# Cheap Supply, Scarce Connection

### A policy brief for commissioners, legislators, and federal regulators

*From the series "The Great Inversion." Citations refer to the papers' source lists.*

The natural monopoly narrowed to the poles and wires, but most of the rules still bundle generation, data, access, and customer power and flexibility with it. A new agreement with new terms answers the questions the old deal left to the monopoly. Every principle has a working precedent, most mechanisms have close ones, and states can start without Congress.

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## 1. The problem

The technology changed. The natural monopoly narrowed. The rules haven't caught up. 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 of generation and storage, about one and a half times the generating fleet; 549 GW holds an interconnection agreement (LBNL 2026) |
| Median queue duration, request to operation | <2 years (mid-2000s) | More than 5 years, for projects built in 2025 (LBNL) |
| Queue completion | Majority connected | 13% of the capacity that entered from 2000 to 2020 (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. Much of 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

**The natural monopoly narrowed; the rules didn't.** The old monopoly bundled five functions: generation, the wires, grid information, access, and customer power and flexibility. Four can now be separated from owning the wires: generation and storage can be competitive, customers can supply power and flexibility themselves, information can be shared, and access can be governed by neutral rules. Only the poles, wires, and substations remain a natural monopoly. Reform did happen, and it changed procedures faster than it changed incentives and control. Independent operators run access to the big wires across much of the country, yet on the local wires the owner still holds much of the data, administers the connection process, and earns a return on what it builds.

**Ratemaking pays for capital.** The rules create a financial asymmetry: a $40 million substation earns an allowed return for forty years, and a $2 million per year battery contract that does the same job earns none (Averch-Johnson, 1962). Not every utility picks the substation, but the two options never arrive with the same incentive. 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 the incentive to propose it is weak, because a cheaper solution is smaller rate base. Twenty-three states have passed laws on grid-enhancing technologies and advanced conductors, many requiring study only, and the Department of Energy found that 7 percent of investor-owned utilities' transmission and distribution investment in 2023 went to advanced grid solutions.

**Gatekeepers have had little to lose from delay.** Interconnection has been run as discretionary, serial study by entities with weak incentives for speed. FERC's Order 2023 added cluster studies and the first penalties for late studies on the big wires; most local queues carry no such penalty. Texas is the most useful real-world comparison, a mechanism worth testing: ERCOT's connect-and-manage framework brought 14.2 GW of solar and storage online in 2021 and 2022 against PJM's 5.6 GW, at less than half PJM's size, managing congestion through the market afterward.

**The reliability market is failing to keep up with 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. It fell 6,623 MW short of its reliability requirement in December 2025 and 6,831 MW short in July 2026, 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 new agreement: five questions, five principles

Each principle carries a menu of mechanisms evaluated in Paper III, with a stance and an evidence tier for each, including the alternatives set aside and the ones rejected. A commission that reaches the same function by another mechanism has used this program effectively.

The diagnosis is five institutional failures. The five principles answer them, and the mechanisms under each are options: a state can hold to a principle and choose a different mechanism.

**How to read the evidence.** Some examples show a mechanism working at scale. Some show a narrower application. Some are analogies. None is offered as proof that the whole five-part program has been tested.

### Why does the owner of the wires act?

**Principle 1. A utility should earn on outcomes delivered, not on capital deployed.** A return on prudent investment stays; what goes is the extra reward for building over buying. 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. The documented failure mode of performance regulation is utilities earning too much.

### Who decides what connects?

**Principle 2. The company that owns the wires should not be the only one deciding who may connect to them.** The wires owner keeps engineering, safety, construction, and operations; what moves is the final say on access where ownership creates a conflict. 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.

### What do resources earn?

**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.

### How does access work?

**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).

### Who pays for new demand?

**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 recedes to a residual backstop wherever coverage passes the reliability-and-cost test, and stays wherever it does not. 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: complete the market where competition can work; strengthen regulation where monopoly remains. The wires stay a regulated monopoly; what changes is how it is regulated.

**What the argument does not claim.**

- That grid constraints are not real.
- That all new generation is cheap.
- That utilities act in bad faith. They respond to the incentives the rules set.
- That every interconnection delay is a utility's doing.
- That independent operators have solved access on the big wires.
- That Texas's whole market design should be copied.
- That performance regulation lowers costs automatically.
- That one mechanism fits every state.

## 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), with DOE lending AEP Texas up to $3.26 billion in 2026 for about 2,800 miles of rebuilt, reconductored, and new lines; 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. Expect public comments in rate cases that ask for the same three things in plain words: pay the utility for results, let someone neutral decide who connects, and publish the map and the rules to connect.

