoff before the program asks it to relinquish control of access, data, or procurement. - **Separate the referee.** Interconnection, grid data, and flexibility markets move to an independent or ringfenced Distribution System Operator. The utility keeps the poles and the storm response and loses the gatekeeper's chair. - **Pay resources for what they do for the grid.** Default dynamic retail rates with hedged options, posted locational offers wherever a resource can defer an upgrade, and Australian-style real-time operating envelopes in place of static interconnection caps. - **Connect by rule.** A standardized pathway for small resources meeting published operating limits, a connect-and-manage pathway required of every RTO for bulk generation and large loads, reconductor-first requirements for transmission expansion, and fast-track access for hyperscalers in exchange for verified peak-hour curtailability. - **Make new load fund reliability.** Forward obligations phase in while the centralized auction becomes a residual backstop. Data centers carry their own capacity costs, and generators finance against long-tenor contracts instead of an auction that swung tenfold in one cycle. **The prize.** On the order of 100 GW of headroom from large-load flexibility on the existing system, which is roughly $100-220 billion of generation capex that need not be built, spanning EIA reference costs and observed 2025-26 market costs; a doubling of throughput on reconductored transmission corridors without new permitting; and months-scale access to the healthiest fraction of the 2,061 GW queue. The first tranche of this capacity program is already built. **The consumer case.** The cheapest electricity ever generated is arriving alongside bills rising faster than inflation, in the fourth such episode in American history and the first without a cost story behind it, because institutions stand between cheap supply and the meter. Each principle aims at a line item: connection by rule lets $40-98/MWh generation compete into the supply line; obligations move data-center capacity costs off household bills and onto their drivers; and performance regulation, reconductor-first showings, and shared-savings deferrals discipline the delivery line, now the fastest-growing part of many bills. Hedged flat options, bill protection, and low-income rates are built in, and the commitment is measurable: real bill growth below matched peer states. **The coalition.** Everyone outside the queue: hyperscalers, DER developers, independent generators (once Principle 5 is heard as "more PPAs"), industrial customers, and the institutional capital that finances all of them. The opposition concentrates where current rules produce earnings, which is why the sequencing leads with the reform that changes what earnings reward. **The path, an illustrative sequence.** No act of Congress required. 2027: states open performance-based regulation dockets; FERC rulemakings on connect-and-manage and Order 2222 deadlines. 2028-29: totex orders take effect, automated interconnection goes live, large-load flexibility tariffs standardize. 2030-31: separated access administration where the escalation criteria are met, first hybrid obligation delivery year. 2032-35: the centralized auction recedes to a residual backstop where obligation coverage passes the reliability-and-cost test, and value-stack tariffs end the net-metering fights. Success is measurable annually: interconnection in days for small resources, offers inside 18 months for large ones, queue conversion above half for mature cohorts, and real bill growth below matched peer states. The grid's first two settlements arrived only after visible, expensive failure, over incumbent opposition, and were later defended by their former opponents. Every precondition for the third is now met. The end state: in 2035, a factory's 20 MW request returns in minutes with headroom, prices, a flexible alternative, and a firm date, and no one waits years for permission. The companion document What Success Looks Like describes that year in full, from the developer's morning to the regulator's dashboard. *Three core papers: I. "How We Built Institutions for the Wrong Grid." II. "The Great Inversion: Cheap Supply, Scarce Connection." III. "Completing the Market." Two companion documents: "What Success Looks Like" and "Examples in the Evidence Base."* \pagebreak # How We Built Institutions for the Wrong Grid ### Paper I: The history, in service of the argument *Companion papers: II. The Great Inversion (the diagnosis) and III. Completing the Market (the reforms).* --- The grid no longer suffers from scarce electricity. It suffers from scarce permission. Paper II documents that inversion; this paper explains where the permission structure came from, because many of the rules now constraining the queue were sensible answers to the engineering and institutional problems of their time. Three settlements built the modern grid. Understanding what each one solved, and what each one assumed, is what makes the third settlement proposed in Paper III legible as evolution. ## Settlement one: the regulatory compact (1907) Electricity began as a competitive business, and an ugly one. After Edison energized Pearl Street in 1882, dozens of firms strung duplicate wires through American cities, and city councils sold franchises in ways that made "utility" and "corruption" synonyms. Samuel Insull, Edison's former secretary and the builder of Chicago's Commonwealth Edison, proposed the fix that stuck: one large generator and one set of wires served a city more cheaply than five competing systems, so let the state grant a monopoly and discipline it through a commission instead of through rivals. Wisconsin and New York created the first public utility commissions in 1907. The deal, an exclusive franchise plus an obligation to serve, in exchange for rates regulated around prudently incurred costs and an authorized return on capital, is the regulatory compact, and it still governs the wires outside a few restructured states [1][2]. Two features of the compact matter for everything that followed. Insull campaigned for it himself, because a state commission was more predictable, and more manageable, than municipal politics; the observation that regulation can serve the regulated as well as the public is as old as the institution, and Stigler formalized it in 1971 [3]. And the compact's payment formula, a return on invested capital, hard-wired a preference that Averch and Johnson would name in 1962: a firm paid for capital will choose capital, whatever the cheaper alternative [4]. Neither feature was a design flaw at the time. Capital was exactly what a country electrifying from nothing needed, and the commission was a real improvement on the city council. The compact scaled until it broke financially. Holding companies pyramided utilities across state lines through the 1920s; the 1929 crash took down the leverage, with Insull's empire among the era's largest business failures, and the New Deal responded with the Public Utility Holding Company Act and the Federal Power Act of 1935. The 1935 settlement drew the jurisdictional seam that still defines the industry: states govern retail rates and distribution, the federal government governs wholesale sales and interstate transmission. Most of the paralysis Paper II documents lives on that seam, because the resources that now matter most for flexibility (batteries, aggregators, flexible loads, distributed generation) operate across or near it. ## The assumption fails (1965 to 1978) For four postwar decades the compact delivered falling real prices, and nobody audits a machine that prints discounts. The discounts stopped in the 1970s: scale economies in thermal generation ran out, oil shocks and inflation drove costs up, nuclear programs hemorrhaged capital, and commissions had to learn to say no. The intellectual foundation cracked with the cost curves. Joskow and Schmalensee's *Markets for Power* (1983) argued that generation, unlike wires, could support competition [5], and PURPA (1978) proved it by accident: required to buy from independent cogenerators at avoided cost, utilities discovered that outsiders could build and run plants perfectly well. The monopoly on generation had been a policy choice wearing an engineering costume. ## Settlement two: the half-finished unbundling (1992 to 2000) The second settlement acted on that discovery at higher voltages. The Energy Policy Act of 1992 opened wholesale generation to competition. FERC's Order 888 (1996) forced utilities to open their transmission lines to all comers on equal terms, encoding the principle that a wire owner who also owns generators cannot referee access to the wire. Order 2000 produced the independent regional operators that now dispatch two-thirds of American load. The pricing architecture came from Schweppe's *Spot Pricing of Electricity* and Hogan's locational marginal pricing: let the price of power vary by time and place to reflect the physics [6][7]. Turning Kirchhoff's laws into a price system remains one of the great applied results in market design, and it works: at the transmission level, thousands of independent generators compete to serve load at prices that track real scarcity. The important distinction is that wholesale unbundling did not eliminate monopoly. It separated competitive functions from transmission's natural-monopoly platform. This series extends that logic into distribution; it does not assume that distribution itself has ceased to be a natural monopoly. The settlement stopped at the substation, for two reasons worth distinguishing. The defensible reason was trauma: California's 2000-01 crisis, a failure of design and manipulation rather than of competition itself [8], froze retail restructuring in half the states and made "market" a dirty word in utility regulation for a decade. The less defensible reason was that nobody powerful needed the distribution system opened. In 2000, nothing behind the meter could generate, store, or flex, so a distribution monopoly that owned the wires, planned the network, ran the interconnection process, held the data, and sold the default product seemed harmless. The local utility kept every one of those roles. It holds them today. ## The wrong grid Which is how America arrived at institutions for the wrong grid. The compact assumes the utility must build everything; a 2,061 GW queue of independent developers is waiting to build instead [9]. Cost-of-service ratemaking assumes capital is the scarce input; capital is lined up and connection is scarce. The 1935 seam assumes a clean boundary at the meter; batteries and flexible data centers live on the boundary. Order 888 assumes the gatekeeping problem ends at transmission voltage; the same conflict of interest now operates on every distribution feeder. Each assumption was true when written. The technology evolved beyond them, and the institutions, unlike the technology, have no cost curve pushing them forward. The pattern across both prior settlements is the useful lesson. Each came only after the old arrangement failed visibly and expensively, each was fought by the incumbents of its day, and each was later defended by many of the same interests that fought it. The third settlement, unbundling the distribution platform and making connection a matter of rules at every voltage level, is specified in Paper III. Its timing follows the same pattern: the visible, expensive failure is already here. ## The precedent that actually fits Policy arguments lean on analogies, and most of the popular ones fit this case badly. Airline deregulation removed price and entry controls from a service with no physical network bottleneck, so it says little about a wires monopoly. Telecom local-loop unbundling is closer and mostly a cautionary tale: regulators tried to share one copper network among competitors by administratively pricing its parts, and the regime collapsed into litigation. Neither is the model here. One precedent matches the structure point for point: natural gas restructuring under FERC Orders 436 and 636 (1985-1992) [10]. Gas pipelines had been merchants that bought the commodity, transported it, and sold the bundle, exactly as utilities bundle electrons with delivery. FERC separated the roles: pipelines became open-access carriers paid regulated rates for transportation, the commodity became a competitive market, and storage, the physical feature that makes a commodity warehousable and hedgeable, developed into a traded service. The parallel is structural, because batteries are beginning to give electricity some of the temporal flexibility that storage gave gas, converting part of an instantaneous delivery service into something with a forward curve. The gas transition also previews the hard parts, since it required explicit treatment of stranded contracts and a decade of litigation, and it ended with a liquid national market that nobody proposes to re-bundle. Where the analogy fails is instructive too: electricity moves near the speed of light on a network that must balance every second, which is why this series pairs open access with operating envelopes and obligations instead of copying gas rules verbatim. By first principles, the gas precedent shows the destination is reachable. --- ## Sources [1] Thomas P. Hughes, *Networks of Power: Electrification in Western Society, 1880-1930* (Johns Hopkins, 1983). [2] Richard F. Hirsh, *Power Loss: The Origins of Deregulation and Restructuring in the American Electric Utility System* (MIT Press, 1999). [3] George J. Stigler, "The Theory of Economic Regulation," *Bell Journal of Economics and Management Science* 2:1 (1971). [4] Harvey Averch and Leland L. Johnson, "Behavior of the Firm Under Regulatory Constraint," *American Economic Review* 52:5 (1962). [5] Paul L. Joskow and Richard Schmalensee, *Markets for Power* (MIT Press, 1983). [6] Fred C. Schweppe et al., *Spot Pricing of Electricity* (Kluwer, 1988). [7] William W. Hogan, "Contract Networks for Electric Power Transmission," *Journal of Regulatory Economics* 4 (1992). [8] Severin Borenstein and James Bushnell, "The U.S. Electricity Industry After 20 Years of Restructuring," *Annual Review of Economics* 7 (2015); Frank A. Wolak's CAISO Market Surveillance Committee analyses. [9] Joseph Rand et al., *Queued Up*, Lawrence Berkeley National Laboratory (annual editions). [10] FERC Orders No. 436 (1985) and No. 636 (1992), restructuring interstate natural gas pipelines as open-access carriers; Paul MacAvoy, *The Natural Gas Market* (Yale, 2000). *General-audience companions: Gretchen Bakke, "The Grid" (2016); Forrest McDonald, "Insull" (1962); Julie A. Cohn, "The Grid: Biography of an American Technology" (2017).* \pagebreak # The Great Inversion: Cheap Supply, Scarce Connection ### Paper II: The diagnosis *Companion papers: I. How We Built Institutions for the Wrong Grid (history) and III. Completing the Market (the reforms).* --- ## America's new bottleneck America has more generating capacity waiting in line than it currently operates. Some 2,061 gigawatts sits in interconnection queues against roughly 1,400 gigawatts in service, much of it financed, engineered, and sited [1]. The typical project waits more than five years. Historically, about 13 percent of that capacity ever connects. Meanwhile a hyperscale data-center campus that would pay a premium for power today cannot buy it, gas turbine order books stretch toward five years [2], PJM's capacity charges have risen from $2.2 billion to more than $16 billion a year [3][4], and retail electricity prices are climbing fast enough to decide governors' races. Scarce electrons no longer explain any of this. America increasingly has the ability to produce cheap electricity, but lacks an equally scalable institutional system for connecting and coordinating it. Some of that scarcity is physical and no reform repeals it: transformers, transmission corridors, HVDC equipment, skilled crews, and buildable land are all physically constrained. But in many high-growth regions, institutional access to physical capacity has become a binding constraint alongside the physical constraints themselves: permission to connect, to compete, and to be paid what a resource is worth, where and when it is worth it. The bottleneck moved from the power plant to the institutions, and the institutions have not caught up. That is the thesis of this series: the monopoly has narrowed. Wires remain a natural monopoly. Generation does not. Storage does not. Demand flexibility does not. Interconnection and grid data should not. Yet the rules governing all of them still assume they do. One framework organizes everything that follows: | Level | The idea | |---|---| | Big idea | **The Great Inversion**: supply got cheap, connection got scarce | | Core thesis | The natural monopoly has narrowed | | Observable symptom | Scarce permission: queues, caps, churning tariffs | | Policy objective | Complete the market | ## The inversion Every assumption the grid's institutions were built on has flipped. | | **1980** | **2026** | |---|---|---| | Generation | Scarce, central, utility-built | Much cheaper in many technologies; increasingly built by non-utility developers | | Storage | Impossible | Commercially viable and increasingly system-integrated | | Demand | Passive, predictable | Active, growing, self-supplying, flexible | | Transmission capacity | Ample | Scarce | | Connection to the grid | Trivial | The binding constraint | | Who builds | The utility | A queue of thousands of independent developers | | Institutions | Matched the technology | Changed unevenly; many legacy incentives remain | Utility-scale solar's levelized cost fell 84 percent between 2009 and 2026, from $359/MWh to a $40-98 range, and battery packs fell further still, 93 percent since 2010 to $108/kWh, with stationary-storage packs at $70 [5]; solar became the first generation technology in a century that pencils at household scale. Batteries reduce one of the industry's historic constraints, the need to balance supply and demand continuously, by allowing energy to be shifted across time. They do not eliminate the need for firm capacity, transmission, or distribution infrastructure. An electron bought at noon now sells at 7 p.m. Demand returned after two decades of flat load, led by data centers whose binding variable is time to power. When the conventional answer, new gas turbines, quotes a five-year delivery date [2], the fastest source of new capacity is increasingly the resource that can be deployed within the existing network’s available headroom, and the second fastest is whatever is already built and waiting in the queue. Cheap supply, scarce connection. Hold that inversion in mind; every failure below is a symptom of institutions still organized around the old column. ### The state of the grid Each row moves the same direction: the technology and capital got cheaper and more abundant while connection, institutional friction, and customer costs got worse. | Metric | Then | Now (2026) | Source | |---|---|---|---| | Utility-scale solar LCOE | $359/MWh (2009) | $40-98/MWh unsubsidized, avg $69 | Lazard 2026 [5] | | Battery pack price | ≈$1,475/kWh (2010, real 2025$) | $108/kWh; stationary packs $70 | BloombergNEF 2025 [5] | | Active interconnection queue | A fraction of the fleet (mid-2000s) | 2,061 GW, against ~1,400 GW in service | LBNL [1] | | Typical queue duration | Under 2 years (projects built mid-2000s) | ≈5 years | LBNL [1] | | Historical queue completion | Majority connected (mid-2000s cohorts) | 13% of capacity; 75% withdrawn | LBNL [1] | | Gas turbine lead time | ≈2 years (2019) | ≈5 years | S&P Global [2] | | PJM annual capacity cost | $2.2B (2024/25 delivery year) | $16.4B (2028/29) | PJM [3][10] | | Retail electricity prices | Tracked inflation (2013-2023) | Outpacing inflation since 2022; nominal residential +33% since 2019 | EIA; LBNL | ## The stakes are larger than the grid For households, the inversion arrives as a paradox. American electricity prices have outpaced inflation in four periods: the early 1970s, driven by the oil shocks; the early 1980s, driven by nuclear cost overruns and utility bond yields near 17.5 percent; the mid-2000s, driven by natural gas; and now. In each of the first three the input got more expensive and the bill followed. This time the inputs got cheaper, with utility-scale solar down 84 percent and battery packs down 93 percent, which is what makes the current episode different in kind rather than in degree. The cheapest electricity ever generated is showing up as steadily rising bills, with nominal residential rates up 33 percent since 2019 and electric and gas utilities requesting a record $31 billion of rate increases in 2025, double the prior year. Cheap supply and expensive bills coexist because the institutions stand between them, and every failure documented below lands, through one line item or another, on an electric bill. Electricity has quietly become industrial policy. AI training capacity is gated on powered land. Semiconductor fabs and reshored factories site wherever interconnection is fastest, which increasingly means abroad or behind a private fence. The Department of Energy has invoked emergency authority to keep aging plants running [4]. A country's ability to connect new supply and new demand to its grid now shapes its competitiveness in the same way its ports and highways once did. Suppose a hyperscaler needs 500 MW. Route one, new gas turbines: order placed in 2026 against a roughly five-year manufacturing backlog [2], then construction; first power around 2031. Route two, solar plus storage: the equipment is purchasable today and the construction schedule runs 12 to 18 months, but a study-first interconnection queue adds more than five years, and more than eight in PJM [1][21]; first power around 2031 or later. Route three, the same solar-plus-storage project under Texas-style connect-and-manage timelines, which run two to three and a half years: first power around 2028 or 2029. Route four, a flexibility agreement that fits the load into headroom on the existing system, the structure Google signed in 2025 and has since scaled toward a contracted gigawatt [11]: service in months. The engineering delay is 12 to 18 months. Everything beyond that is institutional, which means the schedule for American reindustrialization is currently set by procedure rather than by physics. The question this series answers is why a nation that got very good at building cheap generation got very bad at plugging it in. ## Four alternative explanations fall short Four candidate explanations for alternative diagnoses are not supported by the evidence. **Generation is getting more expensive.** Partly true for firm capacity: heavy-duty gas turbine lead times have stretched toward five years, and GE Vernova's backlog grew from 83 GW to 100 GW in a single quarter [2]. The unfirmed side moved the other way: utility-scale solar's levelized cost fell 84 percent since 2009, battery packs 93 percent since 2010, and solar paired with storage cleared at $87 per MWh unsubsidized against $144 to $276 for a gas peaker [5]. A cost story that runs through generation must also explain why bills rose fastest on the delivery lines, where generation does not appear. **The wires are starved of capital.** The spending record says otherwise. Transmission investment nearly tripled between 2003 and 2023, distribution rose about 160 percent and is now the largest capital category at roughly $66.5 billion a year, and congestion stayed high through all of it [26][27]. Capacity stayed scarce while spending set records, which moves the question from how much money to what the money buys. **Load growth did it.** The timing fails. PJM's application-to-operation run stretched from under two years in 2008 to more than eight by 2025, and the queue crossed the size of the operating fleet before the AI buildout reached the meter [21]. New campuses raise the stakes; they arrived at the tail of the backlog, and 2,061 GW of willing supply is standing in it [1]. **Permitting and equipment are the bottleneck.** Transformers, corridors, and crews are scarce, and no rule repeals that. The control is Texas: drawing on the same national equipment market and the same labor pool, ERCOT brought 14.2 GW of solar and storage online in 2021 and 2022 against PJM's 5.6 [6]. When the same machines move through different institutions at almost triple the speed, the machines are not the variable. **The institutions allocate badly.** This is the residual the other four leave standing, and the only account that explains three facts at once: identical equipment connecting at different speeds across a border, record network spending beside persistent congestion, and a queue that predates the load it is blamed on. The first four pressures are real, and every one of them gets more expensive to answer under rules that ration access and pay for capital. The five failures below make that claim specific. ## Five institutional failures These failures are functional. Each failure is an old rule still operating: a design choice that was correct when written and is now the constraint. They are ordered as a mechanism: the payment formula is the motive, the gatekeeper role is the shield that protects it, and the last three are reinforced by the shielded motive. Each failure falls to the principle in Paper III that shares its number. A system can fail at access through a slow interconnection queue, through a capital-biased distribution planner, or through an opaque tariff, and the failure is the same whichever institution produces it. That is why the reforms in Paper III are organized as principles with a menu of mechanisms under each: the function is what must be fixed and the institutional mechanisms are the way the fix gets implemented. The dysfunction is specific, and it is fair to say first what the incumbents are coping with. Utilities face wildfire liability, storm hardening, cybersecurity mandates, an aging workforce, and assets past design life, all at once, and much of their record capital spending addresses real needs. RTO planners absorbed the fastest demand-forecast revisions in fifty years. Commissions process dockets with a fraction of the staff of the companies before them. And every institution described below was rationally designed for the engineering and regulatory conditions of its era. The problem is persistence after the underlying assumptions changed. Much of the persistence is itself rational, because these organizations were optimized above all to avoid catastrophic risk, and risk-avoidant systems change last. Utility executives are optimizing correctly against the incentives regulators built over decades, and would optimize differently against different ones. The critique that follows is aimed at the rules these actors operate under, and it holds even where every individual actor behaves reasonably. That is what makes it an institutional diagnosis: the system produces these outcomes when everyone follows their incentives. ### Failure 1: Utilities earn more when they spend more The insight is sixty years old and comes from regulatory economics. Averch and Johnson showed in 1962 that a firm earning a regulated return on invested capital has a structural incentive to favor capital when the allowed return is tied primarily to rate base [12]. Watch the incentive operate at a single decision. A distribution planner in 2026 faces a feeder that will overload within three years, and four options sit on the desk: | Option | Ratepayer cost | Utility earnings today | Utility earnings under totex | |---|---|---|---| | New substation | ≈$40M capital | ≈10% return for ~40 years | Same allowance as any option | | Reconductor / upgrade in place | A fraction of greenfield | Return on the smaller amount | Keeps most of the savings margin | | Battery contract (third party) | ≈$2M/year | $0 | Shares the savings | | DER aggregation / flexibility | Lowest, most uncertain | $0, plus lost throughput revenue | Shares the savings | The planner is honest, the engineering analysis is competent, and the substation still gets proposed, because the institution's payment formula biased the outcome before the analysis began. The rightmost column is Paper III's Principle 1, and it is the entire point: change what the same planner's employer earns, and the same desk produces different proposals. At transmission voltage the identical table applies. From the earnings perspective, a reconductoring project that doubles a line's capacity for a fifth of the cost of a new line appears as four-fifths of an asset that never got built [8]. **The spending is visible in the functionalized data, and so is what it did not buy.** Utility costs are reported by function on FERC Form 1 and aggregated in the Energy Information Administration's series, which means this argument can be checked. Between 2003 and 2023, distribution spending rose about 160 percent and transmission spending nearly tripled [26]. Investor-owned capital spending reached roughly $208 billion in 2025, up from about $140 billion in 2020, with distribution the single largest category at about $66.5 billion, generation at $62.4 billion, and transmission at $37 billion [27]. Over the same two decades in which distribution and transmission spending grew at those rates, congestion stayed high and interconnection got slower, which is the pattern a system that pays for capital, not outcomes, would be expected to produce. **And bills are rising for more than one reason.