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Ancillary services | The Outlet — Pilot Energy

Pilot Energy — Tue, 26 May 2026 16:23:01 GMT

On a napkin

60 Hz 60.5 Hz — high band 59.5 Hz — low band Regulation responds Regulation ±4 sec response Spinning reserve online, 10 min ramp Non-spin reserve offline, 30 min start Voltage support reactive power, local

The short version

Every second, the grid operates at a knife's edge: supply must exactly equal demand, or frequency drifts from its nominal 60 Hz. A fraction of a hertz too high or too low, and protection systems begin tripping generators and loads. Sustained deviation causes cascading failures — the kind that produce large-scale blackouts.

Ancillary services are the suite of grid support products that prevent this from happening. They are procured separately from energy, priced in their own markets, and increasingly provided by batteries, demand response, and distributed resources alongside traditional thermal generators.

Why ancillary services are growing in value: As variable renewables displace synchronous generators, the grid loses natural inertia and fast-ramping capability. More frequency regulation and reserves are needed — creating significant opportunity for batteries and flexible loads that can respond in milliseconds.

Frequency regulation

Regulation is the fastest and most continuously active ancillary service. Resources providing regulation respond to an automatic generation control (AGC) signal from the ISO every 2–4 seconds, ramping output up or down in real time to keep frequency at 60 Hz. A regulation resource might ramp up and down dozens of times per hour, never holding a steady output level.

Battery storage has become the dominant provider of regulation in many markets — particularly PJM's RegD signal, which favors fast-responding resources. CAISO's frequency regulation market has seen similar trends. The payment structure typically includes a capacity payment for being available plus a performance payment based on how accurately the resource tracks the AGC signal.

Operating reserves

Spinning reserves (synchronized reserves) are generation capacity already online, synchronized to the grid frequency, and able to ramp to full output within 10 minutes. Because they're already spinning, they can respond almost instantly to a sudden generation loss and provide inertial response during the initial seconds of a frequency event.

Non-spinning reserves (supplemental reserves) can be offline but must start and deliver power within 10–30 minutes depending on the market. They're less valuable than spinning reserves — hence a lower clearing price — but provide a deeper backstop for larger contingencies.

Reserve requirements are set by NERC reliability standards and vary by ISO. Most systems carry spinning reserves equal to the single largest contingency — typically the loss of the largest generator on the system.

Other ancillary services

Voltage support and reactive power maintains voltage within acceptable ranges across the transmission network. Reactive power can't be economically transmitted over long distances, so voltage support must be provided locally. It's often procured through cost-of-service arrangements with nearby generators rather than competitive markets.

Black start capability is the ability to restart without an external power source — critical after a widespread outage. Only certain generators (typically hydro, diesel, or specially equipped gas turbines) have this capability, and ISOs pay a separate capacity payment to maintain it.

Co-optimization with energy

Modern ISOs solve energy and ancillary service procurement simultaneously — a process called co-optimization. A generator committing capacity to spinning reserves forgoes the opportunity to sell that capacity as energy. The co-optimized solution finds the least-cost mix of energy and ancillary services, with opportunity cost payments ensuring resources are indifferent between products at the margin.

Common questions

What are ancillary services in electricity markets?

Ancillary services are grid support functions that keep electricity supply and demand balanced, maintain voltage and frequency within acceptable ranges, and allow the system to recover from unexpected disturbances. They are procured separately from energy and include frequency regulation, spinning reserves, non-spinning reserves, supplemental reserves, black start capability, and reactive power/voltage support.

What is frequency regulation?

Frequency regulation is the continuous, automated adjustment of generator output or controllable loads to keep grid frequency at 60 Hz. Resources providing regulation respond to an automatic generation control (AGC) signal from the ISO every 2–4 seconds. Battery storage and demand response are increasingly providing regulation services, often outperforming traditional generators on speed and accuracy.

What is the difference between spinning and non-spinning reserves?

Spinning reserves are generation capacity already online, synchronized to the grid, and able to ramp to full output within 10 minutes. Non-spinning reserves can be offline but must start up and deliver power within 10–30 minutes. Spinning reserves command a premium because they respond faster and provide inertia during the initial seconds of a frequency event.

Why are ancillary services becoming more valuable?

As more variable renewable generation displaces synchronous generators, the grid loses inertia and fast-ramping capability — making regulation and reserves more valuable. Battery storage is particularly well-suited to fast-response ancillary services and is capturing increasing market share. In some markets, ancillary service revenues are the primary driver of battery storage project economics.

How are ancillary services procured?

ISOs procure ancillary services through co-optimization with energy in day-ahead and real-time markets. Providers submit offers specifying available capacity and price; the ISO simultaneously solves for the least-cost combination of energy and ancillary services. Prices are set by the marginal offer cleared in each service market, independently of energy prices — though the markets interact through opportunity costs.

Resource adequacy frameworks | The Outlet — Pilot Energy

Pilot Energy — Tue, 26 May 2026 16:22:59 GMT

On a napkin

Four approaches to ensuring enough generation Centralized capacity mkts PJM · ISO-NE · NYISO · MISO Annual auction sets price Generators paid to be available Load required to procure PJM 2027/28: $333/MW-day Bilateral RA CAISO LSEs contract bilaterally Annual + monthly showings CPUC sets RA requirements Slice-of-day shaping Energy-only + scarcity ERCOT No capacity payments $5,000/MWh price cap ORDC scarcity adders DRRS being added 2025+ What capacity costs add to a typical C&I bill PJM $25–40/MWh ISO-NE $15–25/MWh NYISO $10–18/MWh MISO $8–15/MWh CAISO $5–15/MWh* ERCOT $0** *bilateral **embedded in energy price

The short version

Every grid operator faces the same physical reality: enough generation must be available to meet the next peak demand event with high probability. They use radically different mechanisms to ensure this happens. The Eastern ISOs — PJM, ISO-NE, NYISO, MISO — operate centralized capacity markets that auction off the right to be paid for being available. CAISO uses a bilateral resource adequacy (RA) program where load-serving entities contract directly with generators to meet capacity requirements set by the California Public Utilities Commission. ERCOT alone uses an energy-only design with no capacity payments, relying on scarcity pricing to provide investment signals. Each approach has different costs, different risks, and different implications for commercial procurement.

