Boston-area natural gas capacity: station shortfalls and one LNG terminal's contracts

By Sam Strong, Vice President of Business Development, Discovery Energy. Technical review by Tara Dugger, Chief Operating Officer. Updated October 2026.

Metro used: the Boston-Cambridge-Newton, MA-NH metropolitan statistical area, as delineated in OMB Bulletin No. 23-01 (July 21, 2023): Middlesex, Essex, Suffolk, Norfolk and Plymouth counties (MA) plus Rockingham and Strafford counties (NH). Items are classified inside, outside or unclear using the town and division names in the registered plans; items outside the metro are shown as system context, not as Boston-metro constraints.¹⁴

Key takeaways

Which parts of the record fall inside the Boston metro?

Town-to-county assignments were made manually and checked against the OMB county list (OMB Bulletin No. 23-01).¹⁴

Where does Boston Gas's hourly analysis show station-level shortfalls?

Boston Gas, doing business as National Grid, filed its plan in November 2024 (docket D.P.U. 24-164). It covers the Boston, Essex, Lowell and Cape Cod divisions; the first three are inside the metro. Its design hour is five percent of the design day, and Exhibit NG-4 models each of 37 pipeline take stations in those three divisions for winters 2024/25 to 2028/29, with portable LNG and the Tewksbury vaporization upgrade (winter 2027/28) included. Exhibit NG-4 labels a negative balance a "Shortfall."⁹

By that label, 22 of the 37 stations show a shortfall by 2028/29. By metro classification, at least 14 stations in every winter are in named towns inside the metro, up to 4 more have a plan label that gives no town and so are not located, and up to 3 are in Worcester County towns.⁹¹⁴ Three Tennessee Gas Pipeline (lateral 3) stations north of Boston, all inside the metro, show a shortfall in all five winters:

Total Firm Peak Hour Balance in Dth/hr, Exhibit NG-4. Station-level model results; stations on different pipelines are not netted against each other.⁹

The plan says peak-hour requirements can be served over the five-year period with portable LNG and the Tewksbury increase, and that hourly deficits can arise behind take stations without a daily deficit. NG-4 shows no station-level relief for these three stations. The DPU order records the design-hour requirement but makes no finding on the analysis or on any station.¹⁰

How much does the Boston metro depend on the Everett LNG terminal?

The Everett Marine Terminal (EMT), supplied under contracts with Constellation LNG, sits in Everett (Middlesex County). National Grid said in July 2023 that the terminal has a direct connection with National Grid's distribution system, and the Boston Gas plan describes vaporized LNG delivered directly into the distribution system in Everett.¹³ In 2024 the DPU approved six-year EMT contracts for Boston Gas, EGMA and NSTAR Gas, among others. EGMA's and NSTAR Gas's run through May 31, 2030; Boston Gas's last contract winter ends March 31, 2030.¹³

Boston Gas. In a July 2023 response to the DPU, National Grid said, for Boston Gas's whole Massachusetts system (not the metro alone), that Everett can meet about 15% of total design-hour requirements at design-day conditions, supports pressure on pipeline ends that feed about half of its Massachusetts take stations, and is used for design-hour, design-day and design-season needs. National Grid also said that additional vaporization and portable LNG generally do not help areas fed from Everett, and that replicating the service would need a new LNG plant in the Everett area. These are utility statements, not DPU findings. The DPU's 2025 order records that the company is evaluating ways to reduce or eliminate reliance on incremental EMT supply after the contract expires and must report in its next plan, due November 2026 and not in the record. No replacement is decided.¹⁶

NSTAR Gas, Cambridge division. NSTAR Gas's EMT contract with Constellation LNG totals 15,000 Dth/day: 5,000 Dth/day on the Algonquin G-System, and 10,000 Dth/day to Mystic on the J-System, which serves Cambridge, or into the Tennessee system at Everett. In January 2026 the DPU approved a 5,000 Dth/day pipeline agreement that covers all of NSTAR Gas's existing G-Lateral need. The DPU found that the agreement does not address NSTAR Gas's need for the EMT resource on the J-System in Cambridge, and expects NSTAR Gas to investigate all possible alternatives. The record does not show how that need is met after the current contract ends on May 31, 2030. The plan states the 10,000 Dth/day J-System volume as part of the contract; it does not state a Cambridge design day, so no share is computed.⁸

What is driving new natural gas demand in the Boston area?