** Eight forces move an electric bill, and all eight are now pushing upward, generation included as firm-capacity costs climb. This program directly targets three of them. Network spending for growth and capacity is rising sharply, and Principles 1, 3, and 4 aim directly at it. Capacity and reliability charges are rising sharply, and Principle 5 reassigns them to the loads that cause them. The cost of delay, study, and withdrawal is rising, and Principles 2 and 4 remove it. The remaining five are largely untouched. The cost of generating power is set by the market and needs no docket. Wildfire mitigation, storm hardening, and the replacement of assets past design life are all rising, and total-expenditure regulation funds them in full, which is the point of separating hazard spending from discretionary build. The cost of financing that spending and the scarcity of equipment and skilled labor are both rising, and reform touches them only indirectly, by deploying less capital and reusing more of what exists. The three forces of focus here also compound: capital earns a return for forty years, capacity charges recur annually, and delay multiplies both. Two qualifications. Generation capital is rising quickly again on load growth and now stands at roughly 30 percent of the total, its highest share in more than a decade, so delivery is not the whole story of the last two years even though it is the whole story of the last two decades. And some of the delivery increase answers real needs, since storm hardening, wildfire mitigation, and the replacement of assets past design life all land in that line. What the functionalized data cannot explain away is the ranking. Distribution is the largest capital category in the industry and the least examined of the three. Compared with transmission it has far less federal economic oversight, no comparable nationwide regional-planning framework, and highly uneven competitive-procurement requirements, while generation in restructured regions faces market discipline. It is simultaneously the biggest place utilities spend and the least examined. The return on capital is an important structural reason, but not the only one. Prudence review rewards tangible assets over contracted services. Operating expense carries disallowance risk that capital does not. Capital produces predictable earnings that analysts model easily, while a portfolio of flexibility contracts does not. A substation is easier to defend at a public meeting than a procurement strategy. And a utility that under-builds and then fails carries a liability that a utility that over-builds never does. A framework that pays for outcomes has to displace all of that, not merely the return. This is a claim about incentives, and the incentives were written by commissions and legislatures, so responsibility runs through them. The evidence that the incentive dominates behavior is the pattern itself: enthusiasm for self-built infrastructure of every kind, resistance to third-party resources that compete with rate base, and slow-walked transparency on hosting capacity and interconnection automation. Where the incentive flips, behavior flips with it; Paper III presents the British and Hawaiian evidence. The cheaper option works when someone is paid to choose it. Consolidated Edison's Brooklyn-Queens Demand Management program avoided or deferred a planned infrastructure investment whose original value was roughly $1 billion, using approximately $200 million of demand-side and distributed resources (52 MW of demand reduction plus 17 MW of distributed investment), and it happened because New York's regulators built a specific earnings mechanism to reward the deferral [18]. The accounting has been contested, and fairly: critics calculated a full ten-year deferral cost closer to $855 million once traditional spending inside the program is counted, so the honest claim is that the alternative was materially cheaper, not that a billion dollars vanished [18]. Arizona Public Service installed a 2 MW, 8 MWh battery at Punkin Center rather than rebuilding roughly 20 miles of rural distribution line, deferring the rebuild by three to six years at about half the cost. The system was later placed on standby and disconnected in 2019 after an unrelated battery-fire incident elsewhere on the system, which makes it an honest illustration of both deferral economics and early-storage operational risk. Sterling, Massachusetts, whose municipal utility still operates its 2 MW battery, reports peak-charge savings of roughly $400,000 a year, an estimate analyzed by Sandia National Laboratories [18]. The point of these cases cuts both ways. Non-wires alternatives are proven, and each one required either an unusual regulatory carve-out or a utility outside the investor-owned incentive structure. Under standard cost-of-service ratemaking, BQDM-style outcomes are exceptions someone had to engineer, which is the diagnosis restated as evidence. The political economy compounds the ratemaking. The regulated firm holds the models, the data, the recoverable legal budget, and the career pathways; the public is represented by intervenors on shoestring budgets. Stigler formalized the pattern in 1971 [13], and Ohio demonstrated the extreme case in practice, where a roughly $60 million scheme bought a legislative bailout and sent the speaker of the Ohio House to federal prison [14]. Capture that blunt is rare. The everyday version, an information asymmetry that no one needs to corrupt, is universal. ### Failure 2: The competition administers the rules The rule is structural: for a battery, a solar array, or a flexibility aggregator seeking to connect, the incumbent utility is both the competition and the administrator of access. It runs the queue, sets the study assumptions, holds the hosting-capacity and load data every access decision rests on, and earns a regulated return on the capital alternative to whatever is applying. The referee has a position in the game. Nothing here requires bad faith, which is what makes it a rule rather than a scandal: an honest engineer applying conservative assumptions to data only her employer can see, on a timeline only her employer controls, produces the same outcome as an obstructive one. The country has run this experiment once and recorded the result. In 1996, FERC found that utilities administering access to their own transmission systems discriminated in favor of their own generation, and Order 888 answered with open-access tariffs, functional separation of the transmission function, and a public system for posting available capacity [25]. The finding was not that utility planners were dishonest; it was that self-administered access by an interested party could not be made neutral by conduct rules alone. That finding has never been extended to distribution, where the same structure persists: hosting-capacity data published late, partially, or only under commission order; study queues without binding clocks; and interconnection cost estimates that can move after a project has committed capital, produced by the party that benefits when the answer is a network upgrade. Where regulators have acted, the remedy is always the same: order the incumbent to publish what it knows. This failure is the enforcement layer for the other four. Serial permission (Failure 4) persists because the gatekeeper administers it. The capital bias (Failure 1) persists because the party choosing between wires and services owns the analysis. Fragile compensation (Failure 3) persists because the data that would justify durable terms is held by the counterparty. A reform program that changed the other four rules and left this one standing would be re-litigated inside the gatekeeper's own processes, one docket at a time. ### Failure 3: Distributed resources are compensated by tariffs that can be rewritten, not by contracts that can be financed Distributed and community solar, behind-the-meter batteries, and flexible demand interconnect in months and sit where distribution constraints bind. Their compensation is a patchwork of net-metering regimes and successor tariffs redesigned every few years, often retroactively, usually as the outcome of a political fight between the utility and the solar industry; California alone has cycled through three regimes. FERC's Order 2222, which was supposed to open wholesale markets to aggregated distributed resources in 2020, has compliance timelines stretching toward the 2030s (ISO-NE late 2026, PJM 2028, MISO 2029, SPP 2030) [15]. Whatever the right compensation level, and reasonable analysts disagree about it, the pattern is self-defeating: the most scalable resources on the grid cannot be financed against rules that change with each rate case. ### Failure 4: Projects must ask permission one at a time The rule is serial and discretionary: each project is studied one at a time, in the order it arrived, against the network as it stood that day, and connection is granted case by case. Rationing by process means the queue itself, not price and not physics, decides what gets built and when. That was workable at a dozen large plants a year; it is the binding constraint at two thousand gigawatts of applicants. **What FERC Order 2023 changed.** Order 2023 replaced much of the legacy serial process with a first-ready, first-served cluster framework and stronger readiness requirements. This paper does not assume that nothing has changed. It argues that study reform alone does not solve network expansion, cost allocation, operating limits, and distribution-level access. Queue length is not itself evidence of failure. A queue can be long because entry is cheap, a large share of it always was speculative, and changing interconnection costs can make an otherwise viable project uneconomic. What indicates a process that no longer scales is the combination: withdrawal rates above 70 percent, median durations beyond five years, restudies triggered by every departure, and completion rates that have fallen to 13 percent of capacity. Follow a utility-scale solar project through the median experience in Lawrence Berkeley National Laboratory's data [1]. The developer files an interconnection request and enters a study queue behind hundreds of others. A feasibility study arrives, then a system impact study, then a restudy when a neighboring project drops out and changes the math, then a cluster restudy under reformed procedures, then a network upgrade cost allocation that may exceed the cost of the project itself. Five years pass between request and decision; in PJM specifically, the average application-to-operation timeline stretched from under two years in 2008 to more than eight by 2025 [21]. Four in five projects exit before connecting, and every exit triggers restudies for everyone behind them. Now run the same project in Texas. ERCOT studies only local reliability effects, connects the project in a fraction of the time, and manages congestion afterward through the energy market, with the developer bearing curtailment risk. The approach is called connect and manage, and it is the main reason ERCOT has added new generation and storage faster than any other U.S. system this decade, bringing 14.2 GW online in 2021 and 2022 against PJM's 5.6 GW despite PJM being more than twice its size [6]. Faster is not immune: ERCOT's own median storage timeline has drifted toward four years as its queue swelled, which argues for pairing speed with proactive planning. Similar physics and technologies, materially different interconnection rules and market arrangements. Texas is therefore a useful real-world comparison for interconnection speed, but not a complete control group for national market design. The network itself is constrained by the same institutions. Interregional transfer capacity stagnated for two decades while cost-allocation disputes consumed planning cycles; FERC's Order 1920 (2024) had to compel the long-term planning that regional tariffs should have produced [7]. The cheapest expansions go unbuilt: analysis published in PNAS finds that reconductoring existing lines with advanced conductors can roughly double a corridor's capacity at a fraction of greenfield cost, with no new permitting, though results vary with conductor choice, thermal limits, and structural condition, and not every corridor qualifies [8]. Why utilities rarely propose it anyway is Failure 1. ### Failure 5: Reliability is bought as a commodity, not financed as an asset The rule treats reliability as a commodity to be bought a year or a season at a time, while the thing being bought, a power plant, is a thirty-year asset that must be financed. A short-dated purchase cannot carry long-dated capital, so scarcity shows up as price spikes rather than as new steel. This failure also indicts an institution the restructuring era itself built; the diagnosis applies the same functional test to a 1990s market that it applies to a 1920s payment formula. PJM's capacity auction, which is supposed to secure supply for 67 million people, cleared at $28.92/MW-day for 2024/25 and has since hit administrative price caps in four consecutive auctions. The pattern is not one market’s quirk: the institutions are shortening visibility instead of reconsidering it, with ISO New England moving to prompt seasonal auctions and New York procuring monthly, while Texas runs no capacity construct at all. In PJM: zonal caps in 2025/26 (BGE at $466.35, Dominion at $444.26, the RTO at $269.92) and the RTO-wide cap in each of the next three, at $329.17, $333.44, and $325 [3][4][9][10]. The December 2025 auction fell 6,623 MW short of the reliability requirement, the first in which the entire RTO including FRR areas fell short, and PJM's own simulation put the uncapped clearing price at $529.80 [9]; the July 2026 auction attracted about 525 MW of new resources [10]. Annual costs rose from $2.2 billion to $16.4 billion over the period. When an auction clears at a ceiling negotiated with a governor, while attracting almost no entry, it has stopped discovering prices and started administering them. The failure compounded across choices: auctions delayed for years, severing price signals from investment timelines; accreditation reforms that repriced the fleet overnight; data-center demand underestimated for a decade, then repriced onto all customers at once; and a queue that blocked supply from answering the very signal the auction sent. The data centers make an awkward villain here. Most would rather contract directly for their own capacity, and some are trying: Google's 2025 agreements with Indiana Michigan Power and the Tennessee Valley Authority curtail machine-learning workloads during system peaks [11]. The institutions offered no standard product, so their demand landed in the auction as an undifferentiated forecast, and every household in thirteen states got the bill. The evidence does not establish that the capacity market is the sole cause of inadequate entry. The argument is narrower: repeated price caps, high clearing prices, and limited new entry indicate that the existing mechanism is not reliably converting scarcity into a predictable investment signal. ### The absorption record Five times since 1978, federal regulators changed the rules of this industry, and five times the industry metabolized the change. PURPA created independent generators and was fought to a draw over avoided cost. Order 888 opened the transmission system and stopped at the substation [25]. Order 1000 invited competition into transmission planning and was answered in state legislatures with rights of first refusal. Order 2222 ordered the wholesale door open to distributed resources; the compliance calendar now stretches toward 2030. Order 2023 reformed the queue itself, and its implementation raised the cost of standing in line, thinning the independent pipelines it was meant to clear. The pattern is not that nothing changed. It is that process changed and incentives did not, so every process change was administered by parties paid to blunt it. This is what Failures 1 and 2 predict, run five times. Why would we do the same thing again, expecting a different outcome? **The counterfactual.** Suppose the settlement had continued past the substation in 2001: performance pay on the wires, a neutral administrator at the gate, access under published rules. Two decades of distribution capital would have faced a buy-or-build test before earning a return. The queue would have been engineered for thousands of applicants before two thousand gigawatts arrived to stand in it. Storage would have come to market against posted terms it could finance. The 2020s load wave would have landed on a functioning connection market, and the data centers would be customers in it, not defendants in a blame contest. The counterfactual proves timing, not magnitude; it cannot say what bills would be. What it can say is that every institution this program proposes had a working precedent by 2001, so the cost of the last two decades was a choice about incentives, not a limit of technology. ## The pattern underneath: institutions became the expensive input Step back from the five failures and one economic shift explains them all. For a century, electricity was expensive to produce and cheap to coordinate: the commodity dominated the bill, and the institutional overhead of one utility, one commission, and one annual rate case was rounding error. The cost curves inverted that relationship. Producing a marginal megawatt-hour has never been cheaper. While cheap generation is not the same thing as cheap delivered and reliable electricity, the claim throughout this series is that the gap between the two is now more institutional than physical. The coordination costs, five years of studies, decade-long compliance dockets, serial rate cases, and stakeholder processes with hundreds of parties, can rival the economic value of the production cost differences they are supposed to manage; a project can spend more calendar time and risk capital on permission than on construction. Economists since Coase have taught that institutions exist to economize on transaction costs, and that when relative prices shift this far, the efficient institutional boundary moves [20]. The grid's institutional boundary has moved far less than the economic boundary since 1935. The five failures above are what it looks like when transaction-cost-heavy institutions govern a transaction-cost-light technology, and the reforms in Paper III are, in this framing, boundary corrections: rules and prices replacing case-by-case discretion wherever discretion's coordination cost now exceeds its value. ## The strongest objections, answered directly A thesis this critical of incumbent institutions earns skeptical readers, and the four objections they raise most often deserve full answers. **"The queue is mostly speculative."** Largely true, and it strengthens the diagnosis. Developers file multiple queue positions because a position has been a cheap option on scarce, uncertain grid access; when the study process is slow and its cost allocations are unpredictable, buying several lottery tickets is rational. The speculation is the institution's product. FERC's Order 2023 already raised deposits and readiness requirements, and the headline number has begun shrinking without any easing of the underlying scarcity. And the argument survives heavy discounting: even at the historical completion rate of about 13 percent, the current queue implies on the order of 270 GW of eventually built capacity [1], several years of additions at recent build rates, waiting on procedure. One further caution belongs on the record rather than in a critic's hands: 549 GW already holds a draft or executed interconnection agreement, which is the furthest institutional milestone a project reaches before construction, but withdrawal rates stay above 40 percent even after that stage, so an agreement is a cleared gate rather than a commitment to build [1]. Texas holds queue volumes that are large too; the difference is how fast positions convert to steel. **"Connect-and-manage threatens reliability."** The record says otherwise, and the mechanism explains why. Interconnection studies protect against local overloads, which connect-and-manage handles by studying local effects and curtailing flows in operations; the developer, holding the curtailment risk, self-selects better sites. ERCOT has operated this way through nearly two decades of the country's fastest resource growth, Britain adopted connect-and-manage transmission access in 2010, and Australian networks connect rooftop fleets under real-time operating envelopes [6][16]. ERCOT's genuine reliability failure, Winter Storm Uri in 2021, traced to plant weatherization and fuel supply in the FERC-NERC inquiry, failures a five-year interconnection study does nothing to prevent [19]. The reliability question is real; the study queue is the wrong instrument for it, and Principle 5 in Paper III addresses the right one. **"Utilities need real capital investment."** Agreed, and the reform is capital-neutral. Storm hardening, wildfire mitigation, cyber defenses, and replacement of assets past design life are exactly the spending a totex framework funds, because totex removes the accounting preference rather than the money. What changes is the choice at the margin the current formula distorts: greenfield versus reconductoring, substation versus battery contract, build versus buy. The British networks invested heavily under RIIO; they were paid for delivering outputs with that investment instead of for the investment itself; Paper III presents the record. **"Why isn't the answer just public power?"** Municipal utilities do charge less. In 2024 the average residential bill was $123.78 at public power utilities against $139.42 at investor-owned utilities [22]. Cooperatives, which are also not-for-profit and also earn no return on rate base, averaged $149.18, mainly because they serve low-density rural territory. Cost follows structure and circumstance rather than ownership form. The municipal advantage itself comes largely from tax-exempt debt, exemption from income and property taxation, and statutory preference on federal hydropower at cost-based rates, which are transfers rather than efficiencies and do not scale, because municipalizing additional utilities creates no additional federal dams [22]. Ownership also leaves the binding constraint untouched, since a municipal utility inside PJM waits in the same interconnection queue and pays the same capacity charges, and on permission it is frequently worse: municipal utilities and cooperatives are exempt from state interconnection and net-metering rules in many states, so a restrictive distributed-energy policy faces no commission and no appeal [23]. The transition arithmetic compounds it, with roughly a dozen communities having municipalized in two decades, most attempts abandoned, and Boulder ending a ten-year, $28.7 million effort in 2020 without acquiring a system [24]. The deeper answer is that public power is evidence for this diagnosis. A utility that is not paid a return on invested capital does not exhibit the capital bias, which is exactly what Failure 1 claims, and it is why the non-wires examples in the case evidence above come disproportionately from carve-outs and public power. Sterling, Massachusetts deferred with a battery what an investor-owned utility needed a bespoke earnings mechanism to attempt. Ownership change is one way to escape the payment formula. Changing the payment formula is the general case: it applies to the three-quarters of load that investor-owned utilities serve, and public power can adopt it faster than anyone else, by board action and without a rate case. **"Distributed and variable resources aren't dispatchable like a gas plant."** Correct as stated. Capacity markets already discount every resource to its effective load-carrying capability, so a megawatt of solar counts as a fraction of a megawatt where the data say it should. The discounts move with evidence: PJM's accreditation of demand response rose from 69 percent to 92 percent between consecutive auctions once availability rules tightened and winter performance was counted properly [9]. Grid-scale batteries are among the most dispatchable assets on any system, responding in under a second, and portfolio diversity does the rest. The dispatchability objection is an argument for accurate accreditation inside the reforms, which Principle 5's obligation accounting provides. ## What would prove us wrong The claim in this paper is causal, which makes it testable. Six results would force a revision. **If queue durations fall substantially without interconnection reform**, the process was never the binding constraint, and the backlog was a transient response to a demand shock and never an institutional failure. **If distribution capital spending slows while cost-of-service ratemaking stays in place**, the capital bias is not what drives the spending, and the diagnosis in Failure 1 is wrong. **If states adopting total-expenditure regulation show no divergence in delivery-cost growth from comparable states**, the mechanism does not work in an American context, whatever the British record shows. **If system costs fall but the savings arrive by shifting cost onto inflexible or low-income customers**, the program has failed its distributional test, even with aggregate costs falling. **If large loads decline flexibility terms even when offered service years earlier**, the central trade in the reform program is not one they want, and the flexible-headroom estimates are academic. **If ERCOT's speed advantage disappears while it retains connect-and-manage**, the rule was not the cause of the difference, and Texas stops being evidence for anything here. ## What we do not know No one has operated a full distribution-level market at scale, and the engineering of grids dominated by inverter-based resources remains an active frontier, with grid-forming standards still maturing; South Australia's operating record and ERCOT's storage integration are encouraging but not conclusive [16]. Estimates of flexible-load headroom depend on assumptions about curtailment tolerance that hyperscalers have only begun to test in production [17]. Institutional overhauls have failure modes too, and California's 2000-01 crisis shows what a badly sequenced restructuring costs. The reform program in Paper III is sequenced with that history in view. Operating a reliable power system remains difficult, and nothing here suggests otherwise. What changed is the ranking: institutional friction has become the longest pole in the tent, the delay and cost that binds before the engineering does, and every year of Australian and Texan operating experience lengthens the gap. What is settled: the queue numbers, the auction results, the capital bias, and the direction of the inversion. Cheap supply is not returning to scarcity; even after levelized costs rose roughly 10 percent in Lazard's 2026 series, on higher capital costs, interest rates, and import tariffs, unsubsidized solar and wind remain the cheapest new-build generation [5]. The central open policy question is how much of today's connection scarcity is physical, how much is institutional, and how quickly institutional reform can reduce the latter without compromising the former. *Paper III states the five principles, evaluates the mechanisms under each with a stance and an evidence tier, names who wins and who loses, and lays out a 2027-2035 implementation path. The companion document What Success Looks Like describes ordinary operation in 2035, once the reforms hold.* --- ## Sources [1] Joseph Rand et al., *Queued Up: 2026 Edition*, Lawrence Berkeley National Laboratory (June 2026; 2,061 GW active at year-end 2025, ~8,200 projects, median interconnection-request-to-operation duration above five years; emp.lbl.gov/queues). [2] S&P Global Commodity Insights and trade press reporting (2024-26) on gas turbine order backlogs at GE Vernova, Siemens Energy, and Mitsubishi Power. [3] Utility Dive, "PJM capacity prices set another record with 22% jump" (July 2025); PJM Independent Market Monitor analyses. [4] PJM Inside Lines, "PJM Auction Procures 134,311 MW of Generation Resources" (July 22, 2025); Utility Dive coverage of DOE emergency orders (2025-26). [5] Lazard, *Levelized Cost of Energy+*, 2026 edition (utility-scale solar $40-98/MWh, average $69, against $359 in 2009, an 84 percent decline); BloombergNEF, *2025 Lithium-Ion Battery Price Survey*, December 2025 ($108/kWh average, 93 percent below 2010's ≈$1,474/kWh in real 2025 dollars; stationary-storage packs $70/kWh). [6] Tyler H. Norris, "Beyond FERC Order 2023: Considerations on Deep Interconnection Principle" (Nicholas Institute, Duke University, 2023). [7] FERC Order No. 1920, "Building for the Future Through Electric Regional Transmission Planning and Cost Allocation" (2024). [8] Emilia Chojkiewicz et al., "Accelerating transmission expansion by using advanced conductors in existing line corridors," *PNAS* (2024). [9] PJM, "2027/2028 Base Residual Auction Report" (December 2025). [10] PJM, "PJM Capacity Auction Procures 138,318 MW of Generation Resources" (July 14, 2026). [11] Google announcements of demand-response agreements with Indiana Michigan Power and TVA (2025); Utility Dive and Canary Media coverage. [12] Harvey Averch and Leland L. Johnson, "Behavior of the Firm Under Regulatory Constraint," *American Economic Review* 52:5 (1962). [13] George J. Stigler, "The Theory of Economic Regulation," *Bell Journal of Economics and Management Science* 2:1 (1971). [14] ProPublica and Ohio Capital Journal reporting on the FirstEnergy/HB6 scandal and the conviction of Speaker Larry Householder (2020-24). [15] FERC Order No. 2222 (2020) and subsequent RTO compliance dockets, with accepted or proposed implementation dates of November 2026 (ISO-NE), February 2028 (PJM), June 2029 (MISO), and Q2 2030 (SPP); CAISO implemented November 2024 and NYISO April 2024. [16] ARENA and AEMO, Project EDGE and Project Symphony reports; NERC guidance on inverter-based resources. [17] Tyler H. Norris et al., *Rethinking Load Growth* (Nicholas Institute, Duke University, 2025). [18] Consolidated Edison, Brooklyn-Queens Demand Management filings and NY PSC orders (Case 14-E-0302), with the program's net savings contested in contemporaneous analysis (Greentech Media, 2017); Arizona Public Service, Punkin Center battery deployment (2018) and subsequent NAATBatt presentation disclosing the 2019 standby and disconnection; Sandia National Laboratories (2017) economic analysis of the Sterling Municipal Light Department system, with Clean Energy Group project documentation. [19] FERC, NERC, and Regional Entity joint inquiry, *The February 2021 Cold Weather Outages in Texas and the South Central United States* (2021). [20] Ronald H. Coase, "The Nature of the Firm," *Economica* 4:16 (1937), pp. 386-405; Oliver E. Williamson, *The Economic Institutions of Capitalism* (Free Press, 1985). [21] RMI, "PJM's Speed to Power Problem and How to Fix It" (May 2026), documenting PJM's average application-to-operation timeline rising from under two years in 2008 to more than eight years in 2025. [22] American Public Power Association, 2024 average monthly residential bills by ownership type ($123.78 public power, $139.42 investor-owned, $149.18 cooperative), reported in trade coverage of APPA's affordability analysis; APPA materials on tax-exempt financing and federal hydropower preference; Cato Institute analysis of the tax and financing advantages of public power and the Power Marketing Administrations. [23] U.S. EPA, *Energy and Environment Guide to Action*, chapter on interconnection and net metering standards, noting that municipal and cooperative utilities are exempt from state rules in some states; DSIRE program records for Florida and Pennsylvania. [24] Brattle Group, *Electric Utility Municipalization: Key Statistics and Risk Considerations* (2025); Colorado Public Radio and Energy News Network reporting on Boulder's ten-year, $28.7 million effort and its conclusion in 2020; American Public Power Association statements on the number of successful municipalizations over two decades. [25] FERC, Order No. 888, Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services, 1996. [26] Clean Air Task Force, "A data-driven look at rising U.S. electricity costs and policy solutions" (March 2026), reporting distribution spending growth of about 160 percent and transmission growth of nearly threefold between 2003 and 2023, and attributing part of the pattern to planning processes that reward pre-emptive local capital spending over larger regional projects. [27] Edison Electric Institute, capital expenditure data for 2025 (roughly $207.9 billion of investor-owned utility capital spending, against about $139.8 billion in 2020; distribution approximately $66.5 billion, generation $62.4 billion, transmission $37 billion), as reported by POWER and Utility Dive; Lawrence Berkeley National Laboratory, *Disaggregating Future Retail Electricity Rate Growth* (2021), for the FERC Form 1 functionalized decomposition method. \pagebreak # Completing the Market ### Paper III: Five principles, the mechanisms we evaluated, who wins, who fights, and the road from 2027 to 2035 *Companion papers: I. How We Built Institutions for the Wrong Grid (history) and II. The Great Inversion (diagnosis).