The cost difference is meaningful. Capacity charges add roughly $25-40/MWh to PJM bills today (after 2024-2025 auctions hit the FERC price cap), $15-25/MWh in ISO-NE, $10-18/MWh in NYISO, and $8-15/MWh in MISO. CAISO RA costs vary by LSE and contract but typically add $5-15/MWh. ERCOT has zero explicit capacity charge — though scarcity pricing during reliability events can drive average energy prices substantially higher than other regions over time. The total all-in cost of capacity ends up surprisingly similar across regions; what differs is how it's allocated, hedged, and exposed to volatility.

Capacity markets (PJM, ISO-NE, NYISO, MISO)

Centralized capacity markets work the same way structurally. The ISO calculates the total capacity requirement for an upcoming delivery year based on forecasted peak load plus a planning reserve margin (typically 12-18% above peak). Generators submit offers indicating the price at which they're willing to commit capacity. The ISO clears the auction at the price needed to procure the required quantity — all cleared generators receive the clearing price for every MW for the entire delivery year. The clearing price is then collected from load-serving entities proportional to their forecasted load contribution at peak, who pass costs through to retail customers.

PJM runs the Base Residual Auction (BRA) three years ahead of the delivery year. The 2026/27 BRA cleared at $329.17/MW-day across the entire footprint, hitting the FERC-imposed price cap. The 2027/28 BRA, cleared December 2025, repeated this outcome at $333.44/MW-day — the first time the entire RTO hit the cap, indicating severe capacity shortage. Drivers include rapid data center load growth, electrification, generator retirements, and slow new build progressing through the interconnection queue. ISO-NE's Forward Capacity Market runs three years ahead with reconfiguration auctions closer to delivery. NYISO uses a strip auction model with monthly spot auctions. MISO implemented a seasonal capacity construct starting in 2022 to address reliability events.

CAISO's bilateral RA

CAISO does not operate a centralized capacity market. Instead, California uses a bilateral resource adequacy program where each load-serving entity is required by the California Public Utilities Commission to contract with sufficient generation to meet RA requirements. LSEs must demonstrate compliance through annual and monthly RA showings — providing evidence that they have contracted for enough accredited capacity to cover their share of system needs.

The CAISO RA framework evolved significantly with the implementation of slice-of-day shaping starting in 2025. Rather than just meeting a peak hour requirement, LSEs must now demonstrate capacity availability across all 24 hours, with particular focus on the late afternoon/early evening ramp when solar production declines but load remains high. This change addresses the resource adequacy gap that contributed to the August 2020 rotating outages and reflects the increasing importance of energy availability over multiple hours rather than just instantaneous peak coverage.

ERCOT's energy-only design

ERCOT operates an energy-only market without capacity payments — the only major US ISO to do so. The theory: when generation is tight, wholesale energy prices should rise to scarcity levels that provide adequate revenue signals for generators to maintain availability and for investors to build new capacity. ERCOT implements this through the Operating Reserve Demand Curve (ORDC), an administrative scarcity pricing adder that increases LMPs above marginal cost when operating reserves fall below specified thresholds. The wholesale price cap was reduced from $9,000/MWh to $5,000/MWh in 2023.

Winter Storm Uri (February 2021) exposed weaknesses in the energy-only design. The Performance Credit Mechanism (PCM) was proposed as a hybrid that would add partial capacity payments without creating a full capacity market — but was shelved by the Public Utility Commission of Texas in December 2024 after years of debate. ERCOT is instead implementing the Dispatchable Reliability Reserve Service (DRRS), real-time co-optimization of energy and ancillary services, and ORDC reforms. The bet is that targeted reliability services within an energy-only framework can deliver adequate reliability without the structural cost overhead of a capacity market — though the bet is being stress-tested as ERCOT's load grows four times faster than expected.

ELCC and the accreditation problem

The conceptual challenge with capacity markets is how to credit variable resources — wind, solar, and storage — that don't behave like dispatchable thermal generators. ISOs increasingly use Effective Load Carrying Capability (ELCC) methods that measure the marginal contribution of a resource to system reliability rather than crediting nameplate capacity. A solar facility with 100 MW nameplate might receive only 20-30 MW of ELCC accreditation; a battery's ELCC depends on duration (a 100 MW / 4-hour battery might receive 80+ MW ELCC, but only if other batteries aren't already saturating the system).

ELCC accreditation has reduced capacity contributions of intermittent resources, contributing to the capacity price increases observed in 2024-2025. This is mathematically inevitable: when wind and solar with nameplate capacity displace fully-credited thermal generation, total accredited capacity declines even as installed nameplate grows. The result is higher capacity prices to procure enough accredited capacity, channeling revenue back to remaining dispatchable resources (gas plants, demand response, storage) while creating ongoing pressure to procure more storage and demand response to fill the gap. For commercial buyers, the implication is that capacity charges will likely remain elevated in capacity-market regions through the late 2020s and beyond.

Common questions

What is resource adequacy?

Resource adequacy is the framework grid operators use to ensure enough generation capacity is available to meet expected peak demand with acceptable reliability — typically targeting a loss-of-load expectation of one event in ten years. PJM, ISO-NE, NYISO, and MISO operate centralized capacity markets. CAISO uses a bilateral RA program. ERCOT relies on energy-only scarcity pricing without capacity payments.

How do capacity markets work?

Capacity markets are auctions where generators bid the amount of capacity they will guarantee to deliver during peak periods. The ISO sets the demand requirement based on forecasted peak load plus a reliability margin, and the auction clears at the price needed to procure that quantity. Cleared capacity earns the clearing price for every MW for the delivery year. Recent PJM auctions cleared at $329.17/MW-day (2026/27) and $333.44/MW-day (2027/28), both hitting the FERC-imposed price cap.

What is ELCC accreditation?