The official records searched show no new large gas load in the metro. EIA's September 2026 generator inventory lists no planned natural gas-fired generators in Middlesex, Essex, Suffolk, Norfolk or Plymouth County, Massachusetts, or in Rockingham or Strafford County, New Hampshire.¹⁶ A search of FERC notices in the Federal Register since January 2025 found none that name one of those seven counties together with a natural gas pipeline docket.¹⁶ No data center or generator with a filing-confirmed service date was found, so no new load counts toward the outlook.

What is system context outside the metro?

Gap lines at EGMA and NSTAR Gas

Both plans balance their design-day tables because a supply line is counted as a resource, and in neither record is the line shown as contracted. The lines are company-wide, include divisions inside and outside the metro, and cannot be allocated to metro towns.

EGMA (Brockton, Lawrence, Springfield divisions; 2023 plan). The base-case design-day requirement reaches 538.4 BBtu by 2027/28. "Other Supplies" fills the difference: 21.2 BBtu by 2027/28, which is 3.9% of the design day (illustrative). The plan text describes it as a modest resource deficiency to be served by peaking and spot supply, although an earlier page says the portfolio is sufficient without incremental resources. The DPU found supplies adequate because the company can reasonably be expected to secure incremental supplies; the January 2026 joint order describes an existing design-year deficiency through 2027/28.²⁴ A later EGMA plan was due in November 2025; it is not reviewed here.

NSTAR Gas (Worcester, Framingham, Cambridge, New Bedford divisions; 2024 plan). The base-case design-day requirement reaches 568.1 BBtu by 2028/29. "Winter Service Supplies" (labelled "Citygate Supplies" in Table G-23) fill the gap: 46.8 BBtu by 2028/29, or 8.2% of the design day, and 12.7% in the high-growth case. The plan says directly that the company has a deficiency in all five years, mostly on the Tennessee system. The DPU again found supplies adequate on the expectation that incremental supplies can be secured.³⁴ A later NSTAR Gas plan, D.P.U. 26-94, has been filed; it is not reviewed here.

Boston Gas. Its resource tables carry no such line: across the twelve design-year and design-day pages (base, high and low cases) the resources are named pipeline, storage and LNG lines, unserved load is zero and the one unlabelled row is zero throughout.⁵

A gap line is a modeling choice, not a failure; a utility can plan to buy supply on the day or season. Zero unserved load in the models says the gap was assumed purchased, not that it was bought.⁴

Algonquin G-Lateral approvals

In January 2026 the DPU approved firm transportation agreements on the Algonquin G-Lateral. EGMA's 25,000 Dth/day agreement from November 1, 2029 serves its South Attleboro and Taunton interconnections and covers 74% of a stated 34,000 Dth/day need; the DPU found it removes the need to extend EGMA's EMT contract beyond 2030. The remaining 9,000 Dth/day is described in the order, citing EGMA's testimony, only as "seasonal supplemental supply"; the order names no supplier or contract, so how it is covered is not established. NSTAR Gas's 5,000 Dth/day agreement serves New Bedford. These approvals are outside the metro and do not bear on the Cambridge or Boston Gas items above.⁷⁸

Winter and market context

Context only, as of October 2026. It does not set the outlook level and makes no prediction of outages. Official sources are used wherever they exist; named market and news sources are used only where no official source exists, and each is attributed and dated. Its sources are listed separately under Market and weather sources, and its storage, price and outlook figures are refreshed on the publication date.