* --- **Contents.** [From diagnosis to design: why these five](#d-from-diagnosis-to-design-why-these-five) · [What this is not](#d-what-this-is-not) · [What we would not do](#d-what-we-would-not-do) · [Principles, mechanisms, and pathways](#d-principles-mechanisms-and-pathways) · [How to choose from the menu: five questions](#d-how-to-choose-from-the-menu-five-questions) · [The standard of proof for this proposal](#d-the-standard-of-proof-for-this-proposal) · [The five principles, and the mechanisms under each](#d-the-five-principles-and-the-mechanisms-under-each) · [What the program buys](#d-what-the-program-buys) · [Where the savings come from, and who pays less](#d-where-the-savings-come-from-and-who-pays-less) · [The consumer case: what this does to an electric bill](#d-the-consumer-case-what-this-does-to-an-electric-bill) · [What the reforms would do to capital formation](#d-what-the-reforms-would-do-to-capital-formation) · [Who wins, who loses, and why they will fight](#d-who-wins-who-loses-and-why-they-will-fight) · [Who should bear which risk](#d-who-should-bear-which-risk) · [Where this could go wrong](#d-where-this-could-go-wrong) · [Proven, demonstrated, and reasoned](#d-proven-demonstrated-and-reasoned) · [What we do not know yet](#d-what-we-do-not-know-yet) · [Revisit triggers and escalation criteria](#d-revisit-triggers-and-escalation-criteria) · [Why this window, and not five years ago or hence](#d-why-this-window-and-not-five-years-ago-or-hence) · [Implementation roadmap, 2027 to 2035](#d-implementation-roadmap-2027-to-2035) · [What success means](#d-what-success-means) · [The measures that prove it](#d-the-measures-that-prove-it) · [What America should copy, and from whom](#d-what-america-should-copy-and-from-whom) · [Transition fairness](#d-transition-fairness) · [Conclusion: completing the market](#d-conclusion-completing-the-market) Paper II established the problem: cheap supply, scarce connection. This paper specifies the fix. Every reform names a working precedent. The economics are quantified where the sources allow. The coalition analysis names who wins, who loses, and who can be flipped. And the roadmap sequences the reforms. ## From diagnosis to design: why these five The reforms are the minimal institutional changes required. Grant the diagnosis, five defects in how a monopoly platform is governed, and the design space narrows sharply. The platform's owner is paid for capital instead of outcomes; the minimal correction is to change what it is paid for, which is Principle 1, and nothing smaller (guidance, pilots, exhortation) has moved the behavior in thirty years of trying. The platform's owner referees access for its own competitors; the minimal correction is to move the refereeing, which is Principle 2, and the 1990s already proved at transmission voltage that disclosure rules without separation do not hold. The platform's scarcity is unpriced, so the resources that could relieve it cannot see it; the minimal correction is granular signals where scarcity actually binds, which is Principle 3. Access is rationed by discretionary process; the minimal correction is rules, which is Principle 4. And reliability costs are socialized away from the loads that create them through a construct that has stopped functioning; the minimal correction is to assign the obligation to its driver, which is Principle 5. A reader who accepts the diagnosis and rejects a reform owes an alternative correction to the same defect; a reader who finds the reforms excessive should identify which defect they would leave in place. ## What this is not This is not a plan to nationalize utilities, or to eliminate vertically integrated utilities where states prefer them, or to force retail choice on unwilling jurisdictions, or to mandate that anyone adopt distributed resources, or to subsidize particular technologies, or to relax a single reliability standard. Fuel-neutral means fuel-neutral: a gas peaker that clears an obligation contract and a battery that does so stand on identical footing. The objective: restore competitive markets wherever natural monopoly no longer exists, and regulate what remains a natural monopoly, the wires, better than cost-of-service regulation has managed. ## What we would not do We would not require a separated operator where an existing institution can credibly perform the access function. We would not require distribution nodal pricing where administrative procurement delivers the same value at lower transaction cost. We would not retire centralized resource adequacy before decentralized mechanisms demonstrate equivalent reliability at lower total cost. We would not force distributed resources into merchant exposure where contracts allocate the risk better. And we would not require utilities to build less; we would require them to demonstrate that building is the least-cost way to deliver the required outcome. ## Principles, mechanisms, and pathways This paper is organized in three layers. **Principles** are what must change. They are stated as economic functions, and they are not optional: a utility should earn on outcomes delivered, not on capital deployed; the party that owns the wires should not decide who may connect to them; where and when a resource operates should affect what it earns; access should follow published rules, not case-by-case permission; and incremental system costs should sit with those who create them. **Mechanisms** are how a jurisdiction might satisfy a principle, and they are deliberately contestable: agreeing with a principle while preferring a different mechanism is not an objection to this program. It is the conversation this program exists to facilitate. Totex, performance incentives, shared savings, distribution system operators, hosting-capacity publication, locational offers, operating envelopes, connect-and-manage, standardized connection pathways, large-load tariffs, and obligation-based adequacy are all mechanisms. Each section below states which we prefer, which we regard as viable, which we considered and set aside, and which we reject, with the evidence behind each judgment. **Pathways** are what a region actually does. ERCOT, PJM, a vertically integrated state, and an administered-value market like New York's are likely to reach the same functions through different institutions, because their market structures, resource mixes, and regulatory capacities differ. **Functional equivalence.** A long-term contract, a merchant market, a tolling agreement, a flexibility tariff, and a capacity obligation look very different legally and commercially. Yet each can perform the same underlying function: making a revenue stream predictable enough to finance, by moving volatility to a party better able to carry it. ERCOT tolling and New York's value stack are the clearest illustration. One is a private bilateral arrangement priced off a forward curve; the other is an administratively determined tariff with policy adders on top. The contract length is not the invariant, and neither is the market structure. The economic function is. The question is which mechanism performs the required function most efficiently in a given market. **Institutional inheritance.** Principles should build on institutions that already perform the relevant function effectively, and create new ones only where an existing institution cannot credibly perform it. **The adoption model.** Every principle climbs a ladder, and the gates are the same on all of them: start with transparency, climb only as far as evidence justifies, and treat stopping early as an answer instead of a failure. The rungs differ by which side of the program's objective a principle sits on: market or monopoly. The market-side principles, 3 through 5, climb toward price formation: transparency, then administrative signals, then competitive procurement, then contracted markets, then real-time prices. The monopoly-side principles, 1 and 2, climb toward accountability: transparency, then conduct rules and incentive adders, then output-based allowances and ringfenced administration, then yardstick comparison and structural separation where the escalation criteria trip. The escalation criteria later in this paper specify what justifies each next rung on both. **What the program actually reallocates.** Underneath the principles sit four reallocations, and every mechanism on every menu is one of them: information (who knows what), decision rights (who decides), risk (who bears uncertainty), and rewards (who gets paid). Cost-of-service regulation concentrated all four in one institution because scarcity of capital and of generation once justified it. The inversion of the cost structure is what un-justifies it, and each principle moves one or more of the four to where the inverted economics say it belongs. **The language convention.** This paper uses its modal verbs deliberately. The principles are stated as *must*: they are the argument. A jurisdiction that rejects one is disagreeing with the program. The preferred mechanisms are stated as *should*: they carry our stance and the evidence behind it, and the sections below argue for them at length. The alternatives are stated as *could*: viable routes to the same function, ranked and reasoned, that a jurisdiction whose institutions fit them better is invited to take. ## How to choose from the menu: five questions Before adopting any mechanism in this paper, a jurisdiction should be able to answer five questions. First, what economic function is missing? Second, can an institution you already have perform it? The burden of proof sits with creating something new. Third, who can bear the associated risk most efficiently? The risk-allocation table later in this paper is the worksheet. Fourth, is there enough market depth, telemetry, and participation to justify a more sophisticated mechanism than the simplest one that works? The maturity ladder provides the sequence. Fifth, what evidence would cause you to change course? A mechanism adopted with a revisit trigger is an experiment, and this program is built to be run as a series of experiments. A stakeholder who works through these five questions and lands on a different mechanism than we prefer has used this framework exactly as intended. ## The standard of proof for this proposal We do not need to prove that every queued project is viable. We do not need to prove that every dollar of utility capital spending is unnecessary. We do not need to prove that every physical constraint can be solved with markets. We do need to show that existing institutions systematically make some otherwise economic solutions slower, more expensive, or harder to finance than they need to be. That is the proposition the five principles are designed to test. **The framework at a glance.** | Function | Preferred mechanism | Viable alternatives | Evidence tier | Trigger to escalate or change | |---|---|---|---|---| | Utility neutrality between building and buying | Totex revenue caps with yardstick benchmarking | Performance incentive mechanisms; output-based allowances | Proven at national scale in Britain; one US state | Benchmark comparability fails, or financing health breaks at review | | Independent access administration | Ringfenced DSO function, separating where conflicts persist | Independent operator; state agency; code of conduct | Demonstrated in Britain since 2023; transitional forms widespread | Affiliate complaints rise, procurement concentrates, or queue benchmarks fail twice running | | Locational and temporal value | Posted locational offers with operating envelopes and default dynamic rates | Administered value stacks; contracted flexibility | Demonstrated at population scale in South Australia; components tested for decades | Administrative offers visibly misprice, and metering depth supports price formation | | Access by rule | Automated screening for small resources; connect-and-manage for bulk | Cluster studies; flexible-connection agreements | Proven in ERCOT across nearly two decades; screening software operating | Curtailment or reliability violations exceed published thresholds | | Incremental reliability cost | Large-load tariffs phasing toward bilateral obligations | Centralized procurement retained as backstop | Emerging: state tariffs, France's obligation, contracted hyperscaler flexibility | Obligation coverage fails the reliability-and-cost test, and the auction remains | The sections below carry the full menus, stances, and revisit triggers. ## The five principles, and the mechanisms under each Each section opens with the principle, followed by the menu of mechanisms we evaluated and our stance and evidence tier for each. ### Principle 1. Pay for performance *A utility should earn on outcomes delivered, not on capital deployed · State jurisdiction* Cost-of-service pays a return on approved capital and passes most operating costs through at zero margin, so a wires solution and a service solution are never compared on one financial footing. The principle sets no revenue level; it changes what revenue attaches to. | Mechanism | Our stance | Why | Evidence | |---|---|---|---| | Total-expenditure allowance with yardstick benchmarking | **Preferred** | Removes the incentive for building over buying. | Operating evidence: Britain since 2013; Hawaii since 2020 | | Performance incentives layered on cost-of-service | **Viable** | Workable where totex is unavailable; pays a bonus against the bias it leaves intact. | Operating evidence: PIMs in many US states | | Shared savings for non-wires alternatives alone | **Viable** | A narrow entry point; fixes one decision at a time, not the formula behind all of them. | Narrower application: BQDM, with contested accounting | | Competitive procurement thresholds for distribution capital | **De-prioritized** | Threshold rules get beaten by splitting programs into sub-threshold pieces. | Partial analogue: Order 1000's record | | Reducing the allowed return on equity | **Rejected** | Does not change the bias; raises financing cost and changes no build-or-buy decision. | — | Replace cost-of-service ratemaking with performance-based regulation on the model of Britain's RIIO framework and Hawaii's 2020 performance-based regulation order [1][2]. Three design elements carry the weight. A total expense, or "totex", allowance erases the accounting line between capital and operating spending, so the utility earns the same whether it builds a substation or contracts with a battery fleet; this disarms the Averch-Johnson capital bias at its source. Multi-year revenue caps tie earnings to measured outputs such as interconnection speed and hosting capacity created. Yardstick benchmarking sets each utility's allowance against the measured performance of comparable utilities elsewhere, which severs the link between what a firm tells its regulator and what it earns; Shleifer worked out the theory in 1985, and it remains the most capture-resistant instrument in the toolkit [3]. This principle comes first because its preferred mechanism changes the utility's economic payoff before the program asks it to relinquish control of access, data, or procurement. The British record is the evidence that the financial model is viable. The record: | | Under RIIO (2013 onward) | Source | |---|---|---| | Network credit quality | Investment-grade maintained throughout | Ofgem, rating agencies [1] | | RIIO-1 realized returns | ≈9-10% real on regulated equity, against a ≈5-6% UK-company average | National Audit Office (2020) [1] | | Ofgem's own assessment | Returns ran "at the high end of our expectations"; RIIO-2 promised to be "tougher for investors" | Ofgem [1] | | Reliability | Interruption targets met or beaten across RIIO-1 | Ofgem RIIO-ED1 reviews [1] | | Investment levels | Sustained; totex funded hardening and replacement alongside procurement of alternatives | Ofgem [1] | | Regulator's chief complaint | Companies earning too much, prompting tighter RIIO-2 calibration: totex sharing rates cut from 44-64% to 33-50%, and allowed equity set at 4.55% CPIH-real at 60% notional gearing for GD2/T2 (post-CMA, which removed Ofgem's 25bp outperformance wedge); ED2 later finalized at 5.23% | Ofgem RIIO-2 and ED2 final determinations; CMA (2021) [1] | Read that last row twice, because it is the whole political argument to utilities: the documented failure mode of performance regulation is utility over-earning. The American evidence points the same way at smaller scale. New York built a bespoke earnings mechanism so Consolidated Edison could profit from deferring roughly $1 billion of Brooklyn-Queens substation and grid investment with about $200 million of demand-side and distributed resources, and the deferral happened, though the net savings have been fairly contested [20]. Under totex, that outcome stops requiring a bespoke mechanism. Under cost-of-service, it stays an exception someone must engineer. That is why the examples come disproportionately from carve-outs and public power: Arizona Public Service's Punkin Center battery, 2 MW deferring a roughly 20-mile line rebuild and later retired from service, and Sterling, Massachusetts's storage savings of about $400,000 a year, analyzed by Sandia [20]. ### How much does the capital bias cost? There are three tiers. The demonstrated tier is the documented cases. Brooklyn-Queens deferred a substation with a portfolio of demand-side and distributed resources, under accounting both sides still contest [20]. Reconductoring existing corridors with advanced conductors roughly doubles capacity at about half the cost of new construction [11], and DOE lent AEP Texas up to $3.26 billion to do it across more than 2,800 miles [23]. Britain's totex networks out-earned their allowances persistently enough that the national auditor called the returns too generous [1]. The plausible tier is the trend: distribution spending up about 160 percent over two decades while congestion stayed high, a pattern consistent with the bias and not yet a measurement of it. The third tier is the spending that survives any incentive system: storm hardening, wildfire mitigation, asset replacement, and load-driven expansion, which totex funds in full. The demonstrated tier is thin, and the program is built to thicken it. The yardstick comparisons and alternatives-analysis requirements in the first hundred days produce, jurisdiction by jurisdiction, the decision-level record this question deserves. Until that record exists, Principle 1 rests on the mechanism, the trend, and the documented cases. **The regulatory architecture.** Totex removes one distortion; it does not eliminate regulation. The framework runs from a multi-year baseline through exogenous growth adjustments, output measures, peer benchmarking, quality and reliability incentives, and an extraordinary-event mechanism to a periodic reset. These should be written into the order: - a multi-year but resettable revenue cap - a conservative sharing factor, set low at the outset - audited performance metrics with standardized definitions - an explicit financing-parameter reopener - full funding for mandated resilience and hardening work - independent benchmarking against comparable utilities - no reward available for degraded reliability **Four ways to serve the same constraint.** The following are four options that a planner might consider for a specific constraint on the grid: | Option | Approximate cost | Service provided | Utility incentive today | Under the proposed model | |---|---|---|---|---| | Substation | ~$40M | Permanent network capacity | Capital recovery | Competes with alternatives | | Reconductoring | Lower than greenfield where feasible | Network capacity | Smaller capital return | Competes on total cost | | Battery contract | ~$2M/year | Temporary peak and deferral service | Limited direct earnings | Eligible for shared savings | | DER aggregation | Variable | Flexibility and peak reduction | Limited direct earnings | Procured against verified value | **Totex alone creates an unintended consequence.** Under cost-of-service, a utility is roughly indifferent to socializing a network upgrade for an interconnecting customer, because the asset enters rate base and earns a return either way. But under a total-expenditure revenue cap a socialized upgrade consumes allowance the utility could have spent elsewhere, while the same cost assigned directly to the interconnecting customer consumes none. Left unaddressed this would create a quiet new incentive to push network upgrade costs onto energy developers. Three provisions handle it. The allowance baseline is set to include the utility's historical shared network upgrade spending, and is adjusted downward by any amount reassigned to customers, so that reassignment earns the utility nothing. Cost allocation rules between shared network upgrades and interconnection facilities are fixed as of the effective date and change only in a separate proceeding on an evidentiary showing about cost causation, never quietly inside a rate design filing. And interconnection cost assigned per megawatt connected is reported annually by voltage and project size band, with a review triggered if it rises against the pre-reform baseline or against peer utilities. The last is the cheapest of the three and the most important, because it makes the problem visible before it becomes entrenched. ### Principle 2. Separate the referee *The party that owns the wires should not decide who may connect to them · State jurisdiction* The wires owner today runs the queue, holds the hosting data, and profits from the capital alternative to whatever is asking to connect: a referee with a stake in the score. Under this principle, engineering duties stay with the engineer; what moves is the access decision. | Mechanism | Our stance | Why | Evidence | |---|---|---|---| | Independent distribution system operator | **Preferred (where conflict is material)** | Fullest separation of access, data, and flexibility procurement from network ownership. | Narrower application: UK DSO transition | | Ringfenced affiliate under a code of conduct | **Preferred (as transition)** | With published conditions under which full separation becomes mandatory. | Narrower application | | Extension of an existing ISO or RTO downward | **Viable** | Borrows governance and systems that already exist; suits states inside organized markets. | Operating evidence: at transmission voltage | | State agency, or a competitively rebid contracted operator | **Viable** | Fits states that will not staff a standing institution; the least discussed option and often the best fit. | Partial analogue | | Divestiture of wires ownership | **Rejected** | A decade-long fight, and no evidence that ownership rather than access administration is what binds. | — | Move interconnection processing, hosting-capacity publication, operating-envelope calculation, flexibility procurement, and neutral data access out of the wires business and into an independent or strictly ringfenced Distribution System Operator. The wires utility keeps the poles, the trucks, and the storm response, and loses the gatekeeper's chair. Britain has required functional separation of DSO roles from the wires business since RIIO-ED2 took effect in April 2023, through licence obligations and published DSO baseline expectations, with signed DNO-DSO separation arrangements on the record, and it separated its national system operator outright when NESO was established in 2024 [4]; the De Martini-Kristov framework specified the American version a decade ago [5]. **Governance.** The DSO should be independent in its access functions and subject to transparent governance, with the wires company retaining physical network ownership and builder-of-record status. A ringfenced affiliate is acceptable as a transition where full independence is not immediately feasible, but the rules should identify the conditions under which separation becomes mandatory. Engineering limits stay with the engineer, and the wires company keeps every technical responsibility that connection physically requires; what moves is the access decision, wherever the party deciding has a commercial stake in the answer. **The split of responsibilities.** DSO: interconnection administration, hosting-capacity maps, operating envelopes, flexibility procurement, access data, queue metrics, and standardized connection offers. Utility: wires ownership, construction, maintenance, emergency response, physical network operations, and the reliability obligations assigned to it by tariff. **Who becomes the operator is a real question and it has five answers.** A utility affiliate under a code of conduct is the lightest option and the least protective, workable where the conflict is mild and the data mandates are strong. An independent distribution system operator is the fullest separation and the most expensive to stand up. An extension of the existing ISO or RTO borrows governance and systems that already exist, and suits states already inside an organized market. A state agency puts the function under direct public control, which some states will prefer and others will not staff adequately. And a contracted operator, selected competitively and periodically rebid, is the option least discussed and probably the best fit for smaller states that cannot justify a standing institution. Britain is the worked example of choosing differently at different levels, ringfencing at distribution under licence conditions in 2023 and separating outright at the national system operator in 2024. That pairing is the useful template: ringfence at distribution first, full independence where the conflict warrants it. This is the distribution-level completion of what Order 888 did at transmission voltage, and the reasoning is identical: the owner of a bottleneck cannot referee access for its own competitors. ### Principle 3. Pay resources for what they do for the grid *Where and when a resource operates should affect what it earns · State jurisdiction* Retail prices carry almost no information about when or where the grid is strained, so flexibility that could relieve a constraint has nothing to respond to. The signal must be real; the revenue can stay hedged, contracted, or administered. This principle does two things: it tells a resource what the grid needs, and it defines what the grid pays. | Mechanism | Our stance | Why | Evidence | |---|---|---|---| | Published hosting capacity and avoided-cost values | **Preferred (step 1)** | The prerequisite for everything else, orderable as a reporting requirement. | Operating evidence: state hosting-capacity mandates | | Standing locational offers and operating envelopes | **Preferred (step 2)** | Location and timing reach the resource without building a market first. | Operating evidence: GB flexibility procurement; Australian dynamic envelopes | | Time-varying default rates with a hedged alternative | **Preferred (step 3)** | Two decades of US rate-design evidence, with the equity design attached. | Operating evidence | | Administratively set successor tariffs | **Viable (bridge)** | Workable while markets mature; New York's nine years and its continuous adders are the caution. | Narrower application: VDER since 2017 | | Distribution-level locational marginal pricing | **Deferred** | Transaction costs likely exceed benefit at current volumes; revisit when metering coverage and participation justify it. | Partial analogue: nodal transmission markets | **Signaling scarcity.** Full nodal pricing across millions of meters is the wrong first step, for reasons that would hold even if computation were free. A distribution node is thin: where one battery sits on one feeder, a clearing price is a bilateral negotiation wearing an auction costume, and the mitigation rules needed to police it would end up administering the price anyway. And a nodal price would move with switching, reconfiguration, and maintenance decisions made by the wires owner, who under current structure is also the competition; full price formation before Principle 2 hands the gatekeeper a price-setting lever. The functional content of nodal pricing arrives instead through three instruments. Dynamic default rates tell households **when**, with hedged flat products freely available, following two decades of evidence that the efficiency gains are real and the distributional effects manageable with design [6]. Default is not mandatory, and the equity design is part of the reform: a hedged flat product remains available to any customer who wants a predictable bill, transition years carry bill protection, low-income rates are targeted rather than averaged away, and the automation that captures the value is a utility or third-party obligation, not a household's homework. The status quo is not neutral on this question, since a flat volumetric rate already transfers money from customers who cannot shift usage to those who can. Posted locational offers tell third parties **where**: wherever the utility's planning model shows a deferral value on a specific feeder, that dollar figure per kilowatt-year becomes a standing, technology-neutral offer to any battery, solar array, or flexible load at that location. Operating envelopes tell every connected device **how much**, in real time, replacing static worst-case export caps. Flexible export limits are now the default connection standard for new solar in South Australia, mandatory for essentially all new exporting systems since July 2023 and offered statewide including on rural SWER lines, with other Australian networks implementing through 2031 [7]. Envelopes ration scarcity by quantity instead of price, which is what makes them tractable for small devices run through aggregators. Explicit distribution-level pricing can come later, on that substrate, for large participants. **The implementation burden sits at distribution, not at the seams.** The wholesale side of this program is the better-understood half. The harder engineering is local and unglamorous: secondary networks in dense urban cores where reverse flow was never contemplated, neighborhood transformers sized on diversified load assumptions that behind-the-meter solar and EV charging both violate, feeder-level congestion that appears and clears within hours, voltage regulation on long radial circuits where a few hundred kilowatts at the end of the line moves the whole profile, protection schemes designed for one-way current, and hosting capacity models that go stale and need periodic revalidation against measured data. None of this argues against the reform. The metering, telemetry, and modeling investment in the cost column is real, and envelopes are what make the rest tractable. A state adopting this should expect its first two years to be spent on data quality prior to price formation. **Compensating contribution.