Effective Load Carrying Capability is the method ISOs use to assign accredited capacity values to variable resources like wind, solar, and storage. Rather than crediting at full nameplate, ELCC measures the additional load the system can serve reliably by adding that resource. ELCC accreditation has reduced capacity contributions of intermittent resources, contributing to capacity price increases.

What is the LOLE standard?

Loss of Load Expectation is the reliability standard most US planning regions use — typically expressed as one day of insufficient generation in ten years (0.1 days/year). The reserve margin required to meet 1-in-10 LOLE typically ranges from 12% to 18% of expected peak demand, varying by region.

Why has ERCOT chosen not to have a capacity market?

ERCOT relies on energy-only scarcity pricing — when supply is tight, wholesale prices rise toward the $5,000/MWh cap through the ORDC. The Performance Credit Mechanism that would have added partial capacity payments was shelved by the Texas PUC in December 2024. ERCOT continues to refine its energy-only design through DRRS, real-time co-optimization, and ORDC reforms.

FERC Order 2222 | The Outlet — Pilot Energy

Pilot Energy — Tue, 26 May 2026 16:22:58 GMT

On a napkin

Distributed energy resources (DERs) Rooftop solar BTM battery EV charging Demand response Heat pumps Small CHP Building EMS Small gen DERA Aggregator ≥100 kW pool Wholesale market Energy · capacity Ancillary services CAISO · NYISO · ISO-NE Implementation timeline by ISO CAISO done NYISO end 2026 ISO-NE Nov 2026 PJM Feb 2028 MISO 2027–29 SPP Q2 2030 ERCOT: not subject (outside FERC jurisdiction) — operates own DER pilot via PUCT

The short version

FERC Order 2222, issued in September 2020, required every FERC-jurisdictional grid operator — CAISO, NYISO, ISO-NE, PJM, MISO, and SPP — to revise market rules so that aggregations of distributed energy resources can participate in wholesale capacity, energy, and ancillary services markets. The minimum aggregation size is 100 kW. The intent: unlock the value of small distributed resources (rooftop solar, behind-the-meter batteries, demand response, EV charging, controllable building loads) by allowing them to be bundled and competed against utility-scale generation.

The promise has been slow to materialize. Five years after the Order, only CAISO and NYISO have meaningful DER aggregator participation. PJM, MISO, ISO-NE, and SPP have delayed implementation through multiple compliance filings, with full implementation now scheduled for 2026 through 2030. State retail programs (net metering, behind-the-meter incentives) often pay more than wholesale market participation, limiting demand for DERA programs even where they exist.

What Order 2222 actually requires

Each FERC-jurisdictional ISO must establish a tariff allowing DERAs (Distributed Energy Resource Aggregators) to register as wholesale market participants. The tariff must accommodate physical and operational characteristics of various DER types — generation, storage, demand response, energy efficiency, and EV charging. Aggregations must meet minimum size of 100 kW. The ISO must establish coordination protocols among the grid operator, aggregator, distribution utility, and relevant retail regulator. Critically, Order 2222 prohibits states from broadly excluding DERs from wholesale market participation, though states retain authority over individual DER interconnection.

The structural challenge: a DER aggregator must coordinate with three different parties — the wholesale market (ISO), the local distribution utility, and the state retail regulator — and meet performance standards while doing so. This complexity has delayed implementation as each ISO works through stakeholder processes to define telemetry requirements, double-counting prevention rules, distribution coordination protocols, and settlement procedures.

Implementation status by ISO

CAISO has implemented Order 2222, building on its pre-existing DER Aggregation program operational since 2021. CAISO requires aggregations to operate within a single Sub-LAP, with telemetry standards for aggregations exceeding 10 MW or providing ancillary services. NYISO targets full Order 2222 compliance by end of 2026, building on a DER aggregation program that has been operational since 2021. ISO-NE targets November 1, 2026 for energy market participation, with capacity market participation beginning February 1, 2027 for the 2028/2029 capacity year.

PJM has been the slowest large ISO — its third compliance filing pushed implementation to February 2028. MISO is implementing in phases: Phase 1 by June 2027, Phase 2 by June 2029. SPP targets Q2 2030. ERCOT is not subject to Order 2222 because it falls outside FERC jurisdiction (Texas operates a separate grid not connected to the eastern or western interconnections), but Texas has implemented its own DER aggregation framework through Public Utility Commission of Texas pilot programs.

What this means for commercial DER owners

For commercial and industrial facilities with behind-the-meter solar, battery storage, demand response capability, or controllable loads, Order 2222 creates a new revenue pathway. Through a DERA, the facility's DER can participate in wholesale capacity auctions, day-ahead and real-time energy markets, frequency regulation, operating reserves, and other services — earning revenue streams beyond simple retail rate offset.

The catch: actual revenue depends on local market conditions, the DERA's bidding strategy, and how DERA payments compare to alternative state retail programs. In many regions, behind-the-meter incentives (net metering, demand response retail programs, SGIP-style state subsidies) currently pay more than wholesale market participation through a DERA. This is changing as capacity prices in PJM, NYISO, and ISO-NE rise to record highs — making wholesale capacity payments increasingly competitive with retail program payments. C&I facilities with substantial DER fleets should evaluate both pathways as implementation progresses in their region.

Common questions

What is FERC Order 2222?

FERC Order 2222, issued in September 2020, requires regional grid operators to allow distributed energy resource (DER) aggregations to participate in wholesale electricity markets — capacity, energy, and ancillary services. The Order removes barriers preventing small distributed resources like rooftop solar, behind-the-meter batteries, demand response, and electric vehicles from competing alongside traditional power plants when bundled as aggregations meeting minimum size of 100 kW.

What is a DER aggregator (DERA)?

A DER aggregator (DERA) is a market participant that pools multiple distributed energy resources from different customers into a single resource of sufficient size to participate in wholesale markets. The aggregator handles wholesale market registration, bidding, settlement, and revenue distribution back to individual DER owners. DERAs may include independent power marketers, utilities, software companies, and demand response providers.

When will FERC Order 2222 be implemented across ISOs?