### First moves, by role

**Anyone who pays an electric bill.** Speak up at the utility's next rate case, in a short written comment or at the public hearing, and ask for three things: pay the utility for results, let someone neutral decide who connects, and publish the map and the rules to connect. Comments become part of the record, and specific, local comments carry the most weight. Speak Up at a Rate Case has the steps.

**Governor.** Call on the commission to open a performance-regulation docket, require utilities to publish interconnection metrics and hosting-capacity maps on a fixed schedule, and commit the administration to publishing the data and the consumer outcomes that result. Neither step 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. Hawaii has regulated utilities on performance since 2020 and Britain since 2013, where networks kept investment-grade credit while earning roughly 9 percent real on equity against a 5 to 6 percent national average.

**Commissioner.** 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. 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. 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.** 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. Every element exists in another jurisdiction today. The bill authorizes and does not spend: it changes what regulated monopolies get paid for.

**Utility executive or board member.** File a multi-year plan under a total-expenditure framework, volunteer a feeder or planning area for a flexibility pilot, and support Principle 1 before Principles 2 through 5 are decided. The reform that changes what a utility earns on comes before the reforms that change what it controls. 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, and storm hardening, wildfire mitigation, and cyber defense are funded in full. What the utility gives up is automatic rate-base growth and the gatekeeper's chair; what replaces them is a share of every deferral procured more cheaply than the wires solution.

**Consumer advocate.** Intervene for three 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. Ask for the analytical capacity to police it: funded intervention, access to utility data, and standardized cost-benefit and incidence templates. The status quo is not neutral: flat volumetric rates already transfer money from customers who cannot shift usage to those who can.

**Large-load buyer.** Offer verified curtailability during the top 50 to 100 system hours in exchange for fast-track interconnection, on a tariff available on standardized terms to qualifying industrial, commercial, and public loads, not only hyperscalers. Google signed 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.

**Market operator.** Publish congestion, curtailment, and queue-performance data in machine-readable form, and pilot a connect-and-manage pathway with published operating limits for one class of resources. ERCOT has connected resources this way for nearly two decades, and PJM filed its own connect-and-manage proposal in 2026.

**Investor or developer.** Support a staged transition toward obligation-based reliability procurement in RTO stakeholder processes, press for the standard value-stack tariff at the state level, and commit projects to standardized operating limits. Rule-based access exists only if resources accept the rules.

### 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 managed.
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 line ratings, power-flow control, reconfiguration, non-wires, and reconductoring options are priced against new construction before approval. The toolbox in *Putting the Agreement into Practice* lists seventeen such tools and where each one runs.
7. **Independently verify reliability and flexibility claims** with telemetry-settled measurement, so promised flexibility is a product rather than a hope.

### 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.

### 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.*

### Two predictable responses

After FERC opened transmission to competition in 2011, roughly ten states legislated incumbent rights of first refusal back into place. And spending gets recategorized to escape any threshold, which is why the reforms are drafted against portfolios rather than projects. Four of the five principles are decided at the commission and the statehouse, so that is where the work is.

## 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 metrics that measure the problem (queue duration, completion rate, capacity cost) provide the annual control chart.

### 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 shows | 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 shows | 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 shows | 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 shows | 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.

## 7. Objections answered

### Bills and fairness

**Aren’t data centers the reason electric bills are rising?** They add to it, and the pattern predates them: the line to connect and the climb in delivery charges were both visible before the current wave of demand. A data center that needs major new infrastructure can add costs for everyone. One that uses room the grid already has spreads fixed costs over more electricity. A large-load tariff decides which, by putting the cost of new capacity on the customer that needs it.

**Doesn’t dynamic pricing hurt low-income customers?** Only if designed carelessly, and today’s flat rate already moves money from those who cannot shift usage to those who can. Defaults ship with hedged flat products, transition bill protection, and targeted low-income rates.

### Reliability

**“Only the utility knows how to keep the lights on.”** 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. The institution responsible for keeping the lights on is also holding two thousand gigawatts of willing supply in its waiting room, where projects that came online in 2025 had waited a median of more than five years, and thirteen percent of the capacity that entered from 2000 to 2020 was operating by the end of 2025. A queue that holds willing supply out of service is itself a reliability risk.

**“Connect-and-manage threatens reliability.”** ERCOT has run it through nearly two decades of the nation's fastest resource growth, and Britain adopted it in 2010. Resources connect inside published operating limits the operator can enforce.