** The principle is neutral about the instrument: merchant exposure, a contract, a tariff, or a hybrid can each satisfy it, and the maturity ladder says when each is available. What follows is the preferred design where a tariff is the chosen instrument. What a resource earns has two layers, and keeping them separate matters most for community solar. Underneath sits a grid-services value stack: energy, capacity, and locational value, set by formula, updated on a published schedule, technology-neutral, and identical for a rooftop array, a community solar project, and a standalone battery at the same location. On top sits any state policy adder, explicitly identified, separately justified, and set for a duration the state publishes forward. Net metering on a single premise is a compensation mechanism, and pricing it accurately is straightforward. A community solar bill credit is something else. It is the delivery vehicle for a program a state adopted deliberately, usually with low-income carve-outs, renter access requirements, and siting preferences attached, and the bill credit is the instrument because a subscriber's bill is the only channel that reaches a residential customer who owns no roof and no meter of their own. Replacing that credit with a value stack alone does not merely reprice the resource; it removes the mechanism for a policy the state separately decided to have. Two layers is better for developers, because the grid-services layer becomes financeable on a formula while the policy layer carries the political risk that was previously smeared across the whole payment. States should continue to set adders, eligibility rules, low-income requirements, and capacity blocks case by case, as they do now. What this reform contributes underneath is the formula discipline and the non-retroactivity guarantee, which matter more to the cost of capital. **Signals that move, revenue that does not.** Spot markets discover value, contracts transfer risk, and neither function requires the other to disappear. Dynamic value does not require volatile project revenue. The objection a developer or a lender raises first is that these two goals are in tension, and the two working examples appear to prove it. ERCOT paid storage through volatile merchant energy spreads, storage arrived in volume, and the volatility that justified the investment was competed away by the investment itself. New York set administered values to give projects stability, and those values drift from the system conditions they were meant to represent. One approach produces accurate signals that cannot be financed; the other produces financeable revenue that stops meaning anything. Something appears to have to give. The premise is wrong, and this reform’s design principle rejects it. A compensation regime does two separate jobs: it sets the **level** of revenue, which determines whether a project can be built, and it shapes the **dispatch incentive**, which determines whether the asset does anything useful once it exists. Bundling those into a single instrument is what forces the choice. Separated, a battery operates against live locational and hourly signals while its revenue rides on instruments layered above them. Its decision at six in the evening is still driven by the actual spread; its lender is simply not underwriting that spread. The volatility does not vanish, it moves, from a single-asset project company financed with project debt, which is the worst available holder of spread risk, to a counterparty with a portfolio and a hedge book, which carries it far more cheaply. Three further properties follow that distinguish this design from both cautionary examples. *Different value streams saturate differently, so a stack is more durable than a price.* Energy arbitrage saturates quickly, because every battery competes into the same spread at the same moment. Ancillary services saturate faster still. Capacity accredits downward as penetration rises, which is at least a transparent and predictable form of saturation. Network deferral behaves differently in kind: it is a procurement against a bounded need at a named location. It closes when the need is met and reopens when new constraints appear, rather than being competed to zero by everyone at once. A resource earning across all three has a materially more durable business than one earning from the spread alone. *Someone must have money at stake in the accuracy of a locational value, or it will drift.* This is the structural failure in New York. A utility administering a value stack as a tariff obligation is indifferent to whether the number is right: set too high, the cost flows to ratepayers; set too low, the resource does not appear and the utility builds the wires and earns on them instead. Under Principle 1's shared savings the utility keeps a defined slice of the difference between the deferral and the wires solution, which exposes it in both directions. Overstate the offer and it consumes its own savings share; understate it and nothing bids and it has to build. The value becomes self-correcting because a party is finally exposed to getting it wrong. *Contract duration and price discovery are different questions.* The problem in New York is not that its instruments are long-dated but that its prices are administratively set and then persist. A competitively procured ten-year deferral contract is simultaneously long enough to finance and discovered rather than assumed, and re-tendering new needs at current values lets the marginal price track the system while inframarginal revenue stays stable. Existing contracts should be durable. Prices for new needs should not be. **Customer protection.** No household should be required to become an active electricity trader. Dynamic rates should be paired with automation, a predictable hedged alternative, transition-year bill protection, and targeted assistance. **The incidence design.** Two customers make the test concrete. Customer A cannot shift load: electric resistance heat, no storage, home at peak. Customer B owns the flexible bundle: a vehicle that charges at 2 a.m., a battery, a thermostat that pre-cools. Today's flat rate already moves money from A to B, because both pay the average while B imposes less than it. Naked dynamic pricing would raise A's bill at every peak A cannot avoid, the outcome this program prohibits by design. The default that ships here gives B the dynamic rate while A keeps a hedged flat product priced off the utility's own portfolio cost, so A's exposure holds while B's contribution to peak falls. The fourth layer, targeted low-income rates with transition bill protection, sits under the hedge for the customers who need both. The dollar arithmetic is jurisdiction-specific, which is why the incidence study is commissioned alongside the first performance-regulation docket; the design commitment is that no rate default moves risk onto the customer least able to carry it. **Anti-gaming.** Locational offers and value-stack components should be published under standardized formulas, so a resource owner cannot negotiate individually with the network operator for preferential treatment. **Three design rules keep the stack financeable.** New York's Value of Distributed Energy Resources is the closest working precedent for what is proposed here [27], and it is instructive in both directions: measured against merchant wholesale exposure it has delivered higher value and lower uncertainty, and measured against retail net metering it pays less in most cases. Its base stack has also required a continuous succession of adders since 2017, from the Market Transition Credit to the Community Credit to the Community Adder. *Make the energy component hedgeable at the developer's election.* New York's stack finances on its most fixed element, an environmental value paid per kWh and fixed for twenty-five years, while its hourly energy price and monthly capacity value are discounted heavily by lenders. The lesson is that a formula is not the same as a financeable revenue. The energy layer should therefore be available either as a floating price or as a multi-year fixed strip or contract for differences, priced off the same formula, at the developer's option. *Match component terms to asset life, or publish the rollover.* New York's locational component runs ten years against a twenty-five year asset, and diligence reviews report that projecting revenue past the expiry of the locational and demand components is the first modeling problem practitioners raise. A locational offer should either run for the life of the asset or state its renewal mechanics at the outset, because an undefined terminal value will be valued at zero by a lender. *Hold the design to a complexity budget.* New York's stack was created to simplify the economics of small projects and produced a market that specialist advisors describe as among the most complex in the country for developers and investors, with siting now requiring dispatch modeling and proprietary mapping. Complexity of that order is not neutral; it is a barrier to entry that favors large developers and screens out small ones, which for community solar means screening out precisely the local sponsors the programs were designed to enable. A developer should be able to compute expected compensation for a candidate site, unaided, from published data, in under an hour. Any component that cannot survive that test belongs in a procurement rather than in a tariff. **Non-retroactivity for tariffs and subscriber contracts.** A community solar project that has sold twenty-year bill credits to several hundred residential subscribers cannot pass a mid-stream compensation change through to them, because the savings guarantee is the product. Protecting the tariff while leaving signed subscriptions exposed would break portfolios the reform otherwise helps. California's AB 942 is the live example: as introduced it would have terminated legacy terms after ten years and on home sale, and the home-sale provision was struck only after unusually broad opposition. The rule here should be that compensation terms in executed subscriber agreements survive a transition for their stated term, and new structures apply to new projects and new subscriptions. ### Principle 4. Connect by rule *Access should follow published rules, not case-by-case permission · State and FERC jurisdiction* Serial, project-specific study made sense when a handful of large plants connected each year; it cannot clear two thousand gigawatts of applicants. Published limits stay engineering-grade, and constrained connection replaces exclusion, inside limits the operator can enforce. | Mechanism | Our stance | Why | Evidence | |---|---|---|---| | Standardized pathway against published operating limits | **Preferred** | Screenable, envelope-bounded, below the reliability screen, and reversible. | Operating evidence | | Connect-and-manage where operating rules support it | **Preferred** | Uses existing capacity while the system learns where permanent expansion is justified. | Operating evidence: ERCOT; GB; entering the organized markets | | Reconductor-first portfolio showing | **Preferred** | Applied to a rolling portfolio rather than project-by-project, with no categorical exemption. | Narrower application | | Cluster studies with readiness gates | **Adopted (2023)** | FERC Order 2023 did this; necessary, and not sufficient on its own. | Operating evidence | | Firm-access auctions and capacity-rights trading | **De-prioritized** | Adds a market layer before the data layer exists. | Partial analogue | | Unrestricted connection without an operating envelope | **Rejected** | The caricature opponents attack, and unsafe in fact. | — | Invert the default everywhere. For small resources, provide a standardized connection pathway for projects that satisfy published technical operating limits, screened by software in minutes, the interconnection analog of automated permitting [8]. For bulk generation and large loads, require each RTO or ISO to offer a connect-and-manage pathway with defined study clocks, published curtailment rules, and transparent congestion data. Connect-and-manage is a utilization strategy, not a substitute for planning. Recurring congestion should trigger a comparison between continued curtailment and permanent network investment. The preferred path has four components. **Small resources** connect against published operating envelopes. **Bulk generation** gets a connect-and-manage pathway where technically feasible. **Transmission** requires a reconductor-first portfolio showing before major greenfield build. **Large loads** get a fast-track tariff in exchange for standardized, verifiable flexibility. The size threshold for the standardized pathway belongs to the states. The binding constraint is feeder capacity, and five megawatts on a rural single-phase line is a larger event than fifteen on an urban express feeder, so any fixed figure encodes an assumption about grid architecture that does not hold across fifty states. What a national framework can usefully supply is the test. The standardized pathway should be available wherever four conditions hold: the interconnection question is **screenable**, answerable from published rules against published data without engineering judgment; the resource is **bounded by an operating envelope**, so the worst case is curtailment rather than overload; it sits **below the local reliability screen**, small enough against feeder minimum load and protection settings that it cannot create a condition requiring bespoke study; and the connection is **reversible**, curtailable or disconnectable on operator command with verified telemetry, so errors can be corrected in operations. **Open access operates within transparent engineering limits.** The limits are real and they are specific: voltage regulation on long radial circuits, protection coordination and fault current contribution, anti-islanding and inverter interoperability, cybersecurity for any device the operator can dispatch, and thermal hosting capacity on the conductor and the transformer. What changes is that those limits are published, computed the same way for every applicant, and appealable against a standard. Contrast this with the output of a study whose assumptions the applicant never sees. **The access ladder.** Connect by rule where the incremental reliability risk can be bounded, monitored, and economically compensated. The operating hierarchy: connect without restriction where headroom is demonstrated; connect inside an operating envelope where limits bind sometimes; connect with compensated curtailment where they bind often; reinforce the network where recurring curtailment costs more than the upgrade; deny only where none of these meets the reliability standard at acceptable cost. Denial becomes the documented residual of a priced sequence instead of the default output of a discretionary study. One procedural requirement. The state must publish its threshold, the basis for it, and a fixed schedule for reviewing it against measured outcomes. A state whose envelope deployment matures and whose screens keep passing should be raising its threshold over time, and a published review cycle is what turns that from an advocacy campaign into an administrative routine. At the bulk level, connect-and-manage becomes the national standard for generation and large loads alike; ERCOT has run the experiment at scale for years, and PJM's 2026 move toward connect-and-manage for large loads concedes the point [9][10]. The transmission network itself gets held to the same speed standard: enforced Order 1920 planning, minimum interregional transfer capability, and a reconductor-first requirement, under which a transmission owner must show why advanced conductors or grid-enhancing technologies on the existing corridor cannot deliver the capacity before proposing greenfield construction [11][12]. The evidence base is a peer-reviewed national assessment plus field deployments, such as AEP's Lower Rio Grande Valley project, which reconductored 240 energized line-miles of 345 kV on existing structures, roughly doubling capacity and finishing eight months early [11][21]. The approach is now being financed at federal scale: in July 2026 the Department of Energy closed a loan of up to $3.26 billion to AEP Texas to rebuild, reconductor, or build more than 2,800 miles of transmission, targeting a 100 percent increase in carrying capacity [23]. The qualifier: gains depend on conductor choice, thermal and structural limits, and the specific constraint, which is why the requirement is a showing rather than a mandate; where reconductoring cannot deliver, the showing says so and greenfield proceeds. **Designing against the workaround.** Order 1000 is the cautionary precedent, and it is close enough to this reform to be uncomfortable. FERC removed the federal right of first refusal in 2011 to open transmission to competition, and roughly 2 to 3 percent of transmission investment has since gone through competitive solicitation, meaning about 98 percent of ISO and RTO transmission investment is still made outside a competitive process [25]. The gap is not small: projects outside competition ran roughly 34 percent above their initial cost estimates, while competitive winning bids came in about 40 percent below, usually with cost caps attached [25]. New England shows the mechanism plainly. Transmission owners identify "asset condition" projects unilaterally, outside the regional planning process ISO-NE runs, and those projects are nonetheless cost-allocated across the region exactly like the projects ISO-NE selects. They grew from $58 million when tracking began in 2016 to more than $2.787 billion by early 2023, with annual spending rising eightfold to nearly $800 million and several billion more expected, and no asset condition project has ever been modified or rejected by the reviewing committee [26]. The Asset Condition Reviewer created in response to that criticism has no authority to modify or reject anything. Meanwhile roughly ten states legislated rights of first refusal back into place. The lesson is specific. Rules that police categories are defeated by recategorization, and rules that police dollar thresholds are defeated by splitting a program into sub-threshold pieces. A reconductor-first showing is a category-based rule and would be gamed the same way unless it is built against that history. Four provisions do the work: apply the showing to a rolling twelve-month portfolio of investment on a corridor or substation rather than to individual projects, so splitting gains nothing; permit no categorical exemption for asset condition, local reliability, or maintenance, since those are the categories that absorbed the last reform; give the reviewer authority to reject and to require an alternative rather than merely to comment; and publish the full project list with costs and justifications in machine-readable form, so third parties can detect aggregation patterns the reviewer misses. The deeper protection is Principle 1, and this is the argument for the sequence. Order 1000 tried to police the incumbent's behavior while leaving the incumbent's payoff intact, which meant every dollar of effort spent on recategorization still earned its return. Under a total-expenditure framework the utility earns the same whether it builds or procures, so recategorizing a project yields nothing, and under yardstick benchmarking the allowance is set from what comparable utilities achieve rather than from how this utility describes its own work. A firm can recategorize its projects. It cannot recategorize the benchmark. For hyperscale loads, formalize the trade they are already improvising: fast-track connection and bring-your-own-capacity, in exchange for verified curtailability during the top 50 to 100 system hours, the arrangement Google reached with Indiana Michigan Power and TVA in 2025 [13]. The access principle is deliberately technology-neutral. A rooftop battery, a wind cluster, a fuel-cell installation behind a data-center fence, and eventually a small modular reactor on a campus belong to one coalition. ### Principle 5. Make new load fund reliability *Incremental system costs should sit with those who create them · State tariff first, FERC for the obligation construct* One new campus can require as much peak capacity as a small city, while the bill for standing that capacity up spreads across every household in the region. Costs should be reasonably attributed, and socialized transparently where necessary. | Mechanism | Our stance | Why | Evidence | |---|---|---|---| | Large-load tariff assigning incremental cost | **Preferred (first)** | Moves in 12 to 18 months at a state commission, needs no new authority, and has a direct attributable effect. | Operating evidence: state large-load tariffs, spreading since 2025 | | Obligation-based adequacy, phased | **Preferred (staged)** | Four stages, with the centralized auction as residual backstop until coverage is demonstrated. | Partial analogue: LSE obligation constructs | | Longer forward procurement in the centralized auction | **Viable (partial)** | Helps financeability while keeping the commodity framing that causes the problem; PJM itself proposes it. | Operating evidence: forward capacity auctions | | Bring-your-own-generation mandates for large loads | **De-prioritized** | Forecloses cheaper system solutions and invites bypass. | Partial analogue | | Continued socialization of incremental capacity cost | **Rejected** | On PJM's own numbers: $2.2B to $16.4B a year, spread across 67 million people. | — | New large loads and load-serving entities demonstrate forward physical or contracted coverage of the incremental reliability capability attributable to their load, under standardized products and transparent accreditation rules, against a transparent penalty price. Coverage means contracts with generation, storage, or verified demand flexibility. The existing centralized mechanism becomes a residual backstop while bilateral obligations mature, and any transition must preserve reliability requirements and honor existing commitments. The objective is not to make every customer procure its own generation. It is to make the incremental reliability requirement attributable to new load explicit, financeable, and nondiscriminatory. The principle carries its own corollary: where costs cannot reasonably be attributed, they should be socialized transparently, which is a discipline on the program as much as on the incumbents. France's capacity obligation provides the precedent [14]. **Three kinds of cost.** Incremental cost is caused by the load and would not occur without it: the capacity its demand adds to the peak, the feeder built to its fence line. Allocable cost is shared infrastructure the load advances or enlarges, a transmission line sized past the campus because building once is cheaper than building twice, assigned by use over time as other customers arrive. System-wide cost belongs to everyone and stays socialized: the reliability standard itself, the planning function, storm response. Principle 5 assigns the first category to the load, amortizes the second by demonstrated use, and leaves the third on the general body of ratepayers. A tariff that bills a data center for the whole line it merely accelerated is as wrong as one that spreads its peak across every household, and both errors are now in circulation. **Four stages.** *Stage 1, large-load incremental obligation.* Before attempting to replace a regional capacity market, require new large loads to demonstrate incremental reliability coverage. *Stage 2, voluntary bilateral obligation market.* Allow existing load-serving entities and generators to satisfy requirements through standardized contracts. *Stage 3, residual auction.* Retain a centralized auction for uncovered requirements. *Stage 4, evaluation.* The centralized market recedes only when the decentralized mechanism demonstrably provides equivalent or better reliability at lower total cost, with sufficient liquidity and tested non-performance consequences; where it does not, the auction stays, and that outcome is a finding instead of a failure. Jumping from PJM's current market to a fully decentralized obligation system in one move is not the proposal. Three distinct functions run through this section. **Cost responsibility** answers who pays for incremental reliability; it is what the incidence principle governs, and a tariff can allocate cost without determining market structure. **Resource adequacy** answers who must see that the capacity exists; a centralized auction can secure adequacy without allocating incremental cost to its drivers. **Revenue architecture** answers how a resource gets paid predictably enough to finance that capacity; an aggregator toll can solve revenue risk without touching the first two. ERCOT is the proof that the revenue function can be solved privately, through tolling and bilateral hedging, without any capacity construct at all; the obligation mechanism proposed here solves both at once in markets that have a construct to reform. Generators should read the revenue consequence as an upgrade, and the reason is bankability. No lender finances a turbine against an auction that paid $28.92/MW-day one cycle and $269.92 the next, an administrative cap it has now hit four times running [15]; that volatility is why record prices coincided with roughly 525 MW of new entry in the latest auction [16]. Obligations settle as contracts, and 10-to-15-year contracts with creditworthy counterparties are what project finance is built on. The likely revenue instrument is the long-tenor bilateral contract developers already prefer; the reliability obligation and the revenue contract remain separate design questions. **Three procurement designs, compared.** The ratings are this paper's assessment; the gaming-risk row is the honest one, because the auction's failure modes are at least known. | | Centralized auction | Phased obligations | Bilateral contracting | |---|---|---|---| | Price discovery | High | Medium | Low to medium | | Revenue certainty for new build | Low | High | High | | Resource neutrality | Medium | High | Design-dependent | | New-build financeability | Weak | Strong | Strong | | Reliability accountability | High | High, if verified | Requires verification | | Consumer risk | Price-cap exposure | Contract-term exposure | Counterparty exposure | | Gaming risk | Known | New | New | **Outside the organized markets.** A substantial minority of US load sits outside an RTO, and this is the only principle whose staged obligation mechanism presupposes a capacity construct to replace. The incidence principle generalizes anyway, and its vehicle in a vertically integrated state is the large-load tariff, which several Southeastern utilities are already building: new large loads contract for their own capacity, contribute to the resource plan that serves them, and accept curtailment terms in exchange for speed. The integrated resource plan is the natural vehicle in those states, and these reforms change what it is for. Under cost-of-service ratemaking an IRP functions as a justification for a capital plan. Under a total-expenditure allowance with shared savings and benchmarked outputs, it becomes a procurement plan in which non-wires alternatives, flexibility contracts, and reconductoring compete against new construction on equal financial footing, and the reconductor-first showing becomes a filing requirement within it. For a vertically integrated state, amending the IRP rule is probably the single most consequential move available. ## What the program buys The economic benefit of this program arrives in the form of system-wide compounding efficiency gains. The one-time transition costs center on administration and IT. At scale, the amounts are significant. At any scale the ratio of benefit to cost is attractive. Here are the data points and scenarios behind this evaluation. Duke's Nicholas Institute estimates that curtailment flexibility from large new loads could open on the order of 100 GW of headroom on the existing system [17]; priced against combined-cycle capital costs, this yields a scenario-based $100-220 billion estimate of generation investment that could be deferred if roughly 100 GW of incremental load can be served through existing-system flexibility, before any wires, the low end at EIA's reference cost of $921 per kilowatt (2023 dollars) and the high end at the $2,000-2,200 per kilowatt observed in recent market data [17]. The PNAS reconductoring analysis implies roughly a doubling of throughput on candidate corridors at a fraction of greenfield transmission cost, with no new permitting [11]. The interconnection queue holds 2,061 GW [18], of which 549 GW already holds a draft or executed interconnection agreement; raising the historical completion rate by even ten percentage points would connect roughly as much capacity as the country added over the past decade. And on bills: PJM's capacity charges alone rose from $2.2 billion to $16.4 billion a year across four years of auctions [15][16], costs that decentralized obligations reassign to the loads that drive them. These are illustrative planning estimates rather than empirical forecasts of realized savings, and the range around each is wide. The direction of every one of them is the same. **Aggregated, best case.** Assume jurisdictions covering roughly two thirds of national load implement the preferred or a viable mechanism under each principle by the early 2030s. Annualizing the figures above and counting only efficiency gains, never transfers: deferred generation carrying costs of $10-22 billion a year (the $100-220 billion deferral at a 10 percent fixed charge rate), $6-12 billion a year from scarcity-premium compression in reliability procurement (40 to 70 percent relief of PJM's premium as entry accelerates, at half that intensity across the other organized markets), $4-8 billion a year in delivery efficiency (3 to 6 percent of participating jurisdictions' share of national delivery revenue, the headroom the British record demonstrates), and $3-8 billion a year from faster queue conversion. The total is roughly $25-50 billion a year at maturity, about 5 to 10 percent of the national electricity bill, or $160-330 billion cumulative over a decade with adoption ramping to maturity by year six. Implementation under the same scenario costs roughly $22-54 billion over the decade: regulatory capacity, data and settlement platforms, the incremental metering and telemetry gap, ringfenced access administration, and procurement transaction costs. The defensible benefit-to-cost band is 5:1 to 15:1, on the order of ten to one, and the ratio is harder to move than either level, because most estimation errors move the numerator and the denominator together. These are scenario figures under the same caveat as everything above, and the program's published metrics, not this aggregation, remain the test. ### One connection, twice Scenario figures; the mechanics are the point. A 100 MW data center applies on a constrained part of the system. Today. The application enters a serial study queue where the median wait exceeds five years [18] and PJM's average application-to-operation run is more than eight. The campus's peak joins a capacity requirement procured through an auction whose cost reached $16.4 billion a year, spread across 67 million people [15][16]. The developer prices the wait into the project. The utility studies at its own pace and earns on whatever upgrade the study finds, and the households of the region carry the readiness cost of demand they did not create. Under the program. The load files under a large-load tariff of the kind twenty-four states have approved, demonstrating forward coverage of its incremental capacity. It offers verified curtailability in the top 50 to 100 hours, the structure Google contracted with Indiana Michigan Power and TVA [13], and takes fast-track service against published limits: an answer in months. At the capital costs behind the flexibility estimate, roughly $1,000 to $2,200 of generation capital per kilowatt, 100 MW of curtailable load defers on the order of $100 to $220 million that the auction would otherwise procure and socialize [17]. The ledger by party. The developer trades curtailment in under one percent of hours for years of earlier revenue. The utility earns a performance payment on the flexibility contract and keeps whatever network build demonstrated use later justifies. Incumbent generators sell the campus a contract both sides can finance. Households pay none of the readiness cost and keep the full reliability standard. The numbers are scenario arithmetic from the sources above; the allocation is the design. ## Where the savings come from, and who pays less An electric bill that falls by ten dollars could mean money transferred from a different party or saved via efficiency. The accounting below shows that most of the savings are not a transfer at all. | Source of saving | Mechanism | Who bears the reduction | Transfer or efficiency | |---|---|---|---| | Capacity cost reallocation | Large loads demonstrate their own forward hedges instead of clearing through a socialized auction | Large new loads, which pay what households now pay on their behalf | Transfer, and the largest near-term bill effect | | Avoided distribution and transmission capital | A deferral or a reconductoring means capital is never deployed, so the annual revenue requirement on it is never collected | Utility shareholders lose the equity return on the asset not built, partly restored through shared savings | Efficiency, split between ratepayers and the utility | | Lower energy clearing prices | Queue clearance adds supply that competes against the marginal unit | Incumbent generators lose inframarginal producer surplus | Transfer, and the one that does come out of an incumbent’s margin | | Lower cost of capital | Contracted revenue replaces merchant exposure, so the risk premium falls because the risk falls | Nobody; the premium compensated a risk that no longer exists | Efficiency | | Avoided process cost | Years of study, restudy, and withdrawal churn stop being financed by developers and recovered in prices | The process itself | Efficiency | Two clarifications. **The allowed return on equity is not cut.