Primary Sources We Use

The 0.7 Bcf/d value is nominal Train 1 capacity, not guaranteed daily feedgas demand. Label forward export values as EIA estimates and the half-year comparisons as KilowattLogic calculations. Do not infer a Henry Hub range, basis quote, supplier offer, or delivered-rate outcome.

• - Golden Pass April 2026 export start and Train 1 ramp status
• - Golden Pass Train 1 nominal capacity and expected Train 2 timing
• - First-half 2026 U.S. LNG exports and year-over-year change
• - Second-half 2026 and first-half 2027 EIA export estimates
• - Commercial-buyer interpretation of LNG demand, regional basis, storage, and contract exposure

ISO-NE displays cleared demand quantities as negative values in the official CSV. The 9.9% comparison is a KilowattLogic calculation from official ARA2 and FCA 18 prices. Neither price is a complete customer rate or a guaranteed future auction result.

• - 2027/28 ARA2 interface clearing price and cleared supply/demand quantities
• - Comparison with the original FCA 18 Rest-of-Pool clearing price
• - Boundary between a reconfiguration auction, the original FCA result, and future prompt auctions
• - Commercial-buyer interpretation of capacity pass-through and contract exposure

Use this source for historical April-May petroleum-flow facts. CBP guidance says the extended waiver loading deadline expired August 16, 2026. Do not imply the waiver remains active, that elevated flows continued after May, or that the reported shipments guarantee regional fuel-price, electricity-rate, or supplier-offer outcomes.

• - April and May 2026 waterborne petroleum movements from the Gulf Coast to the West and East Coasts
• - Record West Coast, East Coast, gasoline-blending-component, distillate, and crude-oil shipment context
• - Lower-bound January-February to April West Coast shipment comparison
• - Jones Act waiver scope and the August 16, 2026 covered-product loading deadline
• - Commercial fuel, logistics, backup-generation, and delivery-surcharge review without price guarantees

Label the 6% and 14% values as EIA forecasts and the percentage-point and relative changes as KilowattLogic calculations. This source does not establish an ERCOT forecast, approved or energized load, project cancellations, supplier pricing, or a customer-specific bill outcome.

• - EIA forecast of 6% Texas electricity-load growth in 2027
• - Comparison with the 14% forecast in the prior outlook
• - KilowattLogic calculation of an 8-percentage-point and approximately 57% relative reduction
• - Commercial-buyer interpretation separating an EIA forecast from ERCOT planning and customer rates

The 474 GW and 90% figures are point-in-time request estimates in the state directive. They are not approved projects, energized demand, an ERCOT load forecast, or a retail-rate forecast.

• - Approximately 474 GW of large-load requests under consideration
• - Roughly 90% data-center share of the request snapshot
• - Audit scope covering power, water, incentives, ownership, and project substantiation
• - Boundary between requests under review and approved or energized load

Use this source for August 2026 STEO natural gas updates. Label all values as forecasts and separate them from reported storage, live futures settlements, regional basis quotes, supplier offers, and delivered-rate outcomes.

• - Third-quarter and annual Henry Hub public benchmark forecasts
• - End-October 2026 U.S. working-gas forecast and July-to-August revision
• - LNG export-terminal maintenance and feedgas-demand forecast context
• - Commercial-buyer interpretation separating national benchmarks from regional basis and delivered rates

Use this source for the May 13, 2026 EIA ERCOT solar-versus-coal forecast. Keep EIA forecast generation values separate from delivered commercial rate claims, supplier offers, congestion costs, and KilowattLogic procurement interpretation.

• - ERCOT utility-scale solar and coal generation forecasts for 2026 and 2027
• - ERCOT generation mix context for solar, coal, and natural gas
• - Texas commercial electricity buyer analysis of generation mix, large-load growth, and hourly risk

Use this source for June 2026 STEO natural gas updates. Label values as forecasts and keep them separate from live NYMEX settlements, regional basis quotes, supplier offers, and guaranteed delivered-rate outcomes.

• - Henry Hub 2026 and 2027 public benchmark forecasts
• - U.S. natural gas production, consumption, and LNG export forecast context
• - Gas-indexed electricity procurement and fuel-risk framing

Use this source for July 2026 STEO natural gas updates. Label values as forecasts and separate them from live NYMEX settlements, regional basis quotes, supplier offers, and delivered-rate outcomes.