CAISO has implemented its compliance program. NYISO targets full implementation by end of 2026. ISO-NE targets November 1, 2026 for energy markets, with capacity market participation beginning February 1, 2027. PJM is implementing in February 2028. MISO is implementing in phases — Phase 1 June 2027, Phase 2 June 2029. SPP targets Q2 2030. ERCOT is not subject to Order 2222 since it falls outside FERC jurisdiction.

Does FERC Order 2222 apply to ERCOT?

No, FERC Order 2222 does not apply to ERCOT because ERCOT operates outside FERC jurisdiction. However, Texas has implemented its own framework for DER aggregation through PUCT pilot programs. Distributed resources in ERCOT can participate in ERCOT's energy and ancillary service markets through these state-level pathways, though the participation rules differ from those required by FERC Order 2222.

How can commercial DER owners benefit from FERC Order 2222?

Commercial DER owners — those with behind-the-meter solar, batteries, demand response capability, or controllable loads — can participate in wholesale markets through DERAs, earning revenue for services beyond retail rate offset. Potential revenue streams include capacity payments, energy market arbitrage, frequency regulation, operating reserves, and other ancillary services. The aggregator handles market complexity in exchange for a margin on revenues.

Measurement & verification | The Outlet — Pilot Energy

Pilot Energy — Tue, 26 May 2026 16:22:57 GMT

On a napkin

kWh Baseline period Retrofit Adjusted baseline Reporting period (actual) = savings claimed Time Option A Partial isolation Option B Full retrofit isolation Option C Whole facility (utility bills) Option D Calibrated simulation

The short version

Measurement and verification (M&V) is the practice of quantifying energy savings from efficiency projects — proving that the new equipment, controls, or operations actually saved the energy claimed. Because post-installation energy use is influenced by weather, occupancy, production volume, and operating changes, you can't simply compare last year's bills to this year's. M&V uses statistical methods to isolate savings specifically attributable to the installed measures versus changes in everything else.

M&V matters because programs pay for savings, not equipment. A poorly designed M&V plan can leave significant incentive payments on the table — or create disputes about how much was actually saved. For projects with custom incentive structures, performance guarantees, or ESCO arrangements, M&V outcomes determine project economics as much as installation quality.

The baseline problem and adjusted comparisons

The core challenge of M&V is that energy savings are never directly measured — they are calculated as the difference between what was used and what would have been used without the project. The "would have been" baseline is a counterfactual that must be modeled.

A simple before-and-after comparison fails because conditions change. If you retrofit lighting in January and compare it to the previous January's bill, weather may have been mild, occupancy may have shifted, production may have varied. Sophisticated M&V regresses pre-retrofit energy use against drivers (heating degree days, cooling degree days, production volume, occupancy hours), then applies the regression model to post-retrofit drivers to compute an "adjusted baseline" — what energy would have been at current operating conditions if the retrofit hadn't been installed.

The four IPMVP Options

The International Performance Measurement and Verification Protocol (IPMVP) defines four M&V approaches sized to project complexity. Option A (partial retrofit isolation with key parameter measurement) is typical for lighting upgrades — measure operating hours of the new fixtures, stipulate wattage based on equipment specs. Low cost, moderate accuracy. Option B (full retrofit isolation) measures all variables at the equipment level — used for motor or HVAC upgrades where both load and operating profile matter. Higher cost, higher accuracy. Option C (whole facility) uses utility billing data with regression analysis on the entire building — used for comprehensive multi-measure projects where isolating individual measures isn't practical. Option D (calibrated simulation) uses calibrated energy models — for new construction or complex projects where pre-retrofit baseline isn't available or doesn't reflect intended post-retrofit operation.

ASHRAE Guideline 14 and statistical rigor

ASHRAE Guideline 14 provides detailed statistical methods that complement IPMVP. It specifies minimum requirements for regression modeling quality (R² thresholds, residual analysis), uncertainty quantification (confidence intervals on calculated savings), and reporting (what variables, methods, and data must be documented). For large projects and performance contracts, ASHRAE 14 compliance is often required by funders and counterparties as evidence that the M&V methodology is technically defensible.

Uncertainty calculations matter. A project that calculated 1,000,000 kWh savings with ±20% uncertainty at 95% confidence is delivering different value than one with ±5% uncertainty. Some performance contracts include a "minimum guaranteed savings" floor that triggers payment adjustments when measured savings fall below the lower confidence bound — making rigorous baseline and uncertainty analysis economically critical.

Common questions

What is measurement and verification (M&V)?

Measurement and verification (M&V) is the practice of quantifying energy savings from efficiency projects by comparing post-installation energy use to a baseline. M&V is used to support utility incentive payments, performance contract guarantees, ESCO billing, and corporate sustainability reporting. Because actual post-installation energy use is influenced by weather, occupancy, and operating changes, M&V uses statistical methods to isolate savings specifically attributable to the installed measures.

What is IPMVP?

The International Performance Measurement and Verification Protocol (IPMVP) is the most widely used global framework for M&V. Developed by the Efficiency Valuation Organization, IPMVP defines four M&V Options: Option A (partial retrofit isolation), Option B (full retrofit isolation), Option C (whole facility regression), and Option D (calibrated simulation). Each Option fits different project types based on cost, complexity, and required certainty.

What is ASHRAE Guideline 14?

ASHRAE Guideline 14 is a technical standard providing detailed statistical methods for measuring energy and demand savings. It complements IPMVP by providing specific guidance on regression modeling, uncertainty calculations, and minimum reporting requirements. ASHRAE Guideline 14 is widely referenced in performance contracts and is the technical backbone of formal M&V analyses in the US commercial and institutional sector.

What is the difference between IPMVP Options A, B, C, and D?

Option A (partial retrofit isolation) measures key parameters at the equipment being upgraded — used for lighting retrofits where operating hours can be measured and other parameters stipulated. Option B (full retrofit isolation) measures both parameters at the upgraded equipment — used for motor or HVAC upgrades. Option C (whole facility) uses utility billing data with regression modeling — used for comprehensive whole-building projects. Option D (calibrated simulation) uses calibrated energy models — used for new construction or complex multi-measure projects.

Why does M&V matter for energy incentive programs?