** Nothing in this program lowers the percentage a utility earns on invested capital. What changes is how much capital is deployed to earn that return, and what else the utility can earn on instead, which is why a utility that becomes good at procuring cheap grid services can earn more in total than it does today. **And the reallocation line is not a penalty invented for data centers.** Large loads already pay capacity charges through their tariffs. The reform changes the incidence of a charge they already bear, which is why the trade is acceptable to them at a price that is small against the value of being energized years sooner. What nobody has done is assemble this state by state. The pieces exist in the national laboratory and consultancy literature, but no jurisdiction has published a full incidence study of a total-expenditure transition against its own rate base, load mix, and capital plan. That study is a modest analytical undertaking, it is the first thing commission staff or a consumer advocate will ask for, and it should be commissioned in parallel with the first performance-regulation docket. ## The consumer case: what this does to an electric bill Start with the paradox the inversion produces: the cheapest electricity ever generated is arriving alongside the fourth inflation-beating run-up in American electricity prices, and the first of the four without a cost story behind it. Nominal residential rates are up 33 percent since 2019 and still climbing in real terms, and electric and gas utilities requested a record $31 billion of rate increases in 2025, double the prior year, with only two of the 83 tracked cases rejected [24]. Cheap supply and expensive bills coexist because institutions stand between them. The program is therefore designed to make the sources of rising cost visible and to let lower-cost alternatives compete against higher-cost ones. Whether electric bills follow is the empirical test, and the yardstick is comparable jurisdictions. An electric bill has three cost drivers, and each principle aims at one. The supply line falls when cheap generation can actually connect. Clearing the queue and connect-and-manage (Principle 4) let the $40-98/MWh resource compete against the incumbent's marginal cost, and each ten points of queue completion is roughly a decade of additions arriving to bid. The reliability line is an incidence question. PJM's capacity charges rose from $2.2 billion to $16.4 billion a year, socialized across every household in thirteen states, driven substantially by demand growth those households did not create. Decentralized obligations (Principle 5) put a data center's capacity cost on the data center's books, and replace cap-priced auction charges with contracted supply that new entry can undercut. The delivery line, now the fastest-growing part of many bills, is what Principles 1 through 3 discipline: totex and yardstick regulation end the earn-on-whatever-you-build formula, the reconductor-first showing buys transmission capacity at roughly half the greenfield cost, shared-savings deferrals return most of each avoided substation to ratepayers, and posted locational offers pay households and third parties for flexibility that would otherwise be bought as steel. The regional evidence for how much room this creates: after inflation, rates rose more than 6 cents/kWh in California and more than 2 cents across much of the Northeast and Mid-Atlantic from 2019 to 2025, with delivery investment a principal driver [24]. The protections are important: hedged flat products freely available under default dynamic rates, transition-year bill protection, targeted low-income rates, and non-retroactive tariffs. Nothing here repeals the real cost pressures of wildfire hardening, storms, and cyber defense, which totex funds in full. The claim is narrower: pay for outcomes instead of capital, assign costs to their drivers, let cheap supply connect, and real bill growth in participating states runs below matched peers. ## What the reforms would do to capital formation The audience for grid reform now includes the infrastructure funds, pension managers, and insurers who will finance the buildout, and the reforms read differently through their eyes than through a regulator's. Four channels matter. **Cost of capital.** Project revenue certainty is the largest lever on delivered energy cost for capital-intensive resources; Lazard's published sensitivities show levelized costs moving materially with the assumed cost of capital [22]. Principle 5 replaces merchant exposure to a cap-bound auction with long-tenor contracted revenue from creditworthy counterparties, which is the difference between pricing a project off a volatile spot construct and pricing it off a PPA. **Development-cycle length.** Capital tied up in a five-year study queue earns nothing and compounds risk; a developer's equity turns over roughly twice as fast under connect-and-manage timelines, which raises the productivity of every development dollar and widens the field of firms that can afford to play. **Merchant and regulatory risk.** The value-stack tariffs of the cross-cutting reform, formula-driven and never retroactive, convert grid-edge revenue from a political variable into an underwritable one; the solar and storage industries' consistent message that predictability matters more than price level is a statement about discount rates. **Asset productivity.** Reconductoring, envelopes, and flexibility raise the output of capital already sunk, from wires to waiting projects, which is the cheapest capital formation available: none. The utility-investor version is Principle 1's table above: the British experience says performance regulation preserved credit quality and, if anything, over-rewarded equity, which is why the calibration fight, not the framework, is where investor attention belongs. ## Who wins, who loses, and why they will fight | Group | Gains | Losses | Support likelihood | What moves them | |---|---|---|---|---| | DER developers and aggregators | Durable tariffs, connection by right, and volume | Per-kWh economics where retail-rate crediting still applies | Very high | Predictability finances projects; the level matters less than the fact that it stops changing | | New-entrant generation developers | Long-tenor contracts and far faster entry | Little; the current auction pays them almost nothing | High | The last auction drew about 525 MW of new supply at a record price | | Institutional capital | Contracted revenue, shorter cycles | Merchant volatility plays | High | Revenue certainty is the cheapest lever on cost of capital | | Large loads: hyperscalers and industrials | Time to power, and a standard flexibility product | Capacity costs they currently avoid | High | Time to power dominates the arithmetic; assigned capacity cost is small against a campus energized years sooner | | Consumer advocates | Costs shift to their drivers, hedged default rates | Complexity to police, and a long record of opposing default time-varying rates | Mixed to favorable | Electric bill trajectory and non-retroactivity | | Environmental groups | Queue clearance is the decarbonization constraint | Gas connects faster too, and leads PJM's reopened queue at 106 GW | Mostly yes | The net emissions math of a cleared queue | | Governors | Rate relief voters can feel, and credit for delivering it | Utility political opposition | First mover | Opportunity to lead and attribute the result to this leadership | | Commissioners and staff | Less rate-case theater, better data | A higher analytic bar, and in elected commissions a public vote to defend | Mixed | Funded capacity, and peer benchmarks to work against | | Building trades and IBEW | Reconductoring, hardening, and envelope deployment are union work | The assumption that every solution is new construction | Mixed | Totex redirects the capital program rather than shrinking it | | Co-ops and municipal utilities | The same tools without rate-case exposure | Little, though they answer to boards rather than commissions | Mixed | Board action, federal financing conditions, and joint-action agencies; no mandates | | Incumbent generation and transmission owners | Obligations still pay their capacity, under contract | The largest financial win of the status quo: cap-bound clearing that pays the existing fleet | Resistant | Little near-term; their influence runs through RTO sector voting, so the answer is contracts and FERC process rather than persuasion | | Investor-owned utilities | Earnings on outcomes; totex funds the real needs in full | Automatic rate-base growth, the gatekeeper's chair, and the data monopoly | Strongest opposition | Britain's record is the conversion argument, and it describes where a well-run utility lands rather than how the sector behaves during the fight | The strategic core: the coalition for reform is everyone on the outside of the queue: households, businesses, energy producers and energy consumers large and small. The two resistant rows are not equivalent. Incumbent generation and transmission owners face a revenue loss from one reform, and their influence runs through RTO sector voting, where a bloc can withhold the supermajority that sends a tariff change to FERC under Section 205 and force reformers onto the slower Section 206 path instead. That is a procedural chokepoint at the federal level, and FERC process answers it. Investor-owned utilities face something categorically larger: four of the five principles alter their business model. They fight in the venue where those four are actually decided, the state commission and the legislature, where they hold in-state political relationships, recoverable regulatory expense, and a presence in every district they serve, against intervenors funded at a fraction of their scale. The hard fight is at home, not in Washington. The first reform is chosen precisely because it changes what utility earnings reward, and the funded-intervenor, open-data, and yardstick provisions are part of the program for the same reason. **What would turn each of them.** DER developers leave the coalition if locational procurement replaces retail crediting without a bridge, if curtailment arrives uncompensated, or if telemetry requirements price out small fleets; the transition rules under Principle 3 exist for exactly this reason. Large loads balk at take-or-pay terms on network capacity of uncertain utilization and at collateral sized to a forecast they dispute, which is what standard products and demonstrated-use trueups answer. For utilities the breaking points are baseline resets that confiscate efficiency gains, stranded-cost exposure, and earnings volatility at the reset; the symmetric reopener and the grandfathering of in-flight capital are in the order language because of them. Consumer advocates exit over complexity they cannot police, which is why funded analytical capacity is a coalition condition and why the incidence work is commissioned with the first docket. ## Who should bear which risk Mechanism choice follows from one question: who is best positioned to bear a given risk? The answers below are typical, and the same risk is legitimately allocated differently in different markets. | Risk | Typically best borne by | Note | |---|---|---| | Energy price | Merchant participants, aggregators, and their hedge counterparties | ERCOT tolling is this allocation working privately | | Nodal congestion | Generators, loads, traders, or hedging counterparties with portfolios | Diversifiable across nodes, not within a single project | | Resource adequacy | The system operator and the regulated framework, with incremental cost assigned to incremental load | The subject of Principle 5 | | Distribution constraint | Utility, aggregator, load, or contracted service provider, depending on who can act | The subject of Principle 3 | | Technology performance | Project owner and vendor | Not a policy question | | Long-term policy revision | Government and regulator, where the value was policy-created | The case for non-retroactivity | | Network planning | Utility or system planner, subject to performance incentives | The subject of Principle 1 | ## Where this could go wrong Five failure modes deserve consideration. **Obligation positions could become opaque.** A decentralized reliability obligation settles bilaterally, and bilateral positions that are self-certified, transacted with affiliates, or valued by model rather than by contract are the exact shape of the last great energy scandal. The safeguards are registration and publication of every obligation position, standardized products so positions are comparable, physical backing requirements, and independent verification. An obligation regime without those is worse than the auction it replaces. **Flexibility could be promised and not delivered.** A large load that certifies curtailability and does not curtail is a reliability failure discovered in the worst hour. Measurement and verification settled after the fact against telemetry, with a penalty price exceeding the value of non-performance, is the answer, and it belongs in the tariff before the first fast-track connection is granted. **Shared savings could be inflated.** A utility that overstates the wires project it avoided collects a share of savings that never existed. This is not hypothetical: the accounting behind the Brooklyn-Queens deferral was contested on precisely this point. Counterfactuals need independent review and a standardized method, or the mechanism becomes a subsidy for creative arithmetic. **Benchmarks could be gamed at the reporting layer.** Yardstick regulation is only as good as the comparability of its metrics, which means audited definitions and third-party verification instead of self-reported outputs. **A ringfenced operator could favor its affiliate.** This is the oldest problem in network regulation, and Order 888 wrote the codes of conduct that address it. Where the conflict is severe, the answer is full independence rather than a ringfence. The 2000 and 2001 California comparison will be made whether or not it is apt. That crisis was produced by a design that barred utilities from forward contracting while exposing them to spot prices under a frozen retail rate. Principle 5's central requirement is mandatory forward physical hedging. The mechanism at the heart of this program is the specific antidote to the failure that ended the last one, which is a reason to sequence it carefully. ## Proven, demonstrated, and reasoned The proposed mechanisms have track records with different degrees of implementation at scale. **Established mechanisms with operating evidence.** Performance regulation with a total-expenditure allowance has run in Great Britain for thirteen years across two full control periods, with published outcomes on returns, reliability, and investment [1]. Connect-and-manage has operated in ERCOT for close to two decades through the fastest resource growth in the country [9]. Dynamic operating envelopes have been the default connection standard for new solar in South Australia since 2023, at population scale rather than in pilots [7]. These are engineering and regulatory practices with years of measured results, and the question about them is transferability rather than feasibility. **Demonstrated in narrower application.** Distribution system operator separation is young: Britain imposed functional separation under licence conditions in 2023 and separated its national system operator in 2024 [4]. Locational value pricing has nine years of history in New York's value stack, with mixed results, including a base stack that has required continuous adder support since 2017 [27]. Non-wires alternatives have many pilots and few programs at scale, with contested savings accounting in the best-documented American case [20]. These work, and the open questions are about scale, calibration, and durability. **Proposed institutional combination with partial analogues.** Decentralized reliability obligations have a working precedent in France, in a market with a dominant state-linked incumbent and a structure unlike PJM's, and no American precedent at that scale [14]. Distribution-level price formation is deliberately deferred in this program precisely because no scaled example exists. ## What we do not know yet Several questions in this program are empirical: How much distribution-level locational pricing is economically justified, given transaction costs at current participation volumes. When an aggregator improves risk allocation more than a bilateral contract does. When a long-term contract is preferable to merchant exposure for a given resource class. How much flexible interconnection can safely substitute for network expansion before recurring curtailment makes permanent investment the cheaper answer. When a fully separated operator is warranted rather than a ringfenced affiliate. And when a total-expenditure framework outperforms other mechanisms for removing the capital bias. What matters is less which answer this paper favors than how a jurisdiction finds out. The reform architecture should create controlled opportunities to learn: regulatory sandboxes, bounded pilots, temporary tariffs with sunset clauses, competitive solicitations that reveal price, published baselines, peer comparison groups, and independent evaluation. Where multiple mechanisms can perform the same function, policy should let them compete and measure the result. ## Revisit triggers and escalation criteria A mechanism adopted with a stated trigger is an experiment with results that inform subsequent implementation, so every consequential stance in this paper carries one. **Distribution-level price formation.** Deferred. Revisit when interval metering covers the participating classes, DER participation is deep enough that administrative offers visibly misprice and to discipline a local clearing price, congestion is persistent rather than episodic, estimated transaction costs fall below estimated dispatch benefits, and the price would be computed by an administrator without a commercial stake in the answer. **Separated operator.** Ringfencing is the transition. Escalate to full separation when access conflicts recur under the code of conduct, affiliate complaints rise rather than fall, procurement concentrates in the affiliate beyond a published threshold, or queue performance fails its benchmark for two consecutive review periods. Symmetrically, a ringfenced affiliate that clears every benchmark has earned the lighter structure. **Decentralized reliability obligations.** Expand a stage only when verified obligation coverage reaches the published threshold for the current stage, contract liquidity supports price discovery, non-performance consequences have been tested on a real event, and reliability metrics hold within target. Any failed gate holds the program at its current stage; none of the gates is discretionary. **Total-expenditure regulation.** Expand scope after comparable cost metrics exist across the peer group, the baseline is set from audited historicals rather than forecasts, and financing health is demonstrated through at least one full review period. The reopeners and guardrails under Principle 1 are the operating version of this trigger. These triggers convert the roadmap from a schedule into a set of gates, which is reality for a multi-year program: dates say when to evaluate; evidence says whether to proceed. ## Why this window, and not five years ago or hence The demand shock is present tense: data-center and manufacturing load growth turned grid access into a boardroom problem for the most politically capable companies in the economy, which did not exist as a constituency in 2020. The technologies matured past the argument stage: storage is a commodity, aggregators run real portfolios, and Australian networks operate envelopes at scale, so "unproven" has lost most of its force. The legal groundwork is already laid: Orders 2222, 2023, and 1920 sit on the books waiting for enforcement rather than enactment, which converts multi-year rulemakings into compliance fights. The failure is undeniable and priced: four consecutive cap-bound PJM auctions and bill growth that decides elections gave governors ownership of the problem, and reforms ride on visible failure, as 1907 and 1992 both showed. And capital is available for projects with financeable revenue and a predictable connection on the sidelines with nothing to buy: infrastructure funds seeking contracted grid assets are the natural financiers of every reform in this paper. Windows close. The predictable counter-reformation, incumbents offering rate-based mega-capex as the answer to load growth, is already assembling, and each approved conventional plan extends the old equilibrium's life by an asset's depreciation schedule. ## Implementation roadmap, 2027 to 2035 The program runs on two tracks. Under the Federal Power Act's 1935 division, Principles 1, 2, and 3 sit entirely within state authority, and states own the distribution half of Principle 4. Only Principle 5 requires FERC, though states hold real levers over it through Fixed Resource Requirement elections, large-load tariffs, and their own procurement. **Nothing on the state track waits on the federal track.** A commission that opens a docket in 2027 is not blocked by anything Washington does or fails to do. ### The state track **2027.** Publish interconnection metrics and machine-readable hosting-capacity maps. Open a performance-regulation docket scoped to totex treatment, peer benchmarking, and shared savings. Approve a flexible-connection tariff so small resources connect inside published limits. Open a large-load tariff proceeding that assigns capacity and network costs to new large loads. **2028-2029.** First totex orders take effect, and shared-savings mechanisms make non-wires procurement profitable, which softens utility opposition to everything downstream. Automated screening goes live for small resources. Dynamic rates become the default, with hedged flat products freely available. **2030-2031.** Where the escalation criteria are met, lead states separate access administration from the wires business; elsewhere ringfencing holds, on its benchmarks. Dynamic operating envelopes deploy at scale in high-DER territories. **2032-2035.** Standard value-stack tariffs with scheduled, non-retroactive updates replace the net-metering successor fights. Yardstick benchmarks take over allowance-setting with five years of comparable data. ### The federal track **2027.** FERC opens rulemakings on connect-and-manage as the default interconnection framework and on Order 2222 deadlines with consequences, and enforces Order 1920 planning with reconductor-first showings. PJM's obligation-transition stakeholder process begins, with the 2026 auction record in hand [16]. **2028-2029.** Connect-and-manage is finalized for bulk generation and large loads. Large-load flexibility tariffs standardize the hyperscaler bargain. Minimum interregional transfer requirements are set. **2030-2031.** The first hybrid delivery year runs a shrinking centralized residual auction alongside a growing share of demonstrated bilateral obligations, with cleared legacy commitments paid in full. **2032-2035.** The centralized auction recedes to a residual backstop wherever obligation coverage passes the reliability-and-cost test, and stays wherever it does not. Distribution-level price formation opens for large participants where the revisit triggers say the substrate is ready. ### What proves each stage worked Dockets open and data published by the end of 2027. By 2029, a utility earns more by buying a battery service than by building the substation it replaces. By 2031, new data-center load carries its own demonstrated capacity. By 2035, queue conversion materially above the historical baseline, with median duration and withdrawal measured separately. A target: above 50 percent conversion for mature cohorts, not for the entire active queue. Who moves first: three governors and their commissions, with FERC on a parallel track. Who benefits first: whoever is waiting in a queue, which is everyone the current system is failing. ## What success means Economically valuable projects connect predictably, on a timeline they can finance against. Customers face lower lifetime costs, which is a different and more defensible claim than cheap power. Reliability holds or improves, measured on the standards already in force. Utilities remain financially healthy. And competition shifts investment toward the least-cost solution, whoever owns it. The fourth of those is the one most often left unsaid. A well-run utility earns more under a framework that pays for outcomes than under one that pays for spending, which is what the British record shows and what the sequencing here is built around. ## The measures that prove it By 2030: median small-resource interconnection measured in days, large-load and bulk-generation connection offers inside 18 months, at least five states under totex performance-based regulation, and the first delivery year in which new data-center load carries its own demonstrated capacity. By 2035: queue conversion above half for mature cohorts, median application-to-energization under two years for viable projects, interregional transfer capability growing, capacity costs allocated to their drivers, and real retail bill growth in participating states below matched peer states. Each indicator is measurable annually, and Paper II's failure metrics (queue depth, auction outcomes, bill growth) serve as the control chart. ## What America should copy, and from whom **From Britain:** the regulatory machinery. Totex allowances, output incentives, and DSO separation, plus the caution: RIIO's early price controls over-rewarded outperformance, so calibrate sharing factors tightly from the start [1]. **From Australia:** the grid-edge engineering. Dynamic operating envelopes and aggregator interfaces at rooftop scale, plus the caution: envelopes without market signals waste the flexibility they create; pair them with the locational offers of Principle 3 [7]. **From Texas:** the speed. Connect-and-manage and an entry-friendly bulk market, plus the caution: an energy-only construct passes scarcity through to retail, so pair speed with the hedging obligations of Principle 5 instead of importing the volatility [9]. **From Hawaii:** the politics. Performance-based regulation adopted in the state where distributed penetration made the old model untenable first, proof that a commission can rewrite the compact when the legislature stakes out the destination [2]. ## Transition fairness Nothing here is retroactive: resources that cleared past auctions get paid through their delivery years, and obligations phase in over three cycles. Stranded value that survives independent review has a tested instrument, the ratepayer-backed securitization states used for restructuring-era stranded costs and use today for retired plants [19]. Public power, roughly a quarter of U.S. load, adopts through different doors: board action at TVA (whose 2025 Google agreement shows the appetite [13]), financing conditions at the Rural Utilities Service, and joint-action agencies supplying DSO functions small systems cannot staff. And the open engineering questions Paper II names, inverter-dominated operation above all, argue for the sequenced deployment; every operating year in South Australia and ERCOT shrinks them. ### The advocate's capacity The swing constituency in most of these dockets is the consumer advocate, and the program should arm them. Four provisions do it: funded intervention so participation does not depend on donated expertise; a standing right of access to the utility data the case turns on, under the same rules the operator follows; standardized cost-benefit and incidence templates so every mechanism is scored the same way in every docket, including this program's own proposals; and the authority to commission independent modeling against the utility's counterfactual rather than merely cross-examining it. The proposition is simple: if you want a different regulatory bargain, give the regulator and the public the analytical capacity to negotiate it. ### The utility transition A utility executive's first questions are operational, and they have answers. **Data:** grid data becomes a regulated asset with access rules, on the model of open banking; the utility keeps custody and cost recovery for the systems, and loses the right to withhold. **IT systems:** the ADMS, GIS, and metering platforms utilities are already deploying are the DSO's toolset; separation transfers administrative control and API obligations, not the software estate, and Britain executed this as a licence change rather than a systems rebuild [4]. **People:** the interconnection engineers, planners, and data teams move with their functions, as transmission staff moved into ISOs in the 1990s; the DSO is a destination for the workforce, not a layoff. **Planning processes:** the integrated distribution plan