NOAA's Climate Prediction Center issued its long-lead seasonal outlook on October 15, 2026, a national discussion that names regions and not utility systems.^A1 The U.S. Energy Information Administration said on October 6, 2026 that it expects U.S. natural gas inventories to enter the winter heating season 2% above the previous five-year average, and that milder Northeast weather offsets part of the expected rise in heating oil prices.^A2 EIA's October 2026 Short-Term Energy Outlook says prolonged periods of cold weather could increase withdrawals beyond its forecast.^A3 These are national and regional facts, not statements about National Grid's or Eversource's systems, and none of them is used to set the outlook on this page.

How do global LNG markets reach Boston?

The Everett Marine Terminal is an LNG import terminal, so Boston-area winter supply is tied to the world LNG market in a way most U.S. metros are not. EIA's monthly import data show 2,165 million cubic feet of LNG from Trinidad and Tobago entering at Everett in February 2026 and none from that country from March to July.^A6 In its September 2025 petition to the DPU, EGMA said the number of LNG cargoes received in New England has declined significantly over the last decade, in part because LNG providers receive better pricing elsewhere in the world.¹⁸ ISO New England reports that LNG sendout into New England in winter 2026 was about 45.9 million MMBtu, against 22.4 million the winter before, driven primarily by higher volumes from Everett and St. John.^B2

What changed in 2026. ACER, the EU's agency for energy regulators, says the closure of the Strait of Hormuz is affecting global and European energy and LNG markets.^A5 CNBC reported on July 1, 2026 that Iranian missile attacks in March damaged two LNG trains at Qatar's Ras Laffan complex, curtailing production by 12.8 million tons a year, about 17% of Qatar's LNG exports, and that an Italian buyer said QatarEnergy had extended a force majeure notice, withholding four more cargoes until early September.^A12 The International Energy Agency said on April 24, 2026, as reported by Engineering News, that the conflict could remove around 120 billion cubic metres of LNG supply between 2026 and 2030, 15% of expected global supply, and that each month without LNG cargoes through the strait costs around 10 billion cubic metres.^A11

Europe is competing for the same cargoes. ACER says Russian pipeline gas and LNG together still covered at least 14% of EU gas imports in 2025-2026, and that the United States supplies over 60% of the EU's LNG.^A5 Under Regulation (EU) 2026/261, Russian LNG under short-term contracts could be imported only until April 25, 2026, and Russian LNG under long-term contracts, allowed to continue to the end of 2026, is prohibited from January 1, 2027.^A4A5 European storage was 74.62% full on October 24, 2026 on the Gas Infrastructure Europe AGSI+ platform (an estimated value), and Global LNG Hub, citing AGSI+, reported it down 16.5% from the five-year average on October 16.^A8A10 U.S. storage is the reverse: EIA's weekly table shows 3,644 Bcf of working gas on October 16, 2026,^A7 and EIA expects U.S. inventories to enter winter 2% above the five-year average.^A2

Prices. The European and Asian LNG benchmarks have no official source, so a named market source is used. Global LNG Hub reported the European benchmark (TTF) at USD 28.9/MBtu and the Northeast Asian benchmark (JKM) in the high USD 29s/MBtu on October 16, 2026.^A10 EIA's Henry Hub spot price was $3.10 per MMBtu on October 20, 2026.^A9

Why this matters for Boston. In Discovery Energy's reading of the market, not a statement from these sources, an LNG cargo goes to the buyer that pays the most, so Everett competes with Europe and Asia for Atlantic cargoes during New England's coldest weeks. ISO New England found that New England gas pipelines were significantly constrained throughout winter 2026, that the region relied on LNG sendout during gas-scarce, high-priced periods, and that LNG only partially reduced the New England price premium.^B2 None of the sources says that Everett's contracted supply for Boston Gas or NSTAR Gas is short this winter (note 19).

The DPU record reviewed for this page contains no LNG price data, and none of this section changes the regulatory findings above.

What does the weather outlook say for this winter?