Utility efficiency programs and performance contracts pay for energy savings, not equipment installations. M&V is the mechanism that quantifies how much was actually saved. Programs with rigorous M&V — particularly for custom measures and large projects — pay only for verified savings, which means project economics depend on M&V outcomes as much as installation. Poor M&V design can leave significant incentive value on the table or create disputes that delay payment.

Capacity market — Energy Glossary | Pilot Energy

Pilot Energy — Tue, 26 May 2026 16:22:56 GMT

Capacity market

Category: Markets

Green tariffs | The Outlet — Pilot Energy

Pilot Energy — Tue, 26 May 2026 16:22:55 GMT

On a napkin

Renewable project (new build) Utility owns PPA with renewable project state regulated C&I customer subscribes to green tariff RECs + fixed rate Customer avoids direct PPA complexity — utility handles procurement

The short version

A green tariff is a utility-administered program that allows large C&I customers to source renewable energy through their existing utility relationship — without negotiating a direct PPA with a developer. The utility contracts with a renewable energy project, typically a new-build wind or solar facility, and passes the contracted renewable electricity to enrolled customers at a defined rate. Customers receive RECs from the specific project and can make credible additionality claims for sustainability reporting.

Green tariffs exist because direct PPAs are hard. Negotiating a 20-year PPA requires legal sophistication, credit exposure management, basis risk analysis, and ongoing counterparty management. For mid-market C&I customers without dedicated energy teams, a green tariff offers a materially simpler path to renewable procurement with strong sustainability credentials.

Types of green tariff structures

Voluntary green pricing (VGP) programs are the simplest — customers pay a small premium (often $1–3/MWh) above their standard rate to receive renewable energy and associated RECs. These are typically not tied to a specific project and provide weaker additionality claims.

Large customer renewable programs (sometimes called Renewable Energy Tariffs or RETs) are more sophisticated: the utility procures a specific new-build project and offers the output to subscribing customers at the project's LCOE, often with a fixed or lightly escalating rate for the PPA term. These programs provide stronger additionality and more direct price certainty, and are the format most commonly used by Fortune 500 sustainability teams.

Pros and cons versus direct PPAs

Green tariffs offer simplicity, no credit exposure, utility regulatory backing, and access for customers too small to negotiate direct PPAs. You don't need a lawyer to draft counterparty agreements or a trading desk to manage basis risk. The trade-offs are limited negotiating flexibility on price or terms, fewer customization options, and typically lower potential upside than a well-structured direct PPA in a rising price environment.

For mid-market buyers — annual electricity spend of $2–20M — the green tariff is often the right tool. For large industrial buyers spending $50M+ annually with dedicated energy teams, direct PPAs or VPPAs generally offer more value through price customization, longer terms, and the ability to structure basis and shape risk allocations.

Availability and how to evaluate programs

Green tariff availability varies significantly by state and utility. California, the Southeast (Duke Energy, Georgia Power), and the upper Midwest (Xcel Energy) have particularly active programs. Buyers should evaluate: whether the enrolled project is new-build (additionality), the rate structure (fixed vs. variable), REC registry and vintage, minimum subscription size, and what happens to the rate if the utility's underlying PPA costs change. FERC-jurisdictional interconnection and state utility commission approval govern program design — understanding who approved what matters when assessing rate stability.

Common questions

What is a green tariff?

A green tariff is a utility-administered program allowing large C&I customers to source renewable energy through their existing utility without negotiating a direct PPA. The utility contracts with a renewable project and passes the output to enrolled customers at a defined rate, including RECs from the specific project. It's the most accessible form of corporate renewable procurement.

How does a green tariff differ from a PPA?

A PPA is a direct contract between the buyer and a renewable developer. A green tariff uses the utility as intermediary — the utility holds the PPA and offers the renewable output to customers through a regulated tariff. Green tariffs are simpler and require no direct developer relationship, but offer less flexibility and typically lower economic upside than a direct PPA.

What sustainability claims can buyers make with a green tariff?

Green tariff customers receive RECs for market-based Scope 2 accounting under the GHG Protocol. Programs backed by new-build projects provide strong additionality claims. The strength of the claim depends on project newness, geographic proximity to the buyer's load, and temporal matching of generation to consumption — increasingly scrutinized under advanced sustainability frameworks.

Are green tariff rates fixed or variable?

Green tariff structures vary. Some programs offer fixed rates for the PPA term (comparable price certainty to a direct PPA). Others tie rates to the utility's avoided cost or renewable portfolio costs, which can vary. Fixed-rate programs are generally preferred for budget planning. Buyers should carefully review whether the rate is fixed, indexed, or subject to regulatory change before committing.

Which utilities offer green tariff programs?

Green tariffs are available through many large utilities including Duke Energy, Dominion Energy, Pacific Gas and Electric, Southern California Edison, Xcel Energy, Georgia Power, and numerous cooperatives and municipal utilities. Availability, program structure, pricing, and minimum load requirements vary significantly by utility and state — buyers should contact their utility directly or work with an energy advisor to evaluate available programs.

How electricity prices are set | The Outlet — Pilot Energy

Pilot Energy — Tue, 26 May 2026 16:22:54 GMT

On a napkin

$250 $200 $150 $100 $50 Peak: $238/MWh DR event window LMP = Energy + Congestion + Losses 00:00 06:00 12:00 18:00 24:00 $/MWh

The short version

LMP is the price that determines what every wholesale settlement actually pays out. The grid operator calculates it every five minutes at every transmission node — thousands of separate prices across each ISO — and three things drive what it costs at any given point: the cheapest generator running that interval, whether congestion is forcing more expensive units to dispatch locally, and electrical losses on the wires between generation and load. For buyers on index contracts, those three components determine the monthly bill. For buyers on fixed-price contracts, they determine what the retailer earned or lost serving the load — and ultimately what the next renewal looks like.

LMP = Energy + Congestion + Losses. Congestion is the volatile component. ERCOT West Hub vs. Houston basis ran $300+/MWh during certain 2024 wind events. PJM Western Hub vs. Dominion zone basis has structurally widened as Northern Virginia data center load outgrew available transmission. The February 2021 Texas winter storm cleared the $9,000/MWh administrative cap (since lowered to $5,000) across multiple intervals — almost entirely a congestion and scarcity event, not a fuel-cost event.