survives, produced by the DSO with the utility as builder-of-record for wires solutions, which changes who holds the pen and nothing about whether planning happens. **Capital plans:** in-flight projects grandfather into the totex baseline at approved values, and the reconductor-first showing applies prospectively. **Earnings expectations:** the multi-year revenue cap is set to be earnable at current-plan performance, with upside from outperformance, which is precisely the trade British networks accepted and then profited from; the transition risk investors should actually price is calibration of the sharing factors, and the RIIO record gives them a decade of data to price it with [1]. None of this is free, and the administrative cost is real. It is also one-time, small against a single deferred substation, and largely spending the utilities would incur anyway. ## Conclusion: completing the market Complete the market where competition can work; strengthen regulation where monopoly remains. The 1907 settlement matched scarce, central supply. The 1992-2000 settlement opened the bulk market and stopped at the substation. The technology that forces the third settlement is already installed, financed, or waiting in a queue, and the first tranche of the capacity it would deliver is the only major infrastructure program in American history that is already built. What remains scarce is permission. Permission is made of rules, better rules can reduce the need for infrastructure built to compensate for institutional constraints, and the bodies that can rewrite them, FERC and a handful of state commissions, can start in 2027 without waiting for Congress. The measure that will matter most politically is the simplest: whether the household bill in participating states bends back toward inflation, and every principle above is aimed at exactly that. The end state is a grid on which a manufacturer's request for 20 MW returns an answer in minutes rather than years, and the companion document What Success Looks Like walks through this. The grid's first two settlements arrived only after visible, expensive failure, over incumbent opposition, and were later defended by their former opponents. Every precondition for the third is now met. --- ## Sources [1] Ofgem, RIIO framework documentation and price control reviews, ofgem.gov.uk, including RIIO-2 and RIIO-ED2 final determinations and the RIIO-2 regulatory performance data files (2024, 2025); National Audit Office, *Electricity Networks* (2020), on RIIO-1 returns of roughly 9 percent real against a 5-6 percent UK-company average; Competition and Markets Authority determination (2021) removing the outperformance wedge; Oxera, "RIIO-2 Final Determinations: how final?" (2021), on sharing-rate changes. [2] Hawaii Public Utilities Commission, Docket 2018-0088, performance-based regulation for Hawaiian Electric (2020). [3] Andrei Shleifer, "A Theory of Yardstick Competition," *RAND Journal of Economics* 16:3 (1985). [4] Ofgem, RIIO-ED2 licence conditions and DSO baseline expectations effective April 2023, requiring functional separation of DSO roles (see, e.g., National Grid Electricity Distribution, "DSO-DNO Functional Separation Arrangement," March 2025); the National Energy System Operator (NESO) was established as a separate public body in 2024. [5] Paul De Martini and Lorenzo Kristov, *Distribution Systems in a High Distributed Energy Resources Future* (LBNL FEUR series, 2015); MIT Energy Initiative, *Utility of the Future* (2016). [6] Severin Borenstein, "The Long-Run Efficiency of Real-Time Electricity Pricing," *The Energy Journal* (2005), and Energy Institute at Haas working papers. [7] ARENA and AEMO, Project EDGE and Project Symphony reports on dynamic operating envelopes; South Australia Office of the Technical Regulator, Dynamic Export Requirements (mandatory for new exporting systems from July 1, 2023); SA Power Networks, statewide Flexible Exports announcement (June 2025). [8] National Renewable Energy Laboratory, SolarAPP+ automated permitting documentation. [9] Tyler H. Norris, "Beyond FERC Order 2023" (Nicholas Institute, Duke University, 2023). [10] PJM materials on the connect-and-manage framework for large loads and the FERC 206 show-cause proceedings (2026). [11] Emilia Chojkiewicz et al., "Accelerating transmission expansion by using advanced conductors in existing line corridors," *PNAS* (2024). [12] The Brattle Group, "Unlocking the Queue with Grid-Enhancing Technologies" (2021); FERC Order No. 1920 (2024). [13] Google demand-response agreements with Indiana Michigan Power and TVA (2025). [14] Peter Cramton and Steven Stoft, "The Convergence of Market Designs for Adequate Generating Capacity" (2006); RTE documentation of the French capacity obligation. [15] Utility Dive and PJM Independent Market Monitor coverage of the 2024-2025 auction results. [16] PJM, "PJM Capacity Auction Procures 138,318 MW of Generation Resources" (July 14, 2026). [17] Tyler H. Norris et al., *Rethinking Load Growth* (Nicholas Institute, Duke University, 2025), estimating roughly 76-126 GW of integrable new load across curtailment scenarios of 0.25 to 1.0 percent; U.S. EIA, *Capital Cost and Performance Characteristics for Utility-Scale Electric Power Generating Technologies* (Sargent & Lundy for AEO2025; $921/kW for a 1x1 F-class combined cycle in 2023 dollars); GridLab, Energy Futures Group, and Halcyon, *The New Reality of Power Generation* (September 2025), documenting recent combined-cycle project costs near $2,000/kW. [18] Joseph Rand et al., *Queued Up: 2026 Edition*, Lawrence Berkeley National Laboratory (June 2026); 2,061 GW active at year-end 2025, with 549 GW holding a draft or executed interconnection agreement. [19] Richard F. Hirsh, *Power Loss* (MIT Press, 1999), on restructuring-era stranded-cost treatment; state securitization statutes for retired plant balances. [20] Consolidated Edison, Brooklyn-Queens Demand Management filings and NY PSC orders (Case 14-E-0302), with contested net-savings accounting noted in contemporaneous analysis; Arizona Public Service, Punkin Center battery deployment (2018), placed on standby in 2019; Sandia National Laboratories (2017) analysis of the Sterling Municipal Light Department system. [21] CTC Global and AEP reporting on the Lower Rio Grande Valley advanced-conductor rebuild; details as reported by the vendor and utility. [22] Lazard, *Levelized Cost of Energy+* (2026 edition), cost-of-capital sensitivity exhibits. [23] U.S. Department of Energy, Energy Dominance Financing loan of up to $3.26 billion to AEP Texas (July 2026), energy.gov/edf/aep-texas. [24] Lawrence Berkeley National Laboratory, 2026 update on retail electricity price trends and drivers (nominal residential rates +33 percent since 2019; a record $31 billion of rate-increase requests in 2025, double the prior year, with only two of 83 tracked cases rejected (PowerLines); real-rate increases of 6+ cents/kWh in California and 2+ cents across much of the Northeast and Mid-Atlantic, 2019-25); U.S. EIA, retail prices outpacing inflation since 2022. [25] The Brattle Group analyses of competitive transmission under FERC Order No. 1000, finding roughly 2 to 3 percent of transmission investment competitively solicited, cost escalation of about 34 percent on non-competitive projects, and winning competitive bids about 40 percent below initial estimates; Concentric Energy Advisors, *An Updated Examination of FERC Order No. 1000 Projects* (2024), presenting the incumbent utilities' contrary reading. [26] New England States Committee on Electricity, letter to ISO-NE on Asset Condition Projects (February 2023), documenting growth from $58 million in 2016 to more than $2.787 billion; RMI, *Mind the Regulatory Gap: How to Enhance Local Transmission Oversight* (2024); Utility Dive and CT Mirror reporting on asset condition spending and the limited authority of ISO-NE's Asset Condition Reviewer. [27] New York Public Service Commission, Case 15-E-0751, *In the Matter of the Value of Distributed Energy Resources*, and subsequent VDER compensation orders including the Order Regarding Community Credit and Community Adder Allocations (March 2020); NYSERDA Value Stack documentation on the Market Transition Credit, Community Credit, and Community Adder; Ascend Analytics and Camelot Energy Group practitioner assessments of value stack financeability, component terms, and market complexity (2024-2025). \pagebreak # What Success Looks Like ### Three mornings in 2035, if the principles hold, and the same afternoon everywhere *Companion to the three core papers: I. How We Built Institutions for the Wrong Grid, II. The Great Inversion, and III. Completing the Market.* --- This document illustrates a central claim of the series: different institutions can perform the same economic functions. Three states below run three architectures (merchant, contracted, and planned) and each morning delivers the same five things: transparent access, predictable connection, locational value that reaches the resource, defined reliability responsibility, and financeable revenue. If the functional-equivalence thesis is right, we should be unable to say which state "did the program," because all three did. ## Texas, seven in the morning A battery fleet operator's dispatch desk watches the nodal spread widen ahead of the evening ramp. Her batteries will chase the real price all day; her lender never sees it, because the fleet's revenue rides on tolling agreements with a counterparty that carries the spread across a portfolio and a hedge book. Nobody built a distribution market, nobody administers a value stack, and there is still no capacity construct: adequacy is what the energy price, the reserves, and a deep bilateral contract market deliver. Across town, a data-center campus that connected in fourteen months operates inside its published curtailment terms: the equipment was a condition of interconnection, and the top-hours flexibility it sells back is a product, not an emergency. Access runs through connect-and-manage as it has for decades at bulk voltage, now extended down: published limits, screened fast, curtailment as the worst case. The state never adopted most of the preferred mechanisms in Paper III. It reached the same five functions through merchant institutions. ## New York, seven in the morning A community solar developer prices a candidate site before her second coffee, unaided, from published data, in under an hour. The complexity budget held. The grid-services stack is formula-driven and updates on a published schedule; she elects the fixed strip for the energy layer, so the project finances on a hedgeable revenue while the tariff's locational component states its rollover terms instead of expiring into silence. The policy adder is a line item with a legislated duration, defensible because it is visible. The queue, the hosting data, and the operating envelopes run through the operator function the utilities evolved under commission order: an administrator with published rules, whatever the org chart calls it. Reliability is procured by the state and settled through contracts. No tolling desks, no merchant exposure anywhere in her capital stack: a contracted architecture, delivering the same five functions. ## The Southeast, seven in the morning A vertically integrated utility's planners open the resource plan that is now a procurement plan. Under the total-expenditure allowance the commission adopted, the battery contract and the reconductoring bid compete against the substation on one financial footing, and this morning the substation loses, which costs the utility nothing because the allowance is indifferent and the shared savings are not. The large-load tariff carries the incidence principle without a wholesale market anywhere in sight; the new campus contracts for its own capacity inside the IRP that serves it. Hosting capacity is published because the commission ordered a report, not because anyone built an institution. The state created no operator, no market, and no stack. It amended its planning rule and its payment formula, and the same five functions arrived through the institutions it already had. ## The factory's afternoon A manufacturer requests 20 MW for a plant expansion. The reply arrives in minutes: available headroom on three nearby feeders, the congestion-adjusted delivery price at each, a flexible-service alternative at a discount for accepting curtailment during roughly forty hours a year, the price and eighteen-month schedule of the firm-capacity upgrade option, and a delivery date the access administrator is penalized for missing (a DSO in one state, a ringfenced affiliate in another, the utility's own platform under a commission order in a third). The plant's CFO compares it to the 2026 experience the way travelers once compared airline booking to travel agents. The company also holds its reliability obligation: a portfolio of a ten-year contract with a wind-plus-storage project two counties away, a slice of a demand-response aggregation, and its own backup turbines, registered and visible to the settlement system. Its capacity cost shows up on its own books, itemized, which its investors prefer to the 2026 arrangement, where the cost showed up on everyone's grandmother's bill and, eventually, in a governor's press conference. ## The household's bill A family in a participating state opens the October bill, glances at it, and puts it down, because it is boring. Their default plan is a dynamic rate their thermostat, water heater, and EV charger arbitrage automatically; the year they enrolled, they took the hedged flat option instead, then switched once the bill comparison showed a sustained advantage, and both choices were always theirs. The delivery line has grown slower than inflation for four years running, because the wires company earns against a benchmarked revenue cap rather than a percentage of whatever it builds, and the deferral savings it shares show up as a credit line the commission's dashboard tracks in public. The reliability line is small and itemized; the data-center campus two towns over carries its own capacity on its own books, a lesson the community learned during the 2020s the hard way, when it didn't. The neighbor's battery earns the posted feeder rate for covering the evening peak, which the family notices only as the absence of the substation construction that was once planned for the corner lot. Their aunt, on the low-income rate with bill protection, rode through the transition years without a spike. None of them can name a principle. The 2035 measure of consumer success is that electricity stopped being a thing households think about. The control chart behind that boredom, real bill growth tracked against matched peer states, is published where anyone can check it. ## The utility's quarter The wires company's earnings call is about performance, because that is what it is paid for. Interconnection-speed and hosting-capacity metrics beat the benchmark, which under the yardstick means revenue above the peer-indexed allowance; a storm-hardening program funded fully inside the totex envelope came in early; and the company kept 30 percent of the savings from a substation deferred by a flexibility contract, per the sharing factor. In the states where the escalation criteria tripped, the queue, the data platform, and the envelope engine moved to a separated operator along with the engineers who ran them; where the benchmarks held, the utility kept the functions under the code of conduct. The company's planners now spend their time on the wires plan they hold the pen on as builder-of-record. Its lobbying budget changed shape: quiet between control periods, loud at the reset, because the formula-driven revenue cap left far less to lobby about year to year. That was the design. The laggard utility two states over, which litigated instead of adapting, earns at the bottom of the yardstick band, and its investors have noticed. ## The organized market's evening peak The RTO control room runs the evening ramp on a fleet unrecognizable to 2026: storage everywhere, flexible loads bidding in through aggregators under the long-implemented Order 2222 models, data centers shedding pre-committed load through the top hours per their tariffs, and the interregional ties built under enforced Order 1920 planning moving surplus across seams that used to be walls. Operating a system this inverter-heavy remains hard, and the control room is bigger and better instrumented than it was, running grid-forming standards that were still drafts in 2026. The difference is what the operators no longer do: adjudicate a 3,000-position queue, forecast demand they have no contractual visibility into, or administer a capacity auction whose price a governor negotiated. Resource adequacy is a settlement report of demonstrated obligations, published quarterly, dull as a bank statement. ## The investor's portfolio An infrastructure fund's grid sleeve holds contracted assets that did not exist as a class in 2026: obligation-backed generation with ten-to-fifteen-year tenors and hyperscaler counterparties, DSO-procured flexibility portfolios with formula-tariff revenue, and wires companies whose regulated returns price off a decade of yardstick data instead of off next year's rate-case politics. Cost of capital for new generation sits materially below the merchant-era levels, for the reason Lazard's sensitivity tables always implied: revenue certainty can materially reduce financing costs. The fund's risk memo flags what it still cannot underwrite, and the list is short: calibration risk at the five-year yardstick resets, and the political risk that a future commission unwinds non-retroactivity. No state has tried that yet. ## The regulator's dashboard The commission's open dashboard, the same one the public sees, tracks the control chart Paper III specified: median days-to-connect by resource class, queue depth and completion, envelope utilization, obligation coverage ratios, and bill growth against inflation, each series benchmarked against peer states. Rate cases still happen and still run long. There are simply fewer decisions inside them because the formulas absorbed the annual fights over compensation levels and the yardstick absorbed the fights over costs. The staff economists spend their time on the two open files: sharing-factor calibration for the next control period, and the petition, filed by a coalition of large participants, to open explicit distribution-level price formation on the envelope substrate, the step the 2020s papers deliberately deferred until the data existed to design it. The commission has the data now. ## What did not change Storms still break poles, and crews still restore them, paid through the same totex allowance that funds their trucks. Some customers still choose flat bills, hedged by their suppliers, and never think about the grid at all, which remains their right. Reliability standards did not relax; the obligation penalty price is set against them. A few corridors still needed greenfield transmission, built after reconductor-first showings honestly failed, sited over the same local objections as ever. And the institutions of 2035 are already accumulating their own assumptions that some future inversion will invalidate, because that is what institutions do. The measure of this settlement, like the two before it, will be how expensively it fails when its turn comes, and how much abundance it delivered first. Three architectures, one afternoon. The merchant state, the contracted state, and the planned state deliver transparent access, predictable connection, locational value, defined reliability responsibility, and financeable revenue, through institutions that share almost nothing but the principles. Different institutions. Different pathways. Same principles. \pagebreak # Examples in the Evidence Base ### What the precedents show, and what to do differently ## Evidence standard Each case is read for the **mechanism** it validates, and for the **function** it demonstrates. ERCOT demonstrates that private actors can manage volatility efficiently when they can aggregate it across a portfolio, which is a claim about risk allocation rather than about energy-only markets. New York demonstrates that an administered contract can bridge to investment while a market matures, and that an administered value drifts when no party has money at stake in its accuracy. Britain demonstrates that a payment formula can be changed without impairing network investment. The tolling agreement, the value stack, and the totex allowance are not mandates; each is evidence that a function can be performed. Each case below is classified by what it actually establishes: feasibility, observed effect, mechanism, or analogy. ## Part one: the precedents ### Great Britain: RIIO, 2013 to present **What happened.** Ofgem replaced cost-of-service regulation for energy networks with multi-year price controls built on three elements: a total expenditure allowance that treats capital and operating spending identically for recovery purposes, output incentives that pay for measured performance, and revenue caps set for a control period rather than reset annually. The regime has run through two full cycles, RIIO-1 from 2013 and RIIO-2 from 2021, with electricity distribution on its own cycle through RIIO-ED1 and ED2. **What the evidence establishes.** That totex regulation is administrable at national scale for a decade, and that it does not starve networks of capital. British networks maintained investment-grade credit throughout. Under RIIO-1 they earned roughly 9 to 10 percent real on regulated equity against a UK-wide corporate average of 5 to 6 percent, a gap the National Audit Office criticized as evidence that Ofgem's targets were insufficiently demanding. Western Power Distribution, the only distribution group Ofgem fast-tracked across all its regions under RIIO-ED1, beat its customer-minutes-lost targets by roughly 38 percent and its interruption targets by roughly 26 percent. When its owner sold it in 2021, Ofgem's own networks director cited the premium the buyer paid as proof that the regulated return was adequate. **What it does not prove.** RIIO establishes feasibility and operating experience, not a clean US causal estimate of savings. Britain has one energy regulator for one country, no federal and state division, a smaller and denser network, and a different corporate tax and financing environment. Nothing about RIIO demonstrates that a fifty-jurisdiction system can benchmark across state lines, which is the harder version of the problem. It also does not prove the regime is easy to calibrate, and the evidence points the other way. **The lesson, which is a warning.** RIIO-1's failure mode was over-earning, and it was large enough to become a public scandal, with Citizens Advice claiming £7.5 billion in unjustified profits. Ofgem's correction in RIIO-2 was severe: totex sharing rates cut from a range of 44 to 64 percent down to 33 to 50 percent, allowed equity set at 4.55 percent CPIH-real for gas and transmission, and a 25 basis point outperformance wedge applied on top. Eight companies appealed to the Competition and Markets Authority, which upheld the cost of equity but struck the wedge. Then Ofgem's own performance data showed continued outperformance through an inflation and debt interaction the framework had not anticipated, requiring another fix in RIIO-3. **What this initiative should do differently.** Three things. Set sharing factors conservatively from the start and publish the sensitivity analysis, because the political cost of clawing back excess returns is far higher than the cost of setting them tightly at the outset. Build an explicit reopener for financing-parameter surprises instead of waiting for the next control period. And expect the reset to be litigated, which means the first control period should be short enough to correct and long enough to be worth outperforming, with five years the defensible middle. ### Hawaii: performance-based regulation since 2020 **What happened.** The Hawaii Public Utilities Commission concluded a multi-year proceeding in Docket 2018-0088 establishing performance-based regulation for Hawaiian Electric, with a multi-year rate period, revenue caps, and performance incentive mechanisms. **What the evidence establishes.** That an American state commission can adopt this framework under existing authority, in an American legal and ratemaking context, with an investor-owned utility. This is the single most important thing in the file for an American commissioner, because every other precedent invites the objection that it happened somewhere else with different law. **What it does not prove.** Hawaii is an island system with no interconnection to anywhere, the highest electricity prices in the country, and distributed solar penetration that made the old model untenable earlier than elsewhere. Its commission faced a forcing function that a mainland commission does not. The utility has also since been consumed by wildfire liability, which makes clean attribution of operating results to the regulatory framework nearly impossible for the years that matter most. **The lesson.** Hawaii is a feasibility proof and a legal template, not an effect study. Cite it for what a commission can do under existing authority and for the design of the incentive mechanisms. Do not cite it for how much money performance-based regulation saves, because the wildfire has confounded the record. **What this initiative should do differently.** Pair the first mainland adoption with a pre-registered evaluation design, so that the effect question has an answer in five years. The absence of a clean American effect study is the single largest evidentiary gap in this program, and it is fixable only by planning the measurement before the intervention. ### Texas: connect and manage **What happened.** ERCOT interconnects generation by studying local reliability effects, connecting quickly, and managing congestion afterward through the energy market, with the developer bearing curtailment risk rather than paying for network upgrades determined in advance. **What the evidence establishes.** Speed, decisively, and the claim is bounded: the comparison is descriptive rather than causal, since market structure, geography, resource mix, transmission build, and load growth all differ between the two systems. What ERCOT establishes is that rapid connection under managed operating constraints is feasible at scale. ERCOT brought 14.2 GW online in 2021 and 2022 against PJM's 5.6 GW, despite PJM being more than twice its size, and interconnection runs roughly two to three and a half years against six or more elsewhere. It also proves the reliability objection is answerable, because ERCOT has operated this way for close to two decades. **What it does not prove.** ERCOT is a single-state interconnection largely outside FERC jurisdiction, which removes a coordination problem every other region has. It is also an energy-only market, and this program deliberately does not import that feature. The most common error in citing Texas is to treat connect and manage and energy-only as a package; they are separable, and this program takes the first without the second. ERCOT's own timelines have also drifted as its queue has grown, with median storage interconnection moving toward four years, so connect and manage is faster rather than immune to process congestion. **The misattribution to correct.** Winter Storm Uri in 2021 is routinely offered as proof that the Texas model fails. The joint FERC and NERC inquiry attributed the outages predominantly to generator freezing and natural gas fuel supply failures. No interconnection study prevents a plant from freezing. Uri is an argument about weatherization standards and gas system reliability, and it is not an argument about interconnection policy. **What this initiative should do differently.** Pair connect and manage with proactive network planning, and publish curtailment statistics by node so developers can price the risk instead of guessing at it. ### South Australia: dynamic operating envelopes **What happened.** Since July 2023, essentially all new exporting solar systems in South Australia must be capable of dynamic export control, and SA Power Networks now offers flexible export connections across its territory, including on rural single-wire earth-return lines. Other Australian networks are implementing through 2031. **What the evidence establishes.** That real-time, location-specific export limits can be the default connection standard for ordinary residential customers rather than a pilot for sophisticated participants, and that the engineering and the customer experience both hold up at population scale. **What it does not prove.** Australia has national appliance and inverter standards, a different regulatory architecture, and a rooftop solar penetration that forced the issue. The enrolled and actively managed population is also smaller than the capable population, so claims about how many systems are under live envelope management should be made carefully. This paper's own earlier drafts overstated exactly that point and were corrected. **The lesson.** Envelopes without a market signal are rationing. They solve the hosting-capacity problem and leave the value question unanswered, which is why this program pairs them with posted locational offers. **What this initiative should do differently.** Mandate the capability at the inverter standard instead of negotiating it connection by connection, and publish envelope utilization data so that a customer who is frequently curtailed can see it and a developer can price it. ### France: the capacity obligation **What happened.** France operates a decentralized capacity mechanism in which suppliers must hold certificates covering their customers' contribution to peak demand, with certificates issued to capacity providers on the basis of certified availability. **What the evidence establishes.** That an obligation placed on load-serving entities is an administrable alternative to a centralized capacity auction, and that certificates and bilateral contracting can coexist with regulatory oversight. **What it does not prove.** France has a dominant state-linked incumbent generator and a market structure unlike any US region, and its mechanism has been criticized for illiquidity and for the market power that follows from concentration. It is a design reference rather than a demonstration that the model works in a market with PJM's diversity of participants. **What this initiative should do differently.** Take the obligation structure and add what France's critics say is missing: mandatory registration and publication of positions, standardized products to build liquidity, physical backing requirements, and independent verification. An obligation regime without those is less transparent than the auction it replaces, which is the strongest objection to Principle 5 and the one that must be designed out rather than argued away. --- ## Part two: the domestic proof points Each of these shows the cheaper option working, and each required either a bespoke regulatory carve-out or a utility outside the investor-owned incentive structure. That pattern is the diagnosis restated as evidence. ### Consolidated Edison, Brooklyn-Queens Demand Management Con Edison avoided roughly a billion dollars of substation and grid investment by procuring about $200 million of demand reduction, efficiency, and distributed resources, roughly 52 MW of demand reduction plus 17 MW of distributed investment, under a program the New York Public Service Commission established in Case 14-E-0302 with a specific earnings mechanism attached. **What the evidence establishes.