• - Henry Hub 2026 and 2027 public benchmark forecasts
• - U.S. dry natural gas production, consumption, LNG export, and storage-balance forecasts
• - Power-sector natural gas consumption and wholesale electricity price context for commercial buyer analysis

Use this source for May 2026 public benchmark updates. Keep EIA forecast values separate from live NYMEX settlements, delivered-basis quotes, supplier offers, and KilowattLogic procurement interpretation.

• - Henry Hub 2026 and 2027 public benchmark forecasts
• - Lower 48 marketed natural gas production and storage-balance context
• - U.S. LNG export forecast and global LNG/Hormuz context

Use this source for EIA power-burn forecast coverage. Label values as forecasts and keep natural gas-fired generation signals separate from delivered-rate or supplier-savings claims.

• - U.S. electric-power natural gas consumption forecast for summer 2026 and summer 2027
• - ERCOT and PJM natural gas-fired electricity generation growth context
• - Commercial and industrial electricity demand-growth context for gas-indexed power buyers

Use this source for the May 15, 2026 EIA industrial natural gas demand update. Keep EIA forecast consumption values separate from supplier offers, fixed-price advice, CHP economics, and KilowattLogic procurement interpretation.

• - U.S. industrial natural gas consumption forecasts for 2026 and 2027
• - Manufacturing and chemicals-sector natural gas procurement context
• - Industrial seasonal load-shape and efficiency caveats

Use this source for EIA-reported hourly system demand and generation mix. The record does not establish a retail-rate increase, supplier quote, customer-specific 4CP result, outage, contract exposure, or guaranteed savings.

• - ERCOT 91.1 GW hourly demand record on July 22, 2026
• - Comparison with the 85.5 GW August 10, 2023 record
• - Natural gas and solar shares of generation during the record hour
• - Commercial-buyer peak-management, 4CP, contract, and interval-data questions

Use this source for EIA-reported weekly average system load. It does not establish a retail-rate increase, supplier quote, customer-specific 4CP interval, outage, reliability emergency, or guaranteed savings.

• - ERCOT 74.5 GW record weekly average load for week ending August 22, 2026
• - ERCOT 73.7 GW weekly average load for week ending August 29, 2026
• - Comparison with the prior 70.0 GW weekly record and the highest summer 2025 weekly average
• - Six-week run above the prior weekly average record

FERC has not set the XBRL-CSV deployment timeline. Current EQR deadlines remain in force until the future system is implemented, and the regulatory reporting changes do not establish a retail rate or customer-specific bill outcome.

• - Current EQR filing deadlines and the July 31, 2026 Q2 deadline
• - Three reporting-field eliminations effective for 2026 Q2 EQR filings
• - Material billing-adjustment refiling treatment
• - Pending XBRL-CSV, four-month deadline, and RTO/ISO report implementation timeline

Phase 1 is a qualitative assessment, not a final reform order, modeled savings result, tariff, supplier quote, or customer-specific bill forecast. Its roughly one-quarter bill-share example is residential and is not applied to commercial accounts.

• - April 2021-April 2026 New Jersey commercial and industrial retail-price growth
• - Separation of state-regulated distribution costs from supply and transmission costs
• - Qualitative Phase 1 reform findings and the boundary around pending Phase 2 modeling
• - Commercial-buyer questions for tariff, supplier, capacity, and capital-cost review

NYISO reports wholesale spot-capacity results. KilowattLogic calculates rounded month-over-month changes. These values do not establish a customer-specific ICAP tag, supplier reserve factor, utility delivery tariff, retail contract rate, or bill outcome.

• - September 2026 New York City, Long Island, G-J locality, and NYCA spot-auction clearing prices
• - August-to-September locality price comparisons and percentage changes
• - August and September total awarded-capacity comparison
• - Commercial-buyer interpretation of ICAP-tag and supplier-treatment questions

These documents record PJM Board direction for filings at FERC; they are not a final FERC-approved tariff. Procurement volume can be reduced by bilateral and self-supply commitments, and customer bill treatment depends on approved allocation rules, state authority, supplier contracts, and account-specific load obligations.