How LMP gets calculated

Every ISO that uses nodal pricing — PJM, MISO, ERCOT, SPP, CAISO, ISO-NE, NYISO — solves the same problem on essentially the same cadence. The day-ahead market clears once per day at hourly intervals, typically by 1 PM the day before delivery. Generators submit price-quantity offers; load serves submit demand bids; the optimization solves for the lowest-cost dispatch that respects every transmission and reliability constraint. Day-ahead LMPs are the prices that flow through most financial hedges, FTR settlements, and forward contracts.

The real-time market reruns the same optimization every five minutes against actual physical conditions — a generator that tripped, a cloud over a solar farm, a heat wave spiking residential AC load. Real-time LMPs can deviate sharply from day-ahead prices, particularly during stress events. The difference between day-ahead and real-time at the same node is called the real-time settlement adjustment, and it is the primary income or expense from virtual bidding strategies.

Nodal vs. zonal — why the distinction matters for buyers

Nodal pricing calculates a unique LMP at every transmission bus. PJM alone has more than 10,000 priced nodes. Zonal pricing averages prices across broader geographic zones. Five of the seven US ISOs are nodal at settlement. ERCOT settles generation nodally but load zonally — a structural mismatch that creates persistent transfer risks.

For a buyer with a 5 MW facility on a single distribution feeder, the relevant question is not "what is the PJM Western Hub LMP" but "what is the LMP at the specific load aggregation point my retailer uses for settlement?" Those two numbers can differ by tens of dollars per MWh on a routine basis and by hundreds during constraint events. A retail contract benchmarked to the hub but settled at the node passes that difference through as a separate line item — or absorbs it into the next renewal pricing.

Basis risk and how it gets hedged

Basis is the price difference between two points on the grid — typically between a generator's location and a load center, or between a load zone and the regional hub. Persistent basis indicates persistent transmission constraints, and the trend in recent years has been worsening: data center load growth has concentrated geographically faster than transmission can be built to serve it, with the result that basis between generation-rich and load-rich zones has structurally widened.

The standard hedge is the Financial Transmission Right. FTRs are tradeable financial contracts that pay the holder the difference in LMP between two specified locations over a defined period. A C&I load with persistent exposure to a congested node can buy FTRs from a less constrained hub to the load's settlement point, neutralizing the basis exposure. FTR auctions clear monthly, seasonally, and annually depending on the ISO. The auction revenue is paid to LSE load through ISO surplus distribution; the FTR cash flows hedge against actual settlement congestion. For loads above a few megawatts in chronically constrained zones, FTRs are not optional sophistication — they are the difference between a predictable energy bill and one that surprises every congestion event.

When real-time goes vertical

The headline number most buyers track is not the average LMP but the tail. Day-ahead LMP averages across an ISO might be $35-50/MWh, but real-time can hit the administrative price cap ($5,000/MWh in ERCOT, $3,000/MWh in PJM, similar across the others) during scarcity. The February 2021 Texas storm cleared the cap repeatedly. The August 2020 CAISO rotating outages did the same. The Pacific Northwest June 2021 heat dome cleared the cap in CAISO. Each event was driven by a different combination of supply shortfall, demand surge, and transmission constraint — but the price signal in each case was unmistakable, and the bills paid by load to clear the market were enormous.

Most C&I customers are partially insulated from these spikes by fixed-price retail contracts. But the spikes flow into renewal pricing, capacity charges, and ancillary service uplift across the broader market. Buyers with real-time index contracts, demand response participation, or behind-the-meter generation see the spikes directly — and in DR especially, the spikes are the entire business model.

Commercial implications

Three implications for buyers and developers. First, settlement risk is local. The hub price your retail contract benchmarks is not the price you pay for power at your specific point of withdrawal. Basis between hub and node can run hundreds of dollars per MWh during constraint events, and the trajectory of constraint frequency in most US ISOs is up, not down.

Second, congestion is now the dominant driver of LMP volatility, and it is structural rather than cyclical. The pattern is most acute in PJM Dominion, CAISO load pockets, and ERCOT load zones with rapid data center growth, but the underlying dynamic — load concentration outpacing transmission build — applies across the country.

Third, FTRs are the primary tool for managing the resulting basis exposure. For large industrial loads served at congested nodes, FTR strategy has shifted from optional sophistication to standard practice. The same applies, mirrored, on the generation side: developers signing PPAs at constrained generation nodes face symmetric basis risk that FTRs partially address.

Common questions

What is locational marginal pricing (LMP)?

Locational marginal pricing (LMP) is the cost of supplying one additional megawatt-hour of electricity at a specific location on the grid. It has three components: the energy component (the system-wide cost of the cheapest available generation), the congestion component (added cost when transmission lines are constrained), and the loss component (the cost of electrical losses along the transmission path). LMPs are calculated and published by grid operators (ISOs and RTOs) every 5 minutes in real-time markets and every hour in day-ahead markets.

Why do electricity prices change every 5 minutes?

Grid operators run markets in real time, clearing prices every 5 minutes in real-time markets and every hour in day-ahead markets. Prices change because the cheapest available generation changes as demand rises and falls throughout the day, and as transmission congestion shifts with load patterns. A sudden spike in demand, a generator outage, or a transmission constraint can cause prices to move dramatically within a single interval.

What is the difference between nodal and zonal pricing?

Nodal pricing calculates a unique LMP at every point (node) on the transmission grid — PJM alone has over 10,000 nodes. Zonal pricing averages prices across a geographic zone, providing a simpler but less granular signal. PJM, CAISO, MISO, NYISO, and SPP use nodal pricing. The distinction matters for energy buyers because a contract priced at a hub may not reflect what you actually pay or receive at your specific location.

What is basis risk in electricity markets?

Basis risk is the exposure to price differences between a contract hub (like PJM Western Hub) and the actual node where your generation or load is located. Even if you've hedged at the hub price, your actual settlement is at your node — and those prices can diverge significantly during congestion events. Buyers with loads in chronically congested zones routinely pay more than hub prices suggest.