** That a large deferral is achievable in a dense urban network, and that a utility will pursue one when the regulator builds a way for it to earn from doing so. **What it does not prove.** The savings accounting is contested. Analysts calculated a full ten-year deferral cost closer to $855 million once traditional spending inside the program is counted, so the honest claim is that the alternative was materially cheaper rather than that a billion dollars vanished. The program also required an unusual regulatory construction that no other jurisdiction has replicated at that scale. **The lesson for design.** This case is the argument for independent review of shared-savings counterfactuals. A mechanism that pays a utility a share of avoided cost creates an incentive to overstate the avoided cost, and the first major American example of the mechanism produced exactly that dispute. Build the standardized counterfactual method before the first shared-savings dollar is paid. ### Arizona Public Service, Punkin Center APS installed a 2 MW, 8 MWh battery instead of rebuilding roughly 20 miles of rural distribution line through difficult terrain, deferring the rebuild by three to six years at roughly half the cost. **What the evidence establishes.** That storage substitutes for wires in exactly the way the theory predicts, in a real utility capital plan, with the utility's own numbers. **What it does not prove.** The system was placed on standby and disconnected in 2019 following an unrelated battery fire elsewhere on the utility's system, and APS subsequently sought buyers. It is an honest illustration of deferral economics and an equally honest illustration of early-storage operational risk. **The lesson.** Cite it with the coda. An advocate who presents Punkin Center as an unqualified success will be corrected by anyone who knows the file, and the correction will cost more credibility than the example was worth. Presented complete, it is stronger: the economics worked, and the technology risk of that era has since been addressed through revised safety standards. ### Sterling, Massachusetts The municipal light department's 2 MW, 3.9 MWh battery, commissioned in December 2016 at about $2.7 million with grant assistance, reports roughly $400,000 a year in avoided capacity and transmission charges. Sandia National Laboratories analyzed the estimate. **What the evidence establishes.** That the economics are available to a small utility with no sophisticated market apparatus, and that they can be captured without a rate case, a docket, or a bespoke earnings mechanism, because a municipal utility does not earn a return on rate base and therefore faces no bias against the cheaper option. **What it does not prove.** A municipal utility's cost of capital, tax position, and governance differ from an investor-owned utility's, so the financial case does not transfer line for line. **The lesson, and it is the most important one in this section.** Sterling is the cleanest evidence for the central claim of this program. Remove the payment formula that rewards capital, and the cheaper option gets chosen without anyone needing to be persuaded. The reform generalizes to investor-owned utilities what public power gets structurally. ### American Electric Power, Lower Rio Grande Valley AEP reconductored 240 energized line-miles of 345 kV transmission on existing structures, replacing conventional conductor with advanced composite-core conductor, roughly doubling capacity, finishing eight months ahead of schedule and under budget, and winning an industry award for the work. **What the evidence establishes.** That reconductoring at scale is an executable construction program rather than a modeling exercise, on live lines, in an American utility's hands. **What it does not prove.** Some of the associated figures, including line-loss reduction and generation-capacity value, are vendor-reported and should be labeled as such. And the peer-reviewed national analysis showing that advanced conductors can roughly double corridor capacity at about half the cost of new build carries real conditions: results depend on conductor selection, thermal limits, and structural condition, and not every corridor qualifies. The national cost comparison should rely on the peer-reviewed estimates rather than on the AEP project itself. **What has changed since.** The Department of Energy closed a loan of up to $3.26 billion to AEP Texas in July 2026 to rebuild, reconductor, or build more than 2,800 miles of transmission, targeting a doubling of carrying capacity. Reconductoring is now being financed at federal program scale, which moves the case from demonstration toward practice. ### Google, Indiana Michigan Power and the Tennessee Valley Authority Google signed demand-response agreements in August 2025, the first targeting machine-learning workloads, and by March 2026 reported roughly a gigawatt of contracted data-center demand response with US utilities. **What the evidence establishes.** That the flexibility trade at the heart of Principle 4 is commercially demonstrated in an early-stage deployment, that a hyperscaler will accept curtailment terms in exchange for access, and that the counterparty utilities include both an investor-owned utility and a federal power authority. **What it does not prove.** Curtailment performance has not yet been tested through a sustained system emergency, and the agreements are recent enough that measurement and verification practice is still forming. A Department of Energy review in 2024 could identify no examples of grid-aware flexible data center operation other than Google's, which means this is one firm's practice rather than an industry norm. **What this initiative should do differently.** Standardize the product in tariff instead of leaving it to bilateral negotiation, and require ex-post verification against telemetry with a penalty price that exceeds the value of non-performance. A flexibility commitment that is never tested is a reliability assumption, not a reliability resource. --- ## Part three: the cautionary record ### FERC Order 1000, and how a pro-competition order was absorbed **What happened.** FERC removed the federal right of first refusal in 2011 and required competitive solicitation for certain transmission projects. Roughly 2 to 3 percent of transmission investment has since gone through a competitive process, meaning about 98 percent of ISO and RTO transmission investment is still awarded outside one. Projects awarded outside competition ran roughly 34 percent above their initial cost estimates, while winning competitive bids came in about 40 percent below, usually with cost caps. These figures are descriptive comparisons across different project populations and cost baselines; they should not be read as a causal estimate of the savings from competition. **How it was absorbed.** Three mechanisms, all of which this program must expect. Categorical exemption: in New England, transmission owners identify "asset condition" projects themselves, outside the regional planning process, and those projects are cost-allocated across the region exactly like the projects the operator selects. They grew from $58 million when tracking began in 2016 to more than $2.787 billion by early 2023, with annual spending rising eightfold to nearly $800 million and several billion more expected. No such project has ever been modified or rejected by the reviewing committee, and the Asset Condition Reviewer created in response to that criticism has no authority to modify or reject anything. Threshold and voltage screens, which invite a large program to be presented as a series of smaller ones. And state legislation: roughly ten states enacted rights of first refusal restoring incumbent rights after the federal one was removed. **What it proves, and this is the most useful lesson in the paper.** A reform that polices the incumbent's behavior while leaving the incumbent's payoff intact will be absorbed. Rules that police categories lose to recategorization. Rules that police dollar thresholds lose to splitting. And a federal rule can be reversed at the state level by the same firms that lost at the federal level. **What this initiative does differently.** The reconductor-first requirement applies to a rolling twelve-month portfolio on a corridor or substation rather than to individual projects, so splitting gains nothing. It permits no categorical exemption for asset condition, local reliability, or maintenance, because those are precisely the categories that absorbed Order 1000. The reviewer has authority to reject and to require an alternative, not merely to comment. And the full project list, with costs and justifications, is published in machine-readable form so that third parties can find aggregation patterns the reviewer misses. Underneath all of that sits Principle 1, which is the real protection: under a total expenditure allowance the utility earns the same whether it builds or procures, so recategorizing yields nothing, and under peer benchmarking the allowance comes from what comparable utilities achieve rather than from how this one describes its own work. A firm can recategorize its projects. It cannot recategorize the benchmark. ### California, 2000 and 2001 **What happened.** California's restructuring collapsed into rolling blackouts, utility insolvency, and a national retreat from retail competition that has not fully reversed in twenty-five years. **What it actually shows.** The design barred utilities from forward contracting while exposing them to spot markets under frozen retail rates, and market participants exploited the resulting position. Post-mortems by Borenstein, Bushnell, Wolak and others attribute the failure to that design and to manipulation rather than to competition as such. **Why it matters here.** Principle 5's central requirement is mandatory forward physical hedging. The mechanism at the heart of this program is the specific antidote to the failure that ended the last restructuring wave. The California comparison will be raised whether or not it is apt, and the accurate answer converts the most damaging precedent in the file into support for the design. **The lesson that still binds.** Sequencing and design detail are the whole thing. California did not fail because reform is impossible; it failed because a specific combination of features created an uninsurable position for a regulated entity. Any reform program should be examined for the equivalent, which is why Papers III and V both carry an explicit failure-modes section. ### FERC Order 2222 Issued in 2020 to open wholesale markets to aggregated distributed resources, its implementation dates now run to late 2026 in New England, 2028 in PJM, 2029 in MISO, and 2030 in SPP. The lesson is about enforcement rather than design: an order without deadlines and consequences becomes a compliance negotiation. It is also a caution about relying on federal action for anything time-critical in this program, which is one reason the roadmap runs the state track independently. ### Boulder, Colorado Boulder pursued municipalization for roughly a decade, spent about $28.7 million, and abandoned the effort in 2020 without acquiring a system. Roughly a dozen communities have municipalized in two decades, and most attempts are abandoned or rejected. This answers the reasonable question of why the program does not simply advocate public power. Acquiring a utility takes a decade per jurisdiction and usually fails, while changing the payment formula reaches the three-quarters of load investor-owned utilities serve and can begin with a docket. ### Ohio, House Bill 6 A roughly $60 million scheme secured a legislative bailout, produced the largest utility corruption case in American history, and sent the speaker of the Ohio House to federal prison. It is cited here not for shock value but because it establishes the outer bound of the capture problem the anti-capture provisions address: funded intervenors, open data, peer benchmarking, and the ratepayer-funded lobbying bans now enacted in Colorado, Connecticut, Maine, Maryland, and California. --- ## Part four: what the record adds up to Five conclusions follow from reading these cases together. **The feasibility question is answered and the effect question is not.** Every component of this program runs somewhere, which disposes of the claim that any of it is untested. What no jurisdiction has produced is a clean American effect study of a totex transition against its own rate base and load mix. That gap should be closed deliberately, by commissioning the incidence study alongside the first performance-regulation docket, with the evaluation design registered in advance. **The failure modes are known and they are specific.** Over-earning in the first control period, absorbed reform through recategorization, opaque bilateral positions, inflated shared-savings counterfactuals, unverified flexibility. Every one of these has an instance in the record above, which means every one can be designed against instead of discovered. **The reforms that change payoffs survive; the reforms that police conduct get absorbed.** Order 1000 is the control group for this proposition and RIIO is the treatment. That asymmetry is the strongest single argument for sequencing Principle 1 first. **Small American proof points share a revealing property.** Every domestic deferral success in this file required either a bespoke regulatory mechanism or a utility that does not earn a return on rate base. The exception proves the rule, and Sterling is the exception. **The strongest precedents cut both ways.** Britain proves the framework works and that its calibration is hard. Texas proves speed and reveals its own queue drift. Punkin Center proves the economics and ended in retirement. Con Edison proves the deferral and produced a contested accounting. --- ## Reading guide: which case for which audience | Audience | Lead with | Because | Do not lead with | |---|---|---|---| | Commissioner | Hawaii, Docket 2018-0088 | It is an American commission acting under existing authority | Britain, which invites the different-country objection first | | Legislator | The lobbying-cost bans, and Connecticut pairing performance-based regulation with one | Concrete, bipartisan, recently enacted | RIIO mechanics, which lose a room | | Utility executive or board | RIIO returns and the WPD sale premium | The failure mode was earning too much, and an acquirer paid up | Con Edison, which reads as a threat to rate base | | Consumer advocate | Sterling, and the delivery-versus-supply data | Cheaper option, no rate case, and bills that show the pattern | Texas, which carries the Uri association | | Large load buyer | Google with I&M and TVA | Their own peer, already contracted | France, which is remote from their experience | | RTO stakeholder | Order 1000 and asset condition spending | It is their own record, and it is not defensible | Anything implying the RTO staff are the obstacle | | Journalist | The Order 1000 absorption story | It is a documented, checkable failure with a clear mechanism | The full five-reform program, which does not fit a story | --- ## Sources Great Britain: Ofgem RIIO framework documentation, RIIO-2 and RIIO-ED2 final determinations, and RIIO-2 regulatory performance data (2024, 2025); National Audit Office, *Electricity Networks* (2020); Competition and Markets Authority determination (2021); Oxera, RIIO-2 final determinations review (2021); National Grid and PPL disclosures on the Western Power Distribution transaction (2021); Utility Week reporting of Ofgem commentary on the transaction premium. Hawaii: Hawaii Public Utilities Commission, Docket 2018-0088, Decision and Order (2020). Texas: Tyler H. Norris, "Beyond FERC Order 2023" (Nicholas Institute, Duke University, 2023); S&P Global and Utility Dive reporting on comparative interconnection volumes and timelines; FERC, NERC and Regional Entity joint inquiry, *The February 2021 Cold Weather Outages in Texas and the South Central United States* (2021). Australia: South Australia Office of the Technical Regulator, Dynamic Export Requirements (2023); SA Power Networks statewide Flexible Exports materials (2025); ARENA and AEMO, Project EDGE and Project Symphony. France: RTE documentation of the French capacity mechanism; Cramton and Stoft on capacity market design (2006). Domestic cases: New York PSC Case 14-E-0302 and Consolidated Edison BQDM filings, with contemporaneous critical analysis of the program's net savings; Arizona Public Service materials on the Punkin Center battery (2017 and 2018) and subsequent disclosure of its 2019 standby and disconnection; Sandia National Laboratories analysis of the Sterling Municipal Light Department system (2017); AEP, WSP, Quanta and CTC Global materials on the Lower Rio Grande Valley reconductoring, with vendor-reported figures identified as such; US Department of Energy, Energy Dominance Financing loan to AEP Texas (July 2026); Google demand-response announcements with Indiana Michigan Power and TVA (2025) and subsequent scale reporting (2026). Cautionary record: Brattle Group analyses of competitive transmission under Order 1000; Concentric Energy Advisors, *An Updated Examination of FERC Order No. 1000 Projects* (2024); New England States Committee on Electricity letter to ISO-NE on Asset Condition Projects (2023); RMI, *Mind the Regulatory Gap* (2024); Borenstein and Bushnell, "The U.S. Electricity Industry After 20 Years of Restructuring" (2015) and Wolak's CAISO Market Surveillance Committee analyses; FERC Order No. 2222 compliance dockets; Brattle, *Electric Utility Municipalization* (2025) and reporting on Boulder's effort; Department of Justice deferred prosecution agreement and sentencing records in the FirstEnergy matter. \pagebreak # The Champion's Toolkit ### What to say, what to do first, and what to say when someone objects *Companion to the series "The Great Inversion."* --- ## The case in one minute Electricity became cheap to produce. Connecting it became expensive and slow. Utilities still earn a return on capital they deploy, so they keep deploying capital. Competition stalls at the interconnection queue. Bills rise. Five principles change that. Each has a menu of mechanisms evaluated and a stated preference. And states can start most of the preferred ones without Congress, without new spending, and without waiting for anyone else. --- ## Your role ### Governor **Your headline.** Lower electricity costs without a new subsidy program. **What you do first.** Call on your commission to open a performance-regulation docket, and require your utilities to publish interconnection metrics and hosting-capacity maps on a fixed schedule. Neither needs an appropriation or federal permission. In the roughly ten states that elect their commissioners, including Georgia, Arizona, Louisiana, and Oklahoma, this is a public case to make rather than an order to give, which changes the tactics and not the substance. **Why it is safe.** Hawaii's commission has regulated utilities on performance since 2020. Britain has since 2013, and its networks kept investment-grade credit while earning roughly 9 percent real on equity against a 5 to 6 percent national average, which is the opposite of the underinvestment risk critics raise. You are adapting a mechanism that already operates in the United States and abroad. **What you can announce.** A rate-relief agenda that assigns the costs of large new loads to those loads, publishes what utilities charge and why, and pays them for outcomes instead of for spending. ### Public utility commissioner **Your headline.** Modernize the incentive, and get better data while doing it. **What you do first.** Open a docket on total-expenditure regulation with peer benchmarking, and order machine-readable hosting-capacity and planning data as a condition of the next rate proceeding. **Why it is safe.** The mechanism is documented in Hawaii Docket 2018-0088 and in Ofgem's published RIIO framework, including the parts that went wrong and were recalibrated. You can adopt the design with the correction already in hand. **What it does for your docket load.** Multi-year revenue caps with formula updates reduce the frequency and stakes of contested rate cases. The tradeoff is a higher analytic burden at the front end, which is an argument for funded intervenors and shared benchmarking data across states. ### Legislator **Your headline.** No federal spending, no federal permission required. **What you do first.** Sponsor enabling legislation covering three things: authority for performance-based regulation, a statutory right to a standardized connection pathway for resources that satisfy published technical requirements, and a standard value-stack tariff that updates on a schedule and never retroactively. **Why it is safe.** Every element exists in another jurisdiction today. The bill authorizes your commission to do what Hawaii's already does, and gives distributed energy the predictability that has been the industry's consistent request, which matters more to capital formation than the compensation level itself. **The line that travels.** This is not a subsidy program. It changes what regulated monopolies get paid for. ### Utility executive or board member **Your headline.** You can earn more by performing than by spending, and the transition is designed to be financeable. **What you do first.** File a multi-year plan under a total-expenditure framework, and support Principle 1 before Principles 2 through 5 are decided. The sequence matters to you: the reform that changes what you earn on comes before the reforms that change what you control. **Why it is safe.** Under Britain's framework, networks maintained investment-grade credit and outperformed their allowances often enough that the regulator's recurring problem was clawing back excess returns. In-flight capital plans grandfather into the baseline at approved values. Storm hardening, wildfire mitigation, and cyber defense are funded in full, because total-expenditure regulation removes the accounting preference, not the money. **What you give up.** Automatic rate-base growth, and the gatekeeper's chair. What replaces it is a share of every deferral you procure more cheaply than the wires solution. ### Consumer advocate **Your headline.** Costs land on the customers who cause them, and predictable bills become the default. **What you do first.** Intervene for three specific protections: hedged flat products available by default alongside time-varying rates, transition-year bill protection, and a large-load tariff that assigns capacity cost to new large loads instead of socializing it. **Why it is safe.** The status quo is not neutral. Flat volumetric rates already transfer money from customers who cannot shift usage to those who can, and PJM's capacity costs rose from $2.2 billion to $16.4 billion a year across four auctions, spread across every household in thirteen states and the District of Columbia. ### Large-load buyer: data centers, manufacturers, industrial customers **Your headline.** Power years sooner, in exchange for flexibility you can schedule. **What you do first.** Offer verified curtailability during the top 50 to 100 system hours in exchange for fast-track interconnection. The same fast-track tariff must be available on standardized terms to qualifying industrial, commercial, and public loads, not only hyperscalers. Then support obligation-based resource adequacy in RTO stakeholder proceedings. **Why it is safe.** Google signed exactly this structure with Indiana Michigan Power and the Tennessee Valley Authority in 2025 and has since contracted roughly a gigawatt of data-center demand response. Duke's Nicholas Institute estimates that modest curtailment flexibility could open on the order of 100 GW of headroom on the existing grid. ### Investor or developer **Your headline.** Contracted revenue instead of an auction that has hit its price cap four times running. **What you do first.** Support a staged transition toward obligation-based reliability procurement, beginning with standardized bilateral contracts and a residual centralized backstop, in RTO stakeholder processes, and press for the standard value-stack tariff at the state level. Both convert political variables into underwritable ones. --- ## The minimum viable package A small state, or a commission with limited staff, does not need the full program; the hundred-day package is the ask, and the framework is the justification. Six functions carry most of the value, and each can be satisfied by more than one mechanism. **Transparency.** Publish hosting capacity, interconnection metrics, and avoided-cost values. **Access.** Give resources meeting published technical limits a standardized connection pathway. **Accountability.** Tie some portion of utility revenue to measured outcomes. **Valuation.** Let location and timing affect what a resource earns. **Risk allocation.** Put incremental system cost with the load that creates it. **Competitive neutrality.** Procure competitive services competitively where practical. Everything else in this program is implementation detail on top of those six. ## The first 100 days A commission can begin most of the program immediately; legislation and federal approvals become necessary for some later stages. 1. **Publish interconnection metrics** on a fixed schedule: days from application to study, days to a connection offer, withdrawal rates, and the queue by voltage level. What gets measured gets contested, and what gets contested gets faster. 2. **Publish hosting-capacity maps and feeder deferral values** in machine-readable form, so a third party can see where capacity exists and what avoiding an upgrade is worth. 3. **Open a performance-regulation docket** with a scope that names total-expenditure treatment, peer benchmarking, and shared savings for non-wires alternatives. 4. **Approve a flexible-connection tariff** so small resources can connect inside published operating limits instead of waiting for a bespoke study. 5. **Open a large-load tariff proceeding** that assigns capacity and network costs to new large loads and offers fast-track service in exchange for verified curtailability. 6. **Require alternatives analysis before major network spending** so non-wires and reconductoring options are priced against new construction before approval. 7. **Independently verify reliability and flexibility claims** with telemetry-settled measurement, so promised flexibility is a product rather than a hope. --- ## The scorecard: how a commission knows it worked Fourteen measures in four categories, each drawn from reporting a commission can already require. The categories matter: a scorecard that tracks only consumer outcomes reads as an attack on utilities, and one that tracks only utility performance reads as capture. Publish them annually, benchmark them against peer states, and the program stops being a promise and becomes a management framework. **Consumer** | Measure | What it tells you | Source | |---|---|---| | Delivery charge growth against CPI | Whether the reform reaches the bill | Tariff filings and BLS | | Median days from interconnection request to executed agreement | Whether access is getting faster | Utility and RTO queue records | | Outage duration and frequency | Whether reliability held through the transition | Existing SAIDI and SAIFI reporting | **Competition** | Measure | What it tells you | Source | |---|---|---| | Share of requests withdrawn after study completion | Whether the process is destroying viable projects | Queue records | | Hosting capacity published, and its utilization rate | Whether headroom is visible and being used | Utility hosting-capacity maps | | Interconnection cost assigned per megawatt connected, by voltage and project size | Whether upgrade costs are being reassigned to developers rather than avoided | Interconnection agreements and utility filings | **Utility** | Measure | What it tells you | Source | |---|---|---| | Distribution capital per customer, against peer states | Whether spending is disciplined by comparison | FERC Form 1 | | Operating and capital expenditure mix | Whether the build-or-buy choice has actually changed | FERC Form 1 and distribution plans | | Non-wires alternatives procured as a share of deferred capital | Whether cheaper solutions are winning | Utility distribution plans | | Realized return on equity against authorized return, and against output performance | Whether earnings track performance rather than spending | FERC Form 1 and annual reports | | Rate case frequency and duration | Whether multi-year frameworks are reducing litigation | Commission dockets | **System** | Measure | What it tells you | Source | |---|---|---| | Large-load capacity cost recovered from large loads | Whether incidence has shifted off households | Rate case records | | Curtailment hours per connected megawatt | Whether faster connection is trading away too much delivered energy | RTO and utility operations data | | Reserve margin against target | Whether resource adequacy held | RTO and state reporting | **Causal evaluation.** Every participating state should publish a pre-reform baseline and identify a peer comparison group. Success should be judged against the counterfactual, not against the state's own forecast. The consumer and competition measures move within a year and are the early signal. The utility measures move over a control period. The system measures are the durable test, and they are the ones to put in front of a legislature at the five-year mark. ## When the incumbent makes its pitch Every statehouse hears the same three-part pitch: we know how to stop blackouts and you don't; speculators are gaming the queue and should pay more for access; and nobody employs more skilled workers in your district. Each part contains something true, which is why the answer to each starts with a concession and ends with the trade the incumbent is not offering. **Concede operations first, and completely.** Nothing in this program moves a truck, a lineworker, or a storm response. Engineering limits stay with the engineer, and performance regulation pays the utility more, not less, for operating well. Say this before anything else, because every utility argument gains its force by blurring the access decision into the operating job. **Then flip the blackout card.** The institution claiming that only it can keep the lights on is holding two thousand gigawatts of willing supply in its waiting room, at a median wait above five years, with thirteen percent ever reaching service. A queue that holds willing supply out of service is itself the reliability risk. A governor does not have to choose between reliability and reform; the reform is the reliability program. **Flip the speculator card with a concession.