# 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).*

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**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).