How does LMP affect demand response programs?

Demand response programs are often triggered when real-time LMPs spike above a threshold. Customers who curtail load during high-price intervals effectively earn the difference between the avoided retail cost and the market price. In markets with emergency demand response, curtailed load is compensated at or near the real-time LMP — which during scarcity events can exceed $1,000/MWh in markets with high price caps.

Building certifications | The Outlet — Pilot Energy

Pilot Energy — Tue, 26 May 2026 16:22:52 GMT

On a napkin

Major Building Certifications & Approach LEED USGBC · since 2000 Design-based Points across categories Levels: Certified · Silver Gold · Platinum Renewable: 16 pts Energy: 33 pts ENERGY STAR US EPA Performance-based Actual energy use vs. peers Score: 0–100 percentile ≥75 = certified Renewable indirect via net energy use BREEAM USA UK origin · since 1990 Design + operations Weighted scoring Levels: Pass · Good · Very Good Excellent · Outstanding Global standard smaller US footprint WELL IWBI · since 2014 People-focused Health & wellness Levels: Bronze · Silver Gold · Platinum Complement to LEED

The short version

Building certifications are third-party verified ratings that signal a building's performance against established standards — for energy, environmental impact, occupant health, or some combination. The four most consequential certifications in US commercial real estate are LEED (design-based green building), ENERGY STAR (actual energy performance), BREEAM (global green building), and WELL (occupant health and wellness). Each measures something different and serves different stakeholder needs.

Certifications are increasingly contractual. Many corporate tenants — particularly tech, financial services, and Fortune 500 companies — require LEED Silver/Gold or ENERGY STAR certification as a lease condition. Real estate owners with uncertified buildings face shrinking tenant pools in major markets. This makes certification a market differentiator, not just a marketing badge.

LEED — design-based, comprehensive scope

LEED (Leadership in Energy and Environmental Design), administered by the US Green Building Council, is the dominant US green building certification. LEED awards points across categories — energy and atmosphere, sustainable sites, water efficiency, materials and resources, indoor environmental quality, and innovation — with total points determining certification level: Certified (40-49 points), Silver (50-59), Gold (60-79), or Platinum (80+).

LEED has multiple rating systems for different project types: BD+C (Building Design and Construction) for new construction, O+M (Operations and Maintenance) for existing buildings, ID+C (Interior Design and Construction) for commercial interiors, and ND (Neighborhood Development) for districts. LEED is design-based, meaning certification reflects the building's specifications and projected performance rather than actual measured operations. This is both LEED's strength (predictability) and its frequent criticism (a LEED-certified building can underperform an uncertified one in actual operation).

ENERGY STAR — performance-based, narrow scope

ENERGY STAR for buildings, administered by the US EPA, takes the opposite approach: it certifies based on actual measured energy performance. To earn ENERGY STAR certification, a building must achieve an ENERGY STAR score of 75 or higher on a 1-100 scale — meaning it performs in the top 25% of similar buildings nationally for actual energy use, normalized for size, climate zone, occupancy, and building type.

ENERGY STAR is narrower than LEED — it only addresses energy — but stricter in that it requires verified ongoing operational performance. ENERGY STAR certification must be renewed annually based on the previous 12 months of operational data. Many commercial owners pursue both: LEED for new construction and significant retrofits (one-time achievement); ENERGY STAR for ongoing operations (annual renewal). Combined with the federal 179D commercial buildings tax deduction (which can require ENERGY STAR-comparable performance, and which sunsets for projects with BOC after June 30, 2026 under the OBBBA), this is one of the more common pairings in US commercial real estate.

BREEAM and WELL — different angles on building quality

BREEAM USA is the US adaptation of the UK-originated Building Research Establishment Environmental Assessment Method, the world's longest-running green building certification. BREEAM is more common globally than in the US, where LEED dominates, but BREEAM's stronger international footprint matters for multinational corporate portfolios pursuing consistent global standards.

WELL Building Standard, administered by the International WELL Building Institute, focuses on human health and wellness rather than environmental impact. WELL evaluates buildings across air, water, nourishment, light, movement, thermal comfort, sound, materials, mind, and community. WELL is complementary to LEED — many high-performance buildings pursue both, with LEED addressing environmental impact and WELL addressing occupant experience. WELL has grown rapidly since 2014 as corporate tenants and employee wellness programs have made the workplace environment a competitive differentiator.

The energy procurement connection

Most certifications credit renewable energy procurement and on-site generation. LEED v4.1 awards up to 16 combined points across renewable energy production (on-site generation) and renewable energy procurement (PPAs, VPPAs, green tariffs, RECs). The credit hierarchy values long-term direct procurement (PPAs) higher than short-term unbundled RECs, reflecting additionality concerns. ENERGY STAR doesn't directly credit renewables but indirectly benefits buildings using on-site renewable generation that reduces metered consumption. BREEAM and WELL similarly credit renewable procurement with detailed scoring rules.

For real estate owners and corporate tenants, this means renewable energy procurement strategy interacts directly with certification strategy. A 20-year solar PPA earns more LEED credit than five years of unbundled RECs, even if both deliver the same total renewable energy volume. Building owners increasingly time PPA execution to coincide with certification submission, and many specify renewable procurement as a base building amenity in leases targeting Fortune 500 tenants.

Common questions

What is LEED certification?

LEED (Leadership in Energy and Environmental Design) is a green building certification from the US Green Building Council. LEED awards points across categories including energy, water, materials, indoor environmental quality, and location. Total points determine certification level: Certified (40-49), Silver (50-59), Gold (60-79), or Platinum (80+). LEED is the most widely recognized green building certification globally.

What is ENERGY STAR for buildings?

ENERGY STAR certification for buildings is an EPA program that recognizes commercial buildings performing in the top 25% of their peer group nationally. A building must achieve an ENERGY STAR score of 75 or higher (out of 100) based on actual energy consumption normalized for size, climate, and use type. Unlike LEED, ENERGY STAR measures actual operating performance, not design intent.

What is BREEAM USA?