A very strong El Niño. NOAA's Climate Prediction Center said on October 8, 2026 that a strong-to-very-strong El Niño is likely through January-March 2027 (a chance greater than 83%), and put the chance that October-December exceeds the strength of every El Niño on record back to 1950 at 83%.^B1

The seasonal outlook favors a warmer East. The Climate Prediction Center's November 2026 to January 2027 outlook, issued October 15, favors above-normal seasonal mean temperatures across the northern tier and much of the East, includes the Great Lakes and interior Northeast among the areas with the highest odds, and gives an elevated likelihood of above-normal precipitation along the eastern seaboard.^A1

Milder on average is not the same as no cold snaps. The outlook gives odds for seasonal averages, not for individual cold days, and the gas system's stress comes from short, severe cold. Last winter shows the range: ISO New England reported a 19-day cold snap from January 23 to February 10, 2026, the longest since winter 2015.^B2

Last winter for comparison. ISO New England reported winter 2026 wholesale market costs of $6.5 billion, up 45% from the year before,^B2 and EIA reported that Lower 48 working gas stocks fell 360 Bcf in the week ending January 30, 2026, the largest weekly net withdrawal in the history of its storage report.^B3

Next updates. The Climate Prediction Center's next ENSO discussion is scheduled for November 12, 2026,^B1 and its official 90-day outlooks are issued once each month near mid-month.^A1

What could stress Boston's gas supply this winter?

This is Discovery Energy's qualitative assessment, based on the historical record and the conditions described above. It is not a statistical model and not a forecast. It is not an outage forecast: the rows are conditions that could stress supply.

What past crises looked like. Boston's recent winter emergencies have shown up as extreme prices and electric-grid stress:

• Winter 2026 overall. ISO New England reports the highest wholesale prices of any winter since 2014.^B2
• January 2026 (Winter Storm Fern). Algonquin prices reached approximately $122/MMBtu on January 27, and ISO New England describes the New England gas price as a record high.^B2 The U.S. Department of Energy issued an emergency order for ISO New England in effect from January 25 through January 31, 2026.^C1 Oil supplied 6% of New England's winter supply in winter 2026, up from 2% the winter before, and oil generation exceeded gas generation on several days of the cold snap.^B2

The ISO New England report and the DOE release reviewed for this section describe prices, oil burn and grid emergency measures. A code search of both found no report of a loss of firm gas distribution service to Boston-area customers.^B2C1

In Discovery Energy's client experience, firm customers kept service through these events; interruptible customers were curtailed, as their service terms allow.

Conditions that could stress supply, winter 2026-27, with Discovery Energy's qualitative assessment of each (not a forecast).

What would raise the odds: deep cold in January or February coinciding with the January 1 EU ban on Russian LNG; renewed escalation in the Strait of Hormuz or further damage to Qatari capacity; delays to Everett cargoes; a major pipeline outage; or low regional fuel-oil inventories, as at the start of last winter.^B2

What would lower them: the above-normal temperatures the Climate Prediction Center favors;^A1 resumption of LNG cargoes through the strait, which the IEA says otherwise removes around 10 billion cubic metres of supply a month;^A11 and faster refilling of European storage.^A8

How rare is design-day weather?

The utilities' own plans state the odds they plan for. Boston Gas plans for design-day weather at a 1-in-40.3-year frequency, EGMA at 1-in-33 and NSTAR Gas at 1-in-50.¹¹ Design-day weather has about a 2.5% chance in a given winter (Boston Gas's 1-in-40 standard; EGMA's and NSTAR Gas's standards are similar), based on historical weather. That is the chance of reaching the planned limit, not of losing service. On February 3, 2023, conditions exceeded EGMA's Springfield design day and reached 99% of design at Lawrence and 95% at Cambridge.¹⁵

Why aren't these three plans directly comparable?

• Different design-day standards. Boston Gas plans for 78 equivalent degree days at a 1-in-40.3-year frequency. EGMA uses a 1-in-33-year design day (78 equivalent degree days in Brockton and Springfield, 80 in Lawrence). NSTAR Gas uses a 1-in-50-year design day (88, 81 and 79 equivalent degree days by division). A stricter standard raises the requirement a plan must cover.¹¹
• Only Boston Gas quantifies the design hour. EGMA's plan has no design-hour requirement or take-station balance. NSTAR Gas's plan describes a design-hour criterion with no value and no results.¹¹
• Different years and denominators. The plans cover different forecast periods, and each percentage on this page is a volume divided by that company's own design day for the same winter. They should not be added or ranked.¹¹¹²

What does this mean for business gas costs?