• - Initial 6,831 MW procurement target tied to the 2028/2029 Base Residual Auction shortfall
• - $555/MW-day maximum willingness to pay, up-to-15-year term, and June 1, 2032 in-service deadline
• - August bilateral opening and September 30-October 21 central bid window
• - Proposed load-zone and load-serving-entity cost allocation
• - 50 MW Large Load Registry threshold and Insufficient Resource Adequacy Service framework

This is a straw proposal, not an approved tariff or operating program. The 589.1 MW statewide figure is KilowattLogic arithmetic from the four utility rows. Compensation, measurement, dispatch, enrollment, wholesale stacking, customer savings, and final targets remain unresolved.

• - Proposed 2027-2029 interim VPP phase and July 1, 2027 launch deadline
• - Proposed utility planning floor of at least 3% peak-demand reduction
• - Utility peak-demand and 3% values that sum to 589.1 MW
• - Preliminary estimate of approximately $60 million in annual avoided capacity payments
• - Commercial-buyer interpretation of flexible-load readiness and open program-design questions

Use this source for California CTA context. Do not imply CPUC regulates CTA commodity rates or guarantees savings from CTA service.

• - California Core Transport Agent and retail gas choice background
• - CTA caveats separating utility delivery from third-party gas supply

First cargo is a commissioning milestone, not proof of full commercial operation or sustained daily feedgas demand. DOE FTA and non-FTA authorizations describe overlapping destination permissions and must not be added together. Proposed Phase 2 capacity is not operating capacity.

• - July 8 first LNG cargo from Energia Costa Azul Phase 1
• - 0.4 Bcf/d nominal Phase 1 capacity and U.S.-sourced natural gas supply path
• - 2.2 Bcf/d North American Pacific Coast LNG capacity comparison
• - Separate 0.50 Bcf/d FTA and 0.44 Bcf/d non-FTA Phase 1 authorizations
• - Commercial-buyer interpretation of commissioning, feedgas, basis, and contract exposure

A FERC staff final EIS informs the Commission record but is not a certificate order, construction authorization, in-service approval, or guarantee of the applicant schedule or customer price effects.

• - 110.9 miles of proposed new pipeline facilities across nine Mississippi counties
• - Proposed Greenville Lateral transfer and Gulf South/Texas Gas project scope
• - December 2026 proposed construction start and April 28, 2028 proposed service date
• - Staff environmental findings and separation from Commission certificate approval
• - Commercial-buyer interpretation of future infrastructure, basis, and delivery exposure

The FERC action authorizes construction, modification, and operation; it does not establish that the new capacity is built or in service. Existing Leaf River facility metrics are labeled separately and are not used to infer a final expansion total, delivered-rate change, or supplier offer.

• - 19.18 Bcf increase in certificated working-gas capacity
• - New Home Salt Dome Storage Facility approval state and Mississippi county footprint
• - Existing Leaf River facility injection, withdrawal, and listed working-capacity context
• - Commercial-buyer interpretation of future Gulf and Southeast storage flexibility

The order creates federal reliability and registration milestones. It does not set a retail tariff, approve a specific data-center connection, assign a customer bill impact, or guarantee the final scope of later NERC standards.

• - December 31, 2026 deadline for computational-load Reliability Standard filings
• - December 31, 2026 expectation for Rules of Procedure and entity-registration revisions
• - March 1, 2027 deadline for NERC standards-development workplan
• - Issued-order status and pending-implementation framing

EIA datasets are the primary backbone for public U.S. energy benchmarks. Forecast series are labeled separately from reported historical data.

• - Commercial and industrial electricity benchmarks
• - Natural gas price and consumption datasets
• - Short-Term Energy Outlook forecasts

Today in Energy articles should be cited with publication date, source note, and whether a claim is EIA analysis, third-party data referenced by EIA, or KilowattLogic interpretation.

• - Current EIA analysis of energy prices, supply disruptions, exports, and market context
• - Narrative source backing for source-reported facts that are not exposed as simple API values
• - Federal context for procurement-risk analysis and article updates

Use this source for EIA-reported curtailment context. Avoid converting curtailment values into contract, REC, or bill impacts without explicit buyer-contract caveats.