BREEAM (Building Research Establishment Environmental Assessment Method) is the original green building certification, developed in the UK in 1990. BREEAM USA is the US-specific version. Like LEED, it awards points across categories including energy, water, materials, health, and management. Certification levels are Pass, Good, Very Good, Excellent, and Outstanding. BREEAM is more common globally than in the US, where LEED dominates.

What is the WELL Building Standard?

WELL Building Standard, administered by the International WELL Building Institute, focuses on human health and wellness rather than environmental impact. WELL evaluates buildings across categories including air, water, nourishment, light, movement, thermal comfort, sound, materials, mind, and community. WELL is complementary to LEED and other environmental certifications.

How do building certifications affect energy procurement?

Most certifications award points or credits for renewable energy procurement, on-site generation, and energy efficiency. LEED v4.1 BD+C awards up to 16 points for renewable energy production and offsite renewable purchases combined. ENERGY STAR doesn't directly credit renewables but does normalize against actual energy use, which renewable PPAs help reduce. Many corporate tenants now require LEED or ENERGY STAR ratings as lease conditions.

Sustainability reporting & energy | The Outlet — Pilot Energy

Pilot Energy — Tue, 26 May 2026 16:22:51 GMT

On a napkin

Scope 2 emissions Purchased electricity Location- based Market- based RE100 commitment CDP disclosure SBTi targets Procurement instruments PPAs · VPPAs · RECs Green tariffs · Retail green

The short version

Scope 2 emissions are the greenhouse gas emissions associated with purchased electricity — the carbon released at power plants to generate the electricity your facility consumes. For most commercial and industrial organizations, Scope 2 is the single largest category of controllable emissions. How you measure and report Scope 2 — and what you do to reduce it — is increasingly central to corporate sustainability strategy, investor disclosure, regulatory compliance, and customer and employee expectations.

Market-based and location-based accounting tell very different stories. A company with a clean PPA can report near-zero market-based Scope 2 while location-based reporting shows substantial emissions. The GHG Protocol requires both. Investors and sustainability frameworks increasingly scrutinize the quality and additionality of the instruments behind market-based claims.

The two Scope 2 accounting methods

The GHG Protocol Corporate Standard requires companies to report Scope 2 under both methods. Location-based accounting uses grid average emission factors — typically the EPA's eGRID regional emission factors — reflecting the carbon intensity of the grid regardless of what the company has contracted. Market-based accounting uses the emission factors of the specific electricity instruments the company has purchased: RECs, PPAs, green tariffs. If no specific instrument is held, the residual mix emission factor for the relevant grid applies — often higher than the grid average, since better instruments have been claimed by others.

The gap between market-based and location-based Scope 2 is the "benefit" of renewable procurement — but the credibility of that gap depends entirely on the quality of the instruments claimed.

RE100, CDP, and Science Based Targets

RE100 commits signatory companies to 100% renewable electricity by a target year. Members report annual progress using market-based accounting. Renewable electricity must meet defined quality criteria: from a renewable source, generated in the same country or market, matched in time and geography, and ideally from new-build projects. CDP runs an annual climate questionnaire used by institutional investors — renewable energy percentage, Scope 2 emissions, and energy procurement strategy are key scoring metrics. Science Based Targets initiative (SBTi) sets emissions reduction targets aligned with 1.5°C climate pathways; Scope 2 reductions typically require renewable procurement meeting strong additionality and matching standards, combined with efficiency improvements.

Quality of renewable procurement — what actually matters

Not all renewable energy instruments are equally credible. The quality hierarchy, from strongest to weakest: bundled PPAs from new-build projects with annual or hourly matching (strongest additionality, direct causality, clear REC provenance); green tariffs from new-build utility projects (strong additionality, simpler structure); bundled RECs from existing projects in the same region and year; and unbundled commodity RECs from distant existing projects (weakest — no additionality, poor geographic and temporal matching). Most advanced sustainability frameworks are moving toward requiring 24/7 hourly matching — aligning every hour of consumption with a corresponding hour of clean generation in the same grid zone — as the evolving gold standard.

Common questions

What are Scope 2 emissions?

Scope 2 emissions are GHG emissions associated with purchased electricity, steam, heat, or cooling. For most commercial and industrial organizations, purchased electricity is the dominant Scope 2 source. Scope 2 is defined under the GHG Protocol Corporate Standard — the most widely used corporate emissions accounting framework globally — which requires reporting both location-based and market-based Scope 2.

What is the difference between market-based and location-based Scope 2?

Location-based Scope 2 uses grid average emission factors — the carbon intensity of the regional grid regardless of what the company has contracted. Market-based uses the emission factors of specific contractual instruments (RECs, PPAs). A company with a clean PPA can report near-zero market-based Scope 2 while location-based shows the grid average. The GHG Protocol requires companies to report both methods.

What is RE100?

RE100 is a global initiative committing signatory companies to sourcing 100% of their electricity from renewable sources by a target year (by 2050 at the latest). RE100 members report annual progress, and renewable procurement must meet defined quality criteria including additionality, geographic matching, and temporal matching. Over 400 major companies are RE100 members including many of the world's largest corporations.

What is 24/7 clean energy matching?

24/7 clean energy matching aligns every hour of electricity consumption with a corresponding hour of clean energy generation in the same grid zone. This is more demanding than annual REC matching, which allows a summer wind REC to offset a winter coal-powered consumption hour with no temporal connection. 24/7 matching is emerging as the gold standard, pioneered by Google, Microsoft, and other large technology companies, and is increasingly required by advanced sustainability frameworks.

How do PPAs and VPPAs help with Scope 2 reporting?

Physical PPAs with new-build renewable projects generate bundled RECs retired for market-based Scope 2 accounting. VPPAs generate RECs transferring to the corporate buyer for the same purpose. PPAs from new-build projects provide additionality — the contract causes new renewable capacity to be built. This is increasingly required by RE100, SBTi, and CDP frameworks for the strongest sustainability claims.

Virtual PPA (VPPA) — Energy Glossary | Pilot Energy

Pilot Energy — Tue, 26 May 2026 16:22:50 GMT

Virtual PPA (VPPA)

Category: Procurement