The record contains no customer-class cost allocation, rate or bill figure for any of these supply decisions, so none is given here. The relevance for commercial and industrial customers is structural. Replacements for the Everett contracts after 2030 and any change to the stations above would have to be contracted and approved in later DPU proceedings, and who bears their cost is not decided in these orders. Hourly limits at take stations matter most on the coldest days. Facilities served from the Boston Gas stations north of Boston, or on NSTAR Gas's Cambridge system, are the most directly connected to the inside-metro items above.⁸⁹

What is the outlook for Boston gas capacity through 2029?

Discovery Energy rates the outlook for Boston-area natural gas capacity through 2029 as High (confidence: Medium): Boston Gas's own hourly analysis shows negative peak-hour balances at take stations inside the metro in every winter from 2024/25 to 2028/29, at least 14 of its 37 stations each winter, and the DPU made no finding on them.⁹¹⁰ Documented risk factors: concentration (F1), since National Grid said in July 2023 that the Everett Marine Terminal can meet about 15% of Boston Gas's total design-hour requirements at design-day conditions, a figure for its whole Massachusetts system and not the metro alone;¹ and a more likely design day (F6), since Boston Gas now plans for a 1-in-40.3-year design day, from 1-in-47.9 in its previous plan.¹¹ Two factors would raise a base level by one step, but a raise cannot produce Severe, so the level stays High. Expiring supply (F2) is not counted for the Everett agreement: the plan states no firm interstate pipeline capacity total to test it against, and the agreement is 5.35% of the 2028/29 design peak day by our calculation, below the 10% test. Three developments would change the assessment: National Grid's next plan, due November 2026, and what it says about replacing Everett supply after 2030; whether Burlington, Arlington and Revere remain in shortfall in Boston Gas's next hourly analysis; any DPU action on alternatives for NSTAR Gas's J-System need in Cambridge, and NSTAR Gas's later plan (docket D.P.U. 26-94, filed and not reviewed here).

Outlook levels, from least to most concern: Stable, Watch, Elevated, High, Severe. Levels describe the public record of capacity and supply risk; confidence is reported separately. They are qualitative assessments, not forecasts of outages.

What should Boston-area facilities check now?

• Tariffs and charges, through a utility audit. Confirm each account is on the right rate class and tariff, and that riders, demand charges and capacity-related charges are billed correctly. Over 70% of the clients Discovery Energy has audited were billed incorrectly. An audit verifies tariffs and charges and recovers overcharges before winter costs rise.
• Which utility, division and station. Confirm the serving utility and division for each site, and whether it is fed from a Tennessee lateral north of Boston or the Algonquin J-System.
• Firm or interruptible, and the terms. Know whether each account is firm or interruptible. For interruptible or non-firm accounts, confirm notice periods, curtailment order and penalties before the first cold snap.
• Backup plans and fuel. Check that alternate-fuel and curtailment plans are current and feasible. Where dual-fuel equipment exists, check fuel inventories and resupply arrangements before December.
• Upcoming proceedings. Track the 2026 plan filings and any Everett replacement proceedings.
• Index price exposure in January and February. Know which accounts are priced at Algonquin or another daily index during peak months, and what a repeat of last January's prices would cost.

Frequently asked questions

Related case studies

Discovery Energy publishes gas capacity case studies for other metros, using the same method and outlook scale.