**“Distributed resources aren't dispatchable.”** Accreditation already answers this. PJM's demand-response accreditation moved from 69 percent to 92 percent between consecutive auctions as availability rules tightened, batteries respond sub-second, and Principle 5's obligation accounting prices every resource at its measured contribution.

**Doesn’t separating the operator fragment accountability?** American transmission has run separated since 1996, and nobody proposes going back. The wires company keeps the poles, the trucks, and the storm response; what moves is the access decision, wherever the decider has a stake in the answer.

**Where is the Enron-style risk in this?** Concentrated in Principle 5, and designed against: registered published positions, standardized products, physical backing, independent verification, and telemetry-settled performance with penalties above the value of non-performance. California’s crisis came from banning forward hedging; this program mandates it.

### Utilities and investment

**Won’t utilities fight this?** Some elements, yes, which is why Principle 1 changes what utilities earn on before anything changes what they control. Transmission open access was fought in the 1990s, imposed anyway, and is now defended by its old opponents.

**Won’t utilities underinvest if you cap their revenue?** Britain has run the framework since 2013: investment-grade credit throughout, and returns the auditor criticized as too generous. The documented failure mode is utilities earning too much. Hardening and replacement are funded in full; the building-over-buying preference is not.

**“Nobody employs more skilled workers in the district.”** 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.

### Texas and other models

**Doesn’t Texas have blackouts?** The 2021 failure traced to weatherization and fuel supply, which no interconnection study prevents. Texas is evidence about connection speed (14.2 GW added against PJM’s 5.6), not proof its whole market design should travel.

**Britain and Australia are different countries.** What is borrowed is a payment formula, not a culture: a revenue cap tied to measured outputs works the same in Honolulu as in Birmingham, which is why Hawaii adopted it. Every step runs on existing US authority.

**Didn’t FERC already try this with Order 1000, and fail?** Yes, and that failure designed this program. Order 1000 policed conduct and left the payoff intact, so recategorization beat it. A total-expenditure allowance removes the gain from recategorizing, and a peer benchmark cannot be recategorized at all.

**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. 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, and Sterling, Massachusetts is the case in point. 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. When data centers arrived, prices rose 5.6 percent at investor-owned utilities, far less at publicly owned ones, and not at all at cooperatives (MIT CEEPR, 2026).

### Scope

**Isn’t this deregulation?** No. The wires stay a regulated monopoly. What changes is how it is regulated: more tightly, with revenue caps, peer benchmarks, and published performance. Competition opens only where no monopoly exists; generation has been competitive at wholesale for thirty years.

**Permission is not the only scarcity.** True. Transformers, corridors, and crews are scarce, and no rule repeals that. The program targets the scarcity rules created, institutional permission, which is the portion reform can actually recover.

**“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 13 percent completion rate of the 2000 to 2020 entrants, today's queue implies about 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. Screening is legitimate, which is why this program uses published criteria, deposits, and readiness tests instead of discretion. Who applies those tests matters, which is the case for a neutral referee. And the remedy of paying more to wait longer invites the exit it warns about: large customers and generators are already pricing life off the grid, and every megawatt that leaves takes its contribution to the wires with it.

**Didn’t FERC Order 2023 already address interconnection?** It moved bulk study to clusters with readiness gates: real progress the program builds on. Study reform alone does not solve network expansion, cost allocation, operating limits, or distribution-level access.

**Isn’t this a one-size-fits-all national design?** No. Each principle carries a menu with stated stances; a jurisdiction reaching the same function by another route has done the same thing. ERCOT already performs several of these functions through merchant institutions.

**What if a mechanism you prefer turns out to be wrong?** The principle survives and the mechanism changes. That is why they are separated, and why every consequential stance carries a revisit trigger.

**Does this work outside RTO regions?** Mostly yes: Principles 1 through 3 are state distribution matters everywhere, Principle 4 has a non-RTO federal pathway, and Principle 5’s vehicle is the large-load tariff Southeastern utilities are already building inside the resource plan.

**Isn’t this just grid utilization?** Utilization is a fine metric and an insufficient reform: a new number evaluated by an under-resourced regulator against a mis-incentivized monopoly changes nothing until the payment formula changes. That is Principle 1’s argument.

**Doesn’t faster connection just help gas?** Gas leads PJM’s reopened queue precisely because a slow queue favors whoever can afford to wait. Rules-based access is technology-neutral and rewards whoever builds fastest: today, storage and solar-plus-storage, now nearly half of queued solar.

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*Sources and the full analysis: Papers I to III of "The Great Inversion" and their companion papers.*