** Screening is legitimate, which is why this program uses published criteria, deposits, and readiness tests instead of discretion. But note who defines the word: to the party that owns the gate and sells the competing product, a speculator is a competitor by another name. And the incumbent remedy of paying more to wait longer invites the exit it warns about: large customers and generators are already pricing life off the grid. Every megawatt that leaves takes its contribution to the wires with it, and the households left behind absorb the difference. The utilities' own revenue base is the strongest argument against their own proposal. **Take the jobs card rather than disputing it.** Totex funds the full capital program, and reconductoring, storage, hardening, and interconnection build are union work either way. More projects connected is more work done; the current system produces less construction and more litigation. **The ask.** Stop refereeing blame between the utility and its customers. Change what the utility earns and who keeps the gate, and the fights become bids. ## When someone objects **"Isn't this deregulation?"** No. It regulates the monopoly more tightly, through revenue caps, peer benchmarking, and published performance data, and it opens to competition only the parts that are not a monopoly. Wires stay a regulated monopoly. Generation, storage, and flexibility are not monopolies and have not been for thirty years at the wholesale level. **"Doesn't dynamic pricing hurt low-income customers?"** Only if it is designed carelessly, and the status quo already hurts them. Flat volumetric rates transfer money from customers who cannot shift usage to those who can. Default time-varying rates ship with hedged flat products for anyone who wants a predictable bill, transition-year bill protection, and targeted low-income rates. **"Britain and Australia are different countries."** They are, and the mechanism being borrowed is a payment formula, not a culture. A revenue cap tied to measured outputs works the same way in Honolulu as in Birmingham, which is why Hawaii adopted it. Every step in this program is available under existing US state and federal authority. **"Won't utilities fight this?"** Initially, and the sequence answers that. Principle 1 changes what utilities earn on before Principles 2 through 5 change what utilities control, which is why it goes first. Transmission open access was fought bitterly in the 1990s, imposed anyway, and is now defended by many of the interests that opposed it. **"Doesn't Texas have blackouts?"** Connection reform and an energy-only market are different things, and this program takes the first without the second. ERCOT's 2021 failure traced to plant weatherization and fuel supply in the joint FERC and NERC inquiry, which no interconnection study prevents. What Texas demonstrates is speed: 14.2 GW brought online in 2021 and 2022 against PJM's 5.6 GW, at less than half PJM's size. **"Why isn't the answer just public power?"** Municipal utilities do charge less, and that record deserves respect. But the comparison does not prove what it appears to prove. In 2024 the average residential bill ran $123.78 at public power utilities, $139.42 at investor-owned utilities, and $149.18 at cooperatives, which are also not-for-profit and also earn no return on rate base. Co-op customers pay the most mainly because co-ops serve low-density rural territory, which is the lesson: cost follows structure and circumstance, not ownership form. The municipal advantage comes largely from tax-exempt debt, exemption from income and property tax, and first claim on federal hydropower at cost. Those are transfers, not efficiencies, and they do not scale, since municipalizing more utilities creates no additional federal dams. Ownership also leaves the binding constraint untouched: a municipal utility inside PJM sits in the same interconnection queue and pays the same capacity charges. On permission it can be worse, because municipal utilities and co-ops are exempt from state interconnection and net-metering rules in many states, so a restrictive distributed-energy policy faces no commission and no appeal. And the path is punishing: roughly a dozen communities have municipalized in two decades, most attempts are abandoned, and Boulder spent ten years and $28.7 million before giving up in 2020. The strongest version of the answer is that public power is evidence for this diagnosis rather than an alternative to it. A utility that earns no return on rate base shows no capital bias, which is precisely the claim being made here. Sterling, Massachusetts is in the case evidence for that reason. These reforms are what make any owner perform, and public power can adopt them faster than anyone, by board vote and with no rate case. **"Doesn't faster connection just help gas?"** Gas is now the largest single block in PJM's reopened queue, at 106 GW, precisely because a slow queue favors developers who can afford to wait. Rules-based access is technology-neutral and helps whoever can build fastest, which today includes storage, solar paired with storage, and demand flexibility. Nearly half the solar capacity in queues is now paired with batteries. **"This sounds like European regulation."** and **"This sounds like deregulation."** Both objections get raised, from opposite directions, about the same program. That is a sign the program is neither. It is competition where competition works, and tighter, better-instrumented regulation where it does not. --- ## Running the campaign against the opposition Investor-owned utilities are likely the strongest opposition to this program, they fight where the reforms are actually decided, and they have historically fought with their customers' money. Four tactics follow from that. **Start by making the opposition self-funded.** Before the reform fight, pass the ban on recovering political and lobbying costs from ratepayers. Colorado, Connecticut, and Maine enacted comprehensive versions in 2023 with bipartisan support, covering lobbying, trade association dues, advertising, and grassroots campaigns. Maryland followed in its Next Generation Energy Act, and California's 2025 Ratepayer Protection Act became the first to mandate financial penalties rather than leaving them to regulator discretion. Roughly eighteen states have introduced versions. The effects are documented and immediate: Colorado regulators rejected more than $775,000 in lobbying fees, trade association dues, and investor relations costs from Xcel in a single gas rate case; Connecticut regulators denied over $617,000 from Avangrid and have spared customers up to $10 million; and California's Public Advocates Office found that SoCalGas charged ratepayers $29.1 million between 2019 and 2023 for lobbying against building electrification, after a $10 million penalty in 2022. This bill is independently popular, it passes on bipartisan votes, and it shrinks the war chest that will be aimed at everything else you do. Note also the pairing: Connecticut paired performance-based regulation with a lobbying ban in the same period. **Then make the opposition's spending the scoreboard.** The Connecticut and Maine statutes require utilities to file itemized annual reports of political expenditures, which means the disclosure infrastructure is statutory rather than journalistic and the numbers are the company's own. The message writes itself and is documentable rather than alleged: this company spent this much money opposing a bill that would lower your bill, and here is their filing saying so. Rising opposition spending is evidence the reform is working, and it should be published as a campaign metric on that basis. The Energy and Policy Institute already maintains national tracking. **Use the new asymmetry.** Every previous attempt to reform utility regulation pitted diffuse consumer interests against a concentrated incumbent. That is no longer the shape of the fight. Hyperscale load buyers now have a direct commercial stake in connection speed, lobbying capacity comparable to the utilities', and no legacy rate base to protect. Recruiting them is the single largest change in the balance of forces since restructuring, and it costs the coalition nothing to organize. **Contest the commissions, where they are elected.** In roughly ten states, including Georgia, Arizona, Louisiana, and Oklahoma, commissioners stand for election in low-turnout races that are inexpensive by the standards of statewide campaigns. For a reform program whose center of gravity is the state commission, those are the races where a single seat moves the most policy in the sector. *Sources: state statutes and commission decisions in Colorado, Connecticut, Maine, Maryland, and California; Energy and Policy Institute tracking of utility political spending; California Public Advocates Office filings on SoCalGas expenditures; PowerLines rate-case tracking.* Two defensive notes. Expect a right-of-first-refusal response, because after FERC opened transmission to competition in 2011 roughly ten states legislated incumbent rights back into place, and expect recategorization of spending to escape any threshold you write, which is why the reforms are drafted against portfolios rather than projects. And expect the fight to be at the statehouse rather than in Washington, because that is where four of the five principles are decided. ## Sample language **Docket-opening language for a commission.** > The Commission opens this proceeding to consider a multi-year performance-based regulatory framework for [utility], including: (1) a total-expenditure allowance that treats capital and operating expenditures equivalently for cost-recovery purposes; (2) performance incentive mechanisms tied to measured outputs including interconnection cycle time, hosting capacity made available, peak demand served per dollar of network investment, and reliability; (3) benchmarking of allowed revenue against comparable utilities in other jurisdictions; and (4) a shared-savings mechanism under which the utility retains a defined share of the verified savings from non-wires alternatives procured in place of network investment. **Findings language for enabling legislation.** > The Legislature finds that: (a) the cost of new generation and storage has declined substantially while retail electricity rates have risen faster than inflation; (b) the principal constraint on new supply is the time and process cost of interconnection rather than the availability or price of generating resources; (c) existing cost-of-service ratemaking compensates utilities for capital deployed rather than for outcomes delivered, and therefore does not reward lower-cost alternatives to network construction; and (d) the public interest requires that the Commission be authorized to establish multi-year, performance-based revenue frameworks and to establish rules-based interconnection rights within published operating limits. *Both passages are illustrative drafting templates, and should be conformed to the jurisdiction's own ratemaking statutes and administrative procedure requirements before filing.* --- ## What to hand people The two-page executive summary for a principal. The six-page policy brief for staff who will draft. Paper III for the reform detail, the coalition map, and the roadmap. Paper II for the evidence and the objections answered at length. The press kit for verified figures with sources. \pagebreak # Cheap Supply, Scarce Connection ## A policy brief for commissioners, legislators, and federal regulators *Condensed from the series "The Great Inversion." Citations refer to the full papers' source lists.* --- ## 1. The problem The institutions governing electricity were built for yesterday's technology. Physical constraints are real, but the rules make manageable constraints behave like permanent exclusions. | Metric | Then | Now (2026) | |---|---|---| | Utility-scale solar LCOE | $359/MWh (2009) | $40-98/MWh, avg $69 (Lazard 2026) | | Battery pack price | ≈$1,475/kWh (2010, real 2025$) | $108/kWh; stationary $70 (BNEF 2025) | | Active interconnection queue | Fraction of the fleet (mid-2000s) | 2,061 GW, about one and a half times the fleet; 549 GW holds an interconnection agreement (LBNL 2026) | | Typical queue duration | <2 years (mid-2000s) | ≈5 years (LBNL) | | Queue completion rate | Majority connected | 13% of capacity (LBNL) | | Gas turbine lead time | ≈2 years (2019) | ≈5 years (S&P Global) | | Annual capacity cost | $2.2B (2024/25) | $16.4B (2028/29), 4 straight cap-bound auctions (PJM) | Electrons got cheap. Connection got scarce. The bottleneck is institutional, which is good news, because rules are cheaper to change than infrastructure is to build. A 500 MW load's engineering timeline is 12-18 months for solar-plus-storage; heavy-duty gas turbines and study-first interconnection each add roughly five years (PJM's average application-to-operation timeline now exceeds eight years, per RMI), while ERCOT-style rules cut connection to two or three and a flexibility agreement (per Google's 2025 deals with I&M and TVA, since scaled toward a contracted gigawatt) serves it in months. Procedure, not physics, sets the schedule. ## 2. Why this happened Three findings, each from a different discipline, jointly explain the pattern. **Ratemaking pays for capital.** A utility earning a return on invested capital will prefer a $40 million substation it earns on for forty years over a $2 million per year battery contract it earns nothing on (Averch-Johnson, 1962). Case evidence that the cheaper option works when someone is paid to choose it: Con Edison deferred roughly $1 billion of Brooklyn-Queens grid investment with ~$200 million of demand-side resources under a bespoke NY earnings mechanism (net savings contested, direction not); Arizona Public Service deferred a ~20-mile line rebuild with a 2 MW battery, since retired; Sterling, MA reports ~$400k/year on a Sandia-analyzed municipal battery. Each required a carve-out or public power, which is the diagnosis restated as evidence. The bias operates at every voltage: reconductoring can roughly double a line's capacity at roughly half the cost of new build where conductor and structural conditions allow (PNAS, 2024), and utilities rarely propose it, because a cheaper solution is smaller rate base. **Gatekeepers face no cost for delay.** Interconnection is run as discretionary, serial study by entities with weak incentives for speed. Texas is the most useful real-world comparison, a mechanism worth testing: ERCOT's connect-and-manage framework connects comparable resources several times faster, managing congestion through the market afterward. **The reliability construct collapsed under load growth.** Delayed auctions, overnight accreditation changes, and a decade of underestimated data-center demand produced a capacity market that has hit administrative caps four auctions running instead of discovering prices. Most recently it fell 6,623 MW short of its reliability requirement, with the costs of speculative load socialized onto all customers. The data centers themselves would rather contract for their own capacity; Google's 2025 curtailment agreements with Indiana Michigan Power and TVA show the demand for a product the institutions never offered. Utilities face real pressures (wildfire, storms, cyber, aging assets), and the diagnosis does not require bad faith anywhere. It requires only that people follow the incentives they are given. That is what makes it fixable. ## 3. The five principles, and the preferred mechanism under each Each principle carries a menu of mechanisms evaluated in Paper III, with a stance and an evidence tier for each, including the alternatives we set aside and the ones we reject. What follows is the principle and the preferred mechanism under it; a commission that reaches the same function by another mechanism has used this program effectively. **Principle 1. A utility should earn on outcomes delivered, not on capital deployed.** Preferred mechanism: performance-based regulation for wires. Totex revenue caps (erasing the capex/opex accounting line), output incentives tied to interconnection speed and hosting capacity, and yardstick benchmarking against peer utilities. Precedents: Ofgem's RIIO since 2013; Hawaii PUC Docket 2018-0088. British networks kept investment-grade credit and earned roughly 9 percent real on regulated equity under RIIO-1, against a 5-6 percent UK-company average, which the National Audit Office criticized as too generous. That is the message to carry into every utility conversation: the documented failure mode of performance regulation is utilities earning too much. **Principle 2. The party that owns the wires should not decide who may connect to them.** Preferred mechanism: an independent or ringfenced distribution system operator. Interconnection processing, hosting-capacity maps, envelope calculation, flexibility procurement, and data access move to an independent or ringfenced Distribution System Operator. Precedent: Britain's RIIO-ED2 licence conditions requiring functional separation from April 2023, plus outright separation of the national system operator (NESO, 2024). Principle: the owner of a bottleneck cannot referee access for its own competitors, the same logic as FERC Order 888. **Principle 3. Where and when a resource operates should affect what it earns.** Preferred mechanisms: the maturity ladder. Default dynamic retail rates with hedged flat options; posted, technology-neutral locational offers wherever deferral value exists on a feeder; dynamic operating envelopes replacing static interconnection caps (flexible exports are now the default connection standard for new South Australian solar). Full distribution nodal pricing waits until this substrate exists. **Principle 4. Access should follow published rules, not case-by-case permission.** Preferred mechanism: connect by published rules, both voltage levels. A standardized, software-screened pathway for small resources meeting published operating limits; connect-and-manage as the required pathway where technically feasible for bulk generation and large loads; Order 1920 enforcement plus reconductor-first showings before greenfield transmission; fast-track interconnection for hyperscale loads in exchange for verified curtailability during the top 50-100 system hours (Duke's Nicholas Institute estimates on the order of 100 GW of headroom from such flexibility). **Principle 5. Incremental system costs should sit with those who create them.** Preferred mechanisms: the large-load tariff first, incremental reliability obligations phased behind it. Each load-serving entity, hyperscale loads included, demonstrates forward physical or contracted coverage of its coincident-peak contribution, against a transparent penalty price; the centralized auction shrinks to a residual and sunsets. French precedent. For generators this means long-tenor contracts in place of an auction that paid $28.92/MW-day one cycle and $269.92 the next, an administrative cap it has since hit four times running; contracts are what project finance is built on. **What this is not.** No nationalization, no elimination of vertical integration where states prefer it, no forced retail choice, no DER mandates, no technology subsidies, no relaxed reliability standards. The objective: restore competitive markets wherever natural monopoly no longer exists, and regulate the remaining monopoly (the wires) on performance. ## 4. What it is worth **The system bottom line.** A scenario-based estimate suggests roughly $100-220 billion of avoidable generation capex if 100 GW of large-load growth is served through flexibility on the existing system (Duke estimate priced from EIA's $921/kW reference to observed market costs near $2,000/kW); doubled corridor throughput from reconductoring at about half the cost of new build (PNAS), now being financed at scale through DOE's $3.26 billion loan to AEP Texas for 2,800-plus miles; and each ten percentage points of improved queue completion connecting roughly as much capacity as the country added over the past decade (LBNL). Capacity-cost incidence shifts by design from households to the loads that drive the costs. **The consumer bottom line.** Electric bills have three cost drivers and the reforms discipline each: the supply line (cheap generation finally connects and competes), the reliability line (obligations move the $2.2B-to-$16.4B capacity escalation off households and onto the loads driving it), and the delivery line, now the fastest-growing part of many bills (totex reduces the financial preference for capital-intensive solutions behind 2025's record $31 billion in rate requests; reconductor-first buys transmission at roughly half greenfield cost; deferral savings are shared back). Protections ship with it: hedged flat options under default dynamic rates, transition bill protection, low-income rates, non-retroactive tariffs. The commitment is a published metric: real bill growth in participating states below matched peers. ## 5. Who must act | Actor | First moves | |---|---| | State PUCs | Totex performance-based regulation orders; default dynamic rates; automated interconnection screening; machine-readable planning data | | State legislatures | Performance-based regulation enabling statutes; separation of access administration; statutory right to connect; standard value-stack tariffs with scheduled, non-retroactive updates | | FERC | Rulemakings: connect-and-manage default; Order 2222 deadlines with penalties; Order 1920 enforcement; approve obligation transition tariffs | | RTOs/ISOs | Obligation accounting and settlement; large-load fast tracks; interregional planning | | Utilities | File performance-based regulation plans; stand up ringfenced DSO functions; reconductor-first showings | | Large loads and LSEs | Demonstrate forward hedges; standardize curtailability contracts | No core state reform requires new federal legislation; some federal reforms require FERC action under existing authority, and federal legislation (backstop siting, seam clarification) could accelerate or clarify the program without gating it. ## 6. Measures of success By 2030: small-resource interconnection in days; connection offers for bulk resources and large loads inside 18 months; five states under totex performance-based regulation; the first delivery year in which new data-center load demonstrably carries its own capacity. By 2035: queue conversion above half for mature cohorts; interregional transfer capability growing; real retail bill growth below matched peer states. The failure metrics of Section 1 provide the annual control chart. ## 7. Objections answered *"The queue is speculative":* largely true, and the speculation is the institution's product; slow studies with unpredictable cost allocation make multiple positions a rational option. Even at the historical 13 percent completion rate, today's queue implies ~270 GW of eventually built capacity, several years of additions at recent build rates, waiting on procedure. And 549 GW holds a draft or executed interconnection agreement, though over 40 percent withdraws even after that stage. Order 2023's deposits are already trimming the froth (the queue shrank 10 percent in 2025) without easing the scarcity. *"Connect-and-manage threatens reliability":* ERCOT has run it through nearly two decades of the nation's fastest resource growth, Britain adopted it in 2010, and ERCOT's real reliability failure (Uri, 2021) traced to weatherization and fuel in the FERC-NERC inquiry, which no interconnection study prevents. *"Utilities need capital":* agreed; totex funds hardening, wildfire, cyber, and replacement fully, and changes only the distorted choice at the margin (build vs. buy). *"DERs aren't dispatchable":* accreditation already answers this; PJM's demand-response accreditation moved from 69% to 92% between consecutive auctions as availability rules tightened, batteries respond sub-second, and Principle 5's obligation accounting prices every resource at its measured contribution. *Dynamic rates and vulnerable customers:* defaults ship with hedged options and bill protection; the flat status quo already transfers from inflexible to flexible customers. *Utility opposition:* Principle 1 comes first, changing the utility's payoff before anything moves its control, and the British record shows the framework preserving investment-grade financeability, with its documented early weakness being excessive outperformance, answered by tighter calibration rather than by financial distress. --- *Full argument, sources, coalition analysis, and international lessons: Papers I-III of "The Great Inversion" series. Dates and milestones: the path in the executive summary.* \pagebreak # America Doesn't Have an Electricity Shortage. It Has a Permission Shortage. *Op-ed, ~1,100 words* America has more proposed generation and storage waiting for interconnection than the country currently operates. That does not mean all of those projects are viable. It does mean the process for deciding which projects can connect has become a major constraint. Roughly 2,061 gigawatts, against about 1,400 gigawatts in service, sits in interconnection queues, and 549 gigawatts of it already holds a signed or draft connection agreement, according to Lawrence Berkeley National Laboratory. The typical project waits more than five years for an answer. Historically, only about one-eighth of queued capacity has reached operation. Hold that fact next to the others in the news. Data-center campuses that would pay a premium for electricity today cannot buy it, and gas turbine order books now quote deliveries near five years out. The capacity charges embedded in 67 million people's bills across the PJM region rose from $2.2 billion to more than $16 billion a year across four years of auctions, each of the last four hitting a price cap, one of them negotiated directly with a governor. Household electricity bills have become a campaign issue from Harrisburg to Richmond. The problem is not simply a shortage of generation technology or capital. It is the growing gap between what the system can produce and how quickly institutions can connect and coordinate it. Electrons have never been cheaper to produce; utility-scale solar's cost fell 84 percent since 2009 and battery packs fell 93 percent since 2010. The cheapest electricity ever generated is arriving alongside bills up a third since 2019. American electricity prices have outpaced inflation four times: the oil shocks of the 1970s, the nuclear overruns of the early 1980s, the natural gas run-up of the mid-2000s, and now. The first three had a cost story. This one does not, because what is scarce is permission: permission to connect to the grid, permission to compete on it, permission to be paid what a resource is worth. The bottleneck moved from the power plant to the paperwork, and households are paying the toll: supply that cannot connect, reliability charges socialized from data centers, and delivery spending that utilities are paid to maximize. The institutions are behaving exactly as they were built to. A regulated utility earns a return on capital it deploys, a formula set in 1907, so it prefers a $40 million substation it profits from for forty years over a $2 million a year flexibility contract it profits from never. The two are not the same asset, and the regulatory question is whether the service a feeder actually needs can be procured for less than the full infrastructure solution. Economists have understood the bias since 1962. It explains why utilities propose expensive new transmission lines when re-wiring existing ones with advanced conductors could double their capacity at a fraction of the cost, a finding published in the Proceedings of the National Academy of Sciences. It explains why interconnection stays slow: the entities running the queue bear no cost for delay. And it explains why the fastest fixes, batteries and flexible loads sitting exactly where the grid is strained, are paid under state programs rewritten every few years. Run the arithmetic for a single 500-megawatt data center. Building the solar and batteries takes 12 to 18 months. A new gas turbine arrives around 2031. A study-first interconnection queue delivers grid access around 2031 too. Texas-style rules deliver it around 2028, and a flexibility deal on the existing grid serves it in months. The engineering takes a year and a half; much of the remaining delay is institutional rather than equipment-related. There is a real-world comparison, and there are receipts. Texas connects new generation several times faster than the rest of the country by using a simple rule: connect quickly, manage congestion afterward through the market. In Brooklyn and Queens, Con Edison deferred roughly a billion dollars of substation and grid investment with about $200 million of batteries, efficiency, and demand reduction, once New York regulators built a mechanism letting the utility profit from the cheaper choice. Britain pays its grid companies for measured performance instead of capital spent, and its networks stayed profitable and investment-grade, earning about 9 percent on equity against a 5-to-6 percent national average. In South Australia, real-time connection limits are now the default standard for new rooftop solar. Hawaii rewrote utility ratemaking in 2020. Every major component has a precedent somewhere; none has yet been assembled at US national scale. No core state reform requires new federal legislation. The fix has five parts. Pay utilities for outcomes, so a battery contract and a substation compete on cost. Move the grid's referee functions, interconnection, data, operating envelopes, out of the companies that compete on the field. Price the grid's real scarcity by time and place, with protections for households that want flat bills. Make connection a rule rather than a queue, wherever technically feasible, with fast-track access for big loads that agree to power down during the few hours a year the grid is tight; Google already signed such agreements with utilities in Indiana and Tennessee. And stage a transition toward obligation-based reliability procurement: new large loads should carry the incremental reliability obligations their connection creates, so a data center's growth lands on the data center's books instead of on every household in thirteen states. The skeptics deserve straight answers. Yes, dynamic pricing must ship with hedged options for anyone who wants a predictable bill. Yes, utilities face real burdens, wildfires, storms, cyberattacks, and reform must let well-run companies earn more, which the British model demonstrably does. And yes, the transition must honor every contract already signed; the reforms of the 1990s showed how. But the largest fact in American energy is the one hiding in the queue. One of the country's largest pools of prospective infrastructure is already in development or awaiting connection. Unclogging it would do more for electricity bills, for AI and manufacturing competitiveness, and for the climate than any subsidy now being debated. The reforms require implementation work, but their principal tools are tariffs, regulation, and market design, not federal appropriations. Regulators wrote the rules that made connection scarce. Regulators can rewrite them, starting with two federal rulemakings and a handful of governors in 2027. The grid's institutions were rebuilt twice before, in 1907 and the 1990s, each time only after visible, expensive failure, each time over incumbent objection, and each time the objectors ended up defending the result. The failure is visible now. The electric bills are the evidence.