• Pittsburgh natural gas capacity case study (outlook: High)
• Detroit natural gas capacity case study (outlook: High)
• Salt Lake City area natural gas capacity case study (outlook: High)
• South-central Pennsylvania natural gas capacity case study (outlook: Elevated)

Notes

1. National Grid (Boston Gas), response to DPU Everett inquiry, July 2023, PDF 8, PDF 2, PDF 4, PDF 9. The 15% is National Grid's July 2023 statement, covering Boston Gas's whole Massachusetts system, not the metro alone; it is not recomputed and it is not a DPU finding. ↩
2. EGMA plan, D.P.U. 23-125: Table I-4 PDF 99 [97]; Table G-23 PDF 126. Shares are each year's line divided by that year's design day; illustrative. ↩
3. NSTAR Gas plan, D.P.U. 24-106: Figure 47 PDF 104 [97]; Table G-23 PDF 131; high growth Figure 49 PDF 106. Shares are each year's line divided by that year's design day; illustrative. ↩
4. EGMA text: plan, D.P.U. 23-125 PDF 100 [98], PDF 96 [94]; DPU order D.P.U. 23-125 PDF 32 [30]; joint order D.P.U. 25-133/25-134 PDF 24 [21]. NSTAR Gas text: plan, D.P.U. 24-106 PDF 9 [2], PDF 103 [96]; DPU order D.P.U. 24-106 PDF 35 [33]; joint order D.P.U. 25-133/25-134 PDF 24. Contract status of the gap lines: not shown as contracted in either record. ↩
5. Boston Gas plan, D.P.U. 24-164 Tables G22-D and G23-D, PDF 134 and 137 [Page 43 and 46 of 74]; design day 1,406 to 1,457 BBtu. ↩
6. DPU order D.P.U. 24-164 PDF 34 [32], footnote 12; next plan due November 1, 2026; Boston Gas six-year agreement approved May 2024 (Boston Gas plan, D.P.U. 24-164 PDF 78). ↩
7. Joint order, D.P.U. 25-133/25-134, January 30, 2026: 25,000 Dth/day and 74% PDF 8-9 [5-6]; 34,000 Dth/day PDF 25 [22]; EMT beyond 2030 PDF 28 [25]; 9,000 Dth/day PDF 9 [6]; approval PDF 37-38. ↩
8. NSTAR Gas: plan, D.P.U. 24-106 PDF 84 [77] and 98 [91]; joint order D.P.U. 25-133/25-134 PDF 10 [7], PDF 12 [9], PDF 28 [25]. Contract counterparty Constellation LNG: NSTAR Gas plan, D.P.U. 24-106 PDF 14, Boston Gas plan, D.P.U. 24-164 PDF 78. ↩
9. Boston Gas Exhibit NG-4 workbook, D.P.U. 24-164: column label "Total Firm Peak Hour Balance (-) = Shortfall (+) = Surplus"; stations with a negative balance among the 37 take stations: 19, 20, 21, 20, 22. Each station is classified inside, outside or unclear using the town named in the plan. Design hour criterion: Boston Gas plan, D.P.U. 24-164 PDF 71 [69]. ↩
10. Boston Gas plan, D.P.U. 24-164 PDF 88 [86], PDF 73 [71]; DPU order D.P.U. 24-164 PDF 8 [6], footnote 5. The plan's 4.53% portfolio figure is not used: its basis is not established in the public record. ↩
11. Standards: Boston Gas plan, D.P.U. 24-164 PDF 68 [66]; EGMA plan, D.P.U. 23-125 PDF 70-71; EGMA design hour PDF 102 [100]; NSTAR Gas plan, D.P.U. 24-106 PDF 14 [7], DPU order D.P.U. 24-106 PDF 7 [5]; NSTAR Gas design hour NSTAR Gas plan, D.P.U. 24-106 PDF 14-15. Boston Gas's earlier 1:47.9: DPU order D.P.U. 24-164 PDF 8 [6]; National Grid Everett response PDF 8. Orders finding standards reviewable: DPU order D.P.U. 24-164 PDF 11-12, DPU order D.P.U. 23-125 PDF 33, DPU order D.P.U. 24-106 PDF 36. ↩
12. Filing dates and plan periods as printed: Boston Gas 2024/25 to 2028/29; EGMA 2023/24 to 2027/28; NSTAR Gas 2024/25 to 2028/29. DPU order D.P.U. 24-164, DPU order D.P.U. 23-125, DPU order D.P.U. 24-106. Division lists: Boston Gas (Boston, Essex, Lowell, Cape Cod), EGMA (Brockton, Lawrence, Springfield), NSTAR Gas (Worcester, Framingham, Cambridge, New Bedford). ↩
13. Contract end dates: NSTAR Gas plan, D.P.U. 24-106 PDF 84; EGMA joint order D.P.U. 25-133/25-134 PDF 9; DPU notice D.P.U. 25-133/25-134; Boston Gas last contract winter Boston Gas plan, D.P.U. 24-164 PDF 78; 2024 approvals joint order D.P.U. 25-133/25-134 PDF 9. Direct connection: National Grid Everett response PDF 2; vaporized LNG delivered directly into the Everett distribution system: Boston Gas plan, D.P.U. 24-164 PDF 78 [76]. ↩
14. Metro and limits. Metro: Boston-Cambridge-Newton, MA-NH MSA per OMB Bulletin No. 23-01, July 21, 2023, delineation file PDF 49 (title, date and county list confirmed). No registered file gives the county of each town; the assignments were made manually and checked against the OMB county list. Plan labels with no town (Polaroid, Trapelo Rd, Maple St, Camp Curtis) are unclear. Boston Gas's Cape Cod division and the NG-4 stations outside rows 11-40, 50-59 are not in the 37-station count. The record has no pipeline capacity postings, event history, rate or bill data, and none of the later plans (National Grid due November 2026; EGMA due November 2025; NSTAR Gas docket 26-94). Quotes behind this page were checked against the saved sources; this verifies text presence, not meaning. ↩
15. Feb 3, 2023 observed against design-day EDD: EGMA plan, D.P.U. 23-125, PDF 69 (footnote: 79 EDD in Springfield, 79 in Lawrence) and PDF 71 (design days 78 Springfield, 80 Lawrence); NSTAR Gas plan, D.P.U. 24-106, Figure 39 PDF 64 (Cambridge, 02/03/23, 77 EDD) and Table DD PDF 111 (Cambridge design day 81). Percentages of design EDD are the observed value divided by the design value: Springfield 101.3%, Lawrence 98.8%, Cambridge 95.1%. These are the plans' own observations on one day, not a measure of service. ↩
16. R3 (expanded) search, October 2026, for new gas loads in or near the metro: EIA-860M September 2026 Planned sheet filtered by county; Federal Register FERC notices since January 2025 searched by county for pipeline (CP) dockets; both computed by code. Not established by code: ISO New England's interconnection queue (the public page is a dynamic table, saved but not scriptable); state air permit filings (a web search found no gas turbine application in Massachusetts; the Lowell data center filing covers diesel generators; no New Hampshire search was verified). News is leads only and none is used. ↩
17. Risk factors, Outlook Scale v2.3: F1 and F6 are counted (notes 1 and 11). F2 is not counted: Boston Gas's last-winter Everett contract is 5.35% of the 2028/29 design day, below the 10% test, and the plan states no firm interstate pipeline capacity total for the second test. F3, F4, F5 and F7 are not counted: the record shows no gas supply event tied to a shortfall, no new load with a service date, and no upstream pipeline limit capping a station inside the metro, and the F7 test (note 19) found no filing or official notice of availability stress for Everett's supply.
18. LNG cargo statement: EGMA petition, D.P.U. 25-133, September 2, 2025, PDF 25 (page 7 of 39 of the petition), redacted initial filing. A utility statement, not a DPU finding. It says the number of LNG cargoes has declined over the last decade because of pipeline projects, LNG providers receiving better pricing elsewhere, and a lack of forward contracts by buyers in New England; it does not say Boston Gas's or NSTAR Gas's contracted Everett supply is short. ↩
19. F7 (LNG supply availability stress), tested under Outlook Scale v2.3 with documented supply availability, not price. Documented, at global and regional level: the closure of the Strait of Hormuz affecting LNG markets (ACER, A5); an estimated 120 bcm of LNG supply loss between 2026 and 2030 and about 10 bcm lost for each month without transits (IEA, as reported by Engineering News, A11); withheld Qatari cargoes to an Italian buyer (A12); a decade-long decline in New England cargoes (note 18). Not documented: any filing or official notice that cargoes for Everett's contracted supply to Boston Gas or NSTAR Gas have been withheld or are short; a code search of the saved DPU texts for cargo, tanker, vessel and shipment found hits only in the EGMA petition (the passage in note 18, and a generic description of LNG tankers). F7 is therefore not counted; the evidence concerns the market, not Everett's own supply. If Tara Dugger reads F7 as counting market-wide supply stress for an LNG-dependent system, it would be a third factor, and the level would stay High because a raise cannot produce Severe. The level does not depend on this test.

Market and weather sources

Retrieved October 25, 2026 unless noted. Official sources come first; named market and news sources are used only where no official source exists, and each is marked. They are separate from the DPU-record notes above. Dated figures are refreshed on the publication date.

1. A1. NOAA Climate Prediction Center, Prognostic Discussion for Long-Lead Seasonal Outlooks, October 15, 2026 (official). Link ↩
2. A2. U.S. Energy Information Administration, press release, "EIA expects a mixed picture for winter fuel costs this year," October 6, 2026 (official). Link ↩
3. A3. U.S. Energy Information Administration, Short-Term Energy Outlook, October 2026 (official). Link ↩
4. A4. European Parliament and Council of the EU, Regulation (EU) 2026/261 of January 26, 2026 on phasing out Russian natural gas imports, recital 14 and Article 4 (official; Official Journal text saved from a manual download, quotes confirmed by code). Link ↩
5. A5. ACER, report on Russian gas imports and the implementation of Regulation (EU) 2026/261, 2026 (official EU agency). Link ↩
6. A6. U.S. Energy Information Administration, U.S. Liquefied Natural Gas Imports by Point of Entry, monthly, February to July 2026 (official). Link ↩
7. A7. U.S. Energy Information Administration, Weekly Working Gas in Underground Storage, week of October 16, 2026, released October 22, 2026 (official). Link ↩
8. A8. Gas Infrastructure Europe, AGSI+ storage inventory, EU aggregate, gas day October 24, 2026 (industry transparency platform; saved from a browser download). Link ↩
9. A9. U.S. Energy Information Administration, Henry Hub Natural Gas Spot Price, released October 21, 2026 (official). Link ↩
10. A10. Global LNG Hub, "Natural gas prices weekly update - JKM, TTF and Henry Hub," October 19, 2026 (named market source; TTF and JKM have no official source; AGSI+ storage as cited by the publisher). Link ↩
11. A11. Engineering News, "Middle East war could cause 120 bcm of LNG supply loss from 2026 to 2030 - IEA," April 24, 2026 (news report of the IEA's quarterly gas outlook; the IEA site blocks scripted access). Link ↩
12. A12. CNBC, "LNG market disruption: QatarEnergy extends force majeure with Edison," July 1, 2026 (news report; no official QatarEnergy statement could be downloaded; later extensions are not covered). Link ↩
13. B1. NOAA Climate Prediction Center, ENSO Diagnostic Discussion, October 8, 2026 (official). Link ↩
14. B2. ISO New England, 2026 Winter Quarterly Markets Report, July 2026 (official). Link ↩
15. B3. U.S. Energy Information Administration, Today in Energy, "Record natural gas stock withdrawals during week ending January 30, 2026," February 5, 2026 (official). Link ↩
16. C1. U.S. Department of Energy, news release, "Energy Secretary Secures New England and Texas Grids Amid Winter Storm Fern," January 25, 2026 (official). Link ↩
17. Map base data:. Natural Earth (public domain), coastline and roads, naturalearthdata.com.

Sources

1. Boston Gas Company (National Grid), Long-Range Forecast and Supply Plan, D.P.U. 24-164, November 1, 2024, with Exhibit NG-4 and Appendix B.
2. Massachusetts DPU, order on Boston Gas Company's plan, D.P.U. 24-164.
3. National Grid, response to the DPU's Everett Marine Terminal inquiry, July 2023.
4. Eversource Gas Company of Massachusetts, Long-Range Forecast and Supply Plan, D.P.U. 