• - SPP and MISO wind curtailment context
• - Definition of curtailment as reduction below maximum generation potential
• - SPP hourly wind curtailment trend from 2019 through 2023

Use this source for the May 11, 2026 EIA record-production update. Separate EIA-reported production facts from KilowattLogic interpretation of delivered-rate, capacity, basis, and utility-charge implications.

• - 2025 U.S. primary energy production record context
• - Dry natural gas, crude oil, NGPL, renewable, and coal production facts
• - Supply-side context for commercial electricity and natural gas procurement coverage

Use this source for preliminary U.S. energy-related CO₂ estimates. Do not present it as an all-greenhouse-gas inventory, facility Scope 1/2 calculation, retail-rate forecast, or proof of a renewable-energy claim.

• - 2025 U.S. energy-related carbon dioxide emissions change
• - Electric-power sector emissions and generation-mix context
• - Direct commercial-sector emissions and weather-related fuel-use context
• - Scope and methodology boundaries for commercial buyer interpretation

Use this source for the May 20, 2026 EIA MISO dark-spread update. Keep wholesale fuel-margin data separate from delivered-rate claims, retail supplier offers, capacity charges, transmission charges, and KilowattLogic procurement interpretation.

• - MISO dark-spread and spark-spread comparison for early 2026
• - Winter Storm Fern wholesale fuel-margin context
• - Buyer caveats separating wholesale fuel economics from delivered commercial rates

Use this source for current California natural-gas-price coverage. Keep spot-index facts separate from delivered utility bills, CTA supplier offers, winter-basis forecasts, and KilowattLogic procurement interpretation.

• - California PG&E Citygate, SoCal Border, and SoCal Citygate spot-price context
• - Pacific-region natural gas storage cushion context
• - California gas-fired power-demand and commercial gas procurement caveats

Use this source for the May 5, 2026 EIA Virginia data-center article. Separate reported historical sales and peak-load values from PJM forecast values and KilowattLogic buyer interpretation.

• - Virginia commercial electricity sales growth from 2019 through 2025
• - Dominion zone peak-load history and PJM forecast context
• - Data-center load-growth analysis for Northern Virginia procurement coverage

Use this source for EIA-reported interchange, utilization, load, and outage context. It does not establish a customer-specific price reduction, capacity-market outcome, supplier offer, or continuous CHPE availability.

• - July 3 NYISO imports from Canada and share of system demand
• - Full 1,250 MW CHPE utilization during the early-July heat wave
• - CHPE June outage and July 4 repair-outage context
• - Commercial-buyer distinction between operating capacity, availability, and delivered-rate outcomes

Use this source for CAISO generation-mix facts. Keep utility-scale CAISO generation data separate from rooftop solar, delivered retail rates, supplier quotes, and guaranteed bill-savings claims.

• - CAISO utility-scale solar and natural gas generation comparison for January-May 2026
• - CAISO solar, battery storage, and natural gas capacity context from April 2024 to April 2026
• - California commercial electricity buyer context for daytime solar, evening gas exposure, imports, and storage

Use this source for national nameplate battery-capacity facts. Keep operational capacity separate from operator plans, and do not infer CAISO oversaturation, project completion, wholesale prices, demand-charge savings, or delivered-rate outcomes.

• - U.S. operational utility-scale battery storage capacity through June 2026
• - First-half 2026 battery capacity additions
• - Operator-reported planned additions for second-half 2026, 2027, and 2028
• - Named solar-plus-storage project scale and operating-status context

Use this source for SPP market-monitor facts. Separate MMU-reported wholesale values from KilowattLogic interpretation of VPPA, REC, retail-rate, natural-gas-tariff, and procurement-contract impacts.

• - SPP 2025 negative price interval shares and 2024 comparison
• - SPP Panhandle Eastern hub gas-cost, day-ahead price, real-time price, and congestion-payment metrics
• - SPP market-monitor context for surplus energy, congestion, gas-fired marginal cost, and day-ahead versus real-time wind patterns

Use this source for AEO2026 long-term planning context. Label AEO as alternative-futures scenario analysis, not a single prediction, delivered-rate forecast, supplier quote, or utility tariff.

• - AEO2026 electricity demand growth range through 2050
• - Data center server electricity use range of 446 BkWh to 818 BkWh by 2050 across AEO2026 cases
• - Server electricity use share of commercial-sector electricity in 2025 and 2050
• - Data-center cooling intensity assumptions for commercial-building electricity demand
• - Installed electric generating capacity growth range across AEO cases

Use this source for company-reported merger facts. Separate announced terms from regulatory approval outcomes, future rate impacts, data-center cost-allocation assumptions, and KilowattLogic buyer interpretation.

• - NextEra-Dominion merger transaction terms and ownership split
• - Combined utility account, generation portfolio, and large-load pipeline claims
• - Regulatory approval path and Dominion customer bill-credit proposal

Use this source for EIA's August 26, 2026 release of June regional wholesale market data. Keep wholesale prices and peak-demand observations separate from utility tariffs, supplier offers, capacity and transmission charges, taxes, and account-specific delivered costs.

• - MISO June 2026 daily wholesale electricity price range
• - MISO June 30 trailing-12-month daily peak-demand comparison
• - Commercial-buyer caveats separating wholesale conditions from delivered rates

Use the August 2026 issue for reported June national natural gas data. Keep EIA actuals separate from forward price forecasts, supplier offers, regional basis quotes, and delivered-rate claims.

• - June 2026 U.S. dry natural gas production, consumption, and sector deliveries
• - June 2026 electric-power natural gas deliveries and LNG export levels
• - KilowattLogic May-to-June calculations from the current EIA issue
• - Natural gas supply-demand context for Henry Hub, LNG, and gas-indexed electricity procurement

Storage values are point-in-time EIA estimates and may be revised. Do not convert a national storage print into a guaranteed delivered-rate, supplier-offer, or electricity-price claim.

• - June 25, 2026 weekly storage report for week ending June 19, 2026
• - Lower 48 working gas, weekly injection, year-over-year, and five-year-average comparisons
• - Natural gas procurement context for gas-indexed electricity buyers

Storage values are point-in-time EIA estimates and may be revised. Do not convert a national storage print into a guaranteed delivered-rate, supplier-offer, or electricity-price claim.

• - July 2, 2026 weekly storage report for week ending June 26, 2026
• - Lower 48 working gas, weekly injection, year-over-year, and five-year-average comparisons
• - Natural gas storage context for Henry Hub, LNG, regional basis, and gas-indexed electricity buyers

Storage values are point-in-time EIA estimates and may be revised. Do not convert a national storage print into a guaranteed delivered-rate, supplier-offer, or electricity-price claim.

• - July 9, 2026 weekly storage report for week ending July 3, 2026
• - Lower 48 working gas, weekly injection, year-over-year, and five-year-average comparisons
• - Natural gas storage context for Henry Hub, LNG, regional basis, and gas-indexed electricity buyers

Storage values are point-in-time EIA estimates and may be revised. Do not convert a national storage print into a guaranteed delivered-rate, supplier-offer, or electricity-price claim.

• - July 16, 2026 weekly storage report for week ending July 10, 2026
• - Lower 48 working gas, weekly injection, year-over-year, and five-year-average comparisons
• - Natural gas storage context for Henry Hub, LNG, regional basis, and gas-indexed electricity buyers

Storage values are point-in-time EIA estimates and may be revised. Do not convert a national storage print into a guaranteed delivered-rate, supplier-offer, or electricity-price claim.

• - July 23, 2026 weekly storage report for week ending July 17, 2026
• - Lower 48 working gas, weekly injection, year-over-year, and five-year-average comparisons
• - Natural gas storage context for Henry Hub, LNG, regional basis, and gas-indexed electricity buyers

Storage values are point-in-time EIA estimates and may be revised. Do not convert a national storage print into a guaranteed delivered-rate, supplier-offer, or electricity-price claim.

• - July 30, 2026 weekly storage report for week ending July 24, 2026
• - Lower 48 working gas, weekly injection, year-over-year, and five-year-average comparisons
• - Regional storage withdrawals and natural gas basis context for commercial buyers

Storage values are point-in-time EIA estimates and may be revised. Do not convert a national storage print into a guaranteed delivered-rate, supplier-offer, or electricity-price claim.

• - August 6, 2026 weekly storage report for week ending July 31, 2026
• - Lower 48 working gas, weekly injection, year-over-year, and five-year-average comparisons
• - Regional storage withdrawals and natural gas basis context for commercial buyers

Storage values are point-in-time EIA estimates and may be revised. Do not convert a national storage print into a guaranteed delivered-rate, supplier-offer, or electricity-price claim.

• - August 13, 2026 weekly storage report for week ending August 7, 2026
• - Lower 48 working gas, weekly injection, year-over-year, and five-year-average comparisons
• - Regional storage withdrawals and natural gas basis context for commercial buyers

Use this source for crude-oil geopolitical risk and OPEC/OPEC+ market-share facts. Do not turn the article into a direct electricity-rate forecast or claim guaranteed U.S. delivered-cost impacts.

• - UAE crude oil production and effective production capacity context
• - OPEC and OPEC+ share of world crude oil production with and without UAE
• - Strait of Hormuz rerouting context for UAE and Saudi crude oil exports

Use this source for Permian associated-gas facts. Keep gas-oil-ratio and production-growth facts separate from live Waha basis quotes, pipeline nominations, supplier offers, and guaranteed procurement windows.

• - Permian marketed natural gas and crude oil production growth from 2021 to 2025
• - Permian gas-oil-ratio context for associated gas supply
• - Henry Hub and LNG supply-balance buyer context without delivered-rate guarantees

Use this source for EIA-reported Permian well-design and production facts. Keep upstream productivity separate from live Waha basis, pipeline nominations, supplier offers, and guaranteed delivered-rate outcomes.

• - Permian horizontal-well lateral-length changes from 2015 to 2025
• - 2025 super-lateral completion share and stable annual completion-count context
• - Permian hydrocarbon production growth and associated-gas supply interpretation

Use this source for current petroleum-product price and supply context. EIA uses estimates for the week ending September 5 based on data through September 3. Do not convert national or regional gasoline, crack-spread, import, or inventory figures into a facility-specific fuel quote, electricity-rate forecast, or guaranteed procurement result.

• - September 2026 U.S. and regional regular-gasoline retail averages
• - Gasoline crack-spread comparison with 2025
• - Gasoline import and gasoline/distillate inventory comparisons with five-year averages
• - Fuel, fleet, logistics, and backup-generation risk framing without electricity-rate claims

Use this source for petroleum inventory and fuel-market context. Do not turn weekly crude, gasoline, distillate, or propane stock figures into a direct electricity-rate forecast, supplier quote, or guaranteed procurement recommendation.

• - Commercial crude oil inventory, refinery utilization, and import context for week ending June 19, 2026
• - Gasoline, distillate, propane, and total petroleum stock context versus five-year average
• - Fuel-market risk framing for logistics, backup fuel, and second-order energy exposure without delivered-rate claims

Values are reported by month and should be cited with the reporting period and release context.

• - Average commercial revenue per kilowatthour by state
• - Average industrial revenue per kilowatthour by state
• - National and state electricity benchmark comparisons

Storage reports should be cited with the week-ending date and release date.

• - Working gas in underground storage
• - Weekly injection and withdrawal changes
• - Storage comparisons against prior year and five-year average

EIA released this report on August 20, 2026 at 10:30 a.m.; cite 3,169 Bcf total and the 16 Bcf injection as week-ending August 14 estimates, not a supplier quote or delivered-rate forecast.

• - Lower 48 working gas for week ending August 14, 2026
• - August 20, 2026 weekly injection and regional storage changes
• - Storage comparisons against prior year and five-year average

EIA released this report on August 27, 2026 at 10:30 a.m.; cite 3,184 Bcf total and the 15 Bcf injection as week-ending August 21 estimates, not a supplier quote or delivered-rate forecast.

• - Lower 48 working gas for week ending August 21, 2026
• - August 27, 2026 weekly injection and regional storage changes
• - Storage comparisons against prior year and five-year average

EIA released this report on September 3, 2026 at 10:30 a.m.; cite 3,214 Bcf total and the 30 Bcf injection as week-ending August 28 estimates, not a supplier quote or delivered-rate forecast.

• - Lower 48 working gas for week ending August 28, 2026
• - September 3, 2026 weekly injection and regional storage changes
• - Storage comparisons against prior year and five-year average
• - Week-over-week storage-cushion and regional-flow analysis

EIA released this weekly storage report on May 7, 2026 at 10:30 a.m.; values should be cited as week ending May 1, 2026.

• - Lower 48 working gas for week ending May 1, 2026
• - May 7, 2026 weekly injection and regional storage changes
• - Storage comparisons against prior year and five-year average

EIA released this weekly storage report on May 14, 2026 at 10:30 a.m.; values should be cited as week ending May 8, 2026.

• - Lower 48 working gas for week ending May 8, 2026
• - May 14, 2026 weekly injection and regional storage changes
• - Storage comparisons against prior year and five-year average

EIA released this weekly storage report on May 21, 2026 at 10:30 a.m.; values should be cited as week ending May 15, 2026.

• - Lower 48 working gas for week ending May 15, 2026
• - May 21, 2026 weekly injection and regional storage changes
• - Storage comparisons against prior year and five-year average

EIA released this weekly storage report on May 28, 2026 at 10:30 a.m.; values should be cited as week ending May 22, 2026.

• - Lower 48 working gas for week ending May 22, 2026
• - May 28, 2026 weekly injection and regional storage changes
• - Storage comparisons against prior year and five-year average

EIA released this weekly storage report on June 4, 2026 at 10:30 a.m.; values should be cited as week ending May 29, 2026.

• - Lower 48 working gas for week ending May 29, 2026
• - June 4, 2026 weekly injection and regional storage changes
• - Storage comparisons against prior year and five-year average

EIA released this weekly storage report on June 18, 2026 at 10:30 a.m.; values should be cited as week ending June 12, 2026.

• - Lower 48 working gas for week ending June 12, 2026
• - June 18, 2026 weekly injection and regional storage changes
• - Storage comparisons against prior year and five-year average

EIA released the November 2025 storage-capacity report on May 21, 2026. Do not treat annual capacity changes as a weekly price forecast.

• - Lower 48 demonstrated peak storage capacity
• - Lower 48 working gas design capacity
• - Storage-capacity context for weekly inventory reports

PJM usage and redistribution terms should be checked before reproducing raw Data Miner output.

• - PJM market reports and operating data
• - Capacity-market context
• - Public wholesale market datasets

Capacity values should be tied to the delivery year, auction type, report date, and whether the value is a final clearing price or pre-auction planning parameter.

• - PJM capacity auction clearing-price context
• - Delivery-year capacity-market schedules and supporting files
• - Capacity-cost exposure in PJM procurement coverage

ERCOT API and data-access routes should be cited by report name, delivery channel, and retrieval date where practical.

• - ERCOT public market reports
• - Texas large-load and settlement-price context
• - Market transparency datasets

NYISO data should be tied to the relevant market, zone, date, and report surface.

• - New York wholesale market context
• - LBMP and load-related market reporting
• - Installed capacity and system-condition context

Preliminary and final market values should be labeled distinctly when that distinction matters.

• - New England LMP and load data
• - Wholesale cost and ancillary-service context
• - Winter reliability and market reform reporting

CAISO OASIS provides real-time and market-result data; pages should identify the report or market interval used.

• - California wholesale market prices
• - System demand and transmission context
• - CAISO market-result reporting

EDAM participation and benefit claims should distinguish official launch/participant status from future rate-case pass-through analysis.

• - Western day-ahead market launch and participant status
• - EDAM report availability, reliability-capacity metrics, and transfer context
• - Western market-design coverage for commercial buyers

MISO market-report values should be linked to the applicable market report, auction period, or planning case.

• - MISO market report data
• - Planning Resource Auction context
• - Midwest capacity and reliability reporting

MISO PRA values should preserve season, local resource zone, annualized framing, and posting date.

• - MISO seasonal and annualized capacity prices
• - Resource adequacy and local resource zone capacity context
• - Midwest capacity-cost mitigation coverage

This source reports wholesale capacity-auction results. It does not establish a customer-specific delivered rate, supplier offer, tariff pass-through, PLC obligation, or guaranteed demand-response payment.

• - 2028/2029 Base Residual Auction clearing price and cleared UCAP
• - RPM plus FRR capacity relative to the RTO Reliability Requirement
• - Installed reserve margin, new generation, uprates, and large-load planning context
• - Longitudinal comparison with the 2027/2028 Base Residual Auction

Use this outlook for May 2026 seasonal reliability facts. Treat adequate-resources language as PJM reliability planning context, not as a retail price forecast or delivered-rate guarantee.

• - PJM summer 2026 peak-load forecast
• - Source-reported generation capacity and contracted demand-response values
• - Seasonal reliability and load-management planning context

Use this FERC assessment for summer 2026 reliability and market context. Separate reliability adequacy findings from delivered-rate forecasts, supplier offers, and guaranteed bill outcomes.

• - Summer 2026 regional reliability risk context
• - Natural gas basis and wholesale power price expectations
• - Hydropower, drought, and extreme-weather buyer-risk analysis

Use this NERC assessment for reliability-risk labels and regional source facts. Do not convert reliability risk categories into retail-rate claims without visible caveats and account-specific context.

• - NPCC-New England, Texas RE-ERCOT, and WECC-Northwest summer risk findings
• - Demand and resource trends across NERC assessment areas
• - Large-load, hydropower, low-wind, and battery-addition context

Use ERCOT public notices for specific operating messages and timestamps. Do not convert these notices into emergency, load-shed, retail-rate, or guaranteed price claims unless ERCOT makes those claims directly.

• - ERCOT Non-Spin deployment notices
• - Sudden generation-loss operational postings
• - Texas summer operating-signal analysis

Use each notice as a time-stamped operating fact. Totals for later postings sum only quantities ERCOT described as additional; do not recast the sequence as an emergency, load-shed event, retail-price forecast, or customer-bill result.

• - August 29 and 30 Non-Spin deployment sequences and full recalls
• - Comparison of initial deployments with explicitly additional notices
• - Daily no-sudden-generation-loss-above-450-MW status

Use the September 2 postings as time-stamped operating facts. The 1,208.9 MW total combines the initial 888.4 MW posting with four later deployment postings and is KilowattLogic analysis; do not recast the sequence as an emergency, load-shed event, retail-price forecast, or customer-bill result.

• - September 2 Non-Spin deployment sequence and full recall
• - Combination of the initial deployment with later time-stamped postings
• - Daily no-sudden-generation-loss-above-450-MW status

Use this source for ERCOT's July 27 methodology disclosure. The approximately 3,700 MW figure is an average corrected hourly ECRS-plus-Non-Spin requirement difference, not load shed, an outage total, or a measured operating shortfall. ERCOT reported no reliability issue and did not revise posted August quantities.

• - Corrected ECRS and Non-Spin model requirement difference
• - ERCOT reliability finding and August 2026 procurement posture
• - Buyer caveats separating methodology and settlement risk from retail-rate or load-shed claims

Use this source for ERCOT Batch Zero process and current-status facts. ERCOT did not publish an aggregate qualified-load or MW total in the September 3 notice. Provisional or conditional classification, QSA inclusion, model review, and verification milestones are not final qualification, approval to energize, confirmed demand, guaranteed transmission cost, or delivered-rate impact.

• - Batch Zero effective date and July 2026 submission milestones
• - September 3 provisional-classification issuance and dispute/reconciliation sequence
• - Verification, model-data-cure, and PUCT-exception conditions
• - Limited 14-business-day alternate-eligibility-material window for specified loads
• - Dynamic-model review results and cure-period status
• - Quarterly Stability Assessment load counts and non-energization caveat
• - December 10 eligibility and community-impact report target
• - Large-load queue scale and data-center share from ERCOT June 2026 materials
• - Buyer caveats separating interconnection queue pressure from confirmed load, retail rates, and supplier offers

Use EIA reliability metrics as territory- and utility-level annual averages. They do not predict a specific facility outage, establish a battery or generator runtime, or prove the economics of a resilience project. KilowattLogic calculates the approximate 18-to-1 duration comparison from EIA's reported 36-hour Puerto Rico and roughly two-hour mainland values.

• - Puerto Rico 2025 average outage duration with and without major event days
• - Puerto Rico 2025 average interruption frequency with and without major event days
• - Comparison with mainland U.S. utility interruption duration
• - Commercial continuity-planning caveats and KilowattLogic ratio calculation

FERC claims should cite the order, docket, filing, or notice when available.

• - Federal energy orders and rulemakings
• - Capacity-market and transmission-policy actions
• - Regulatory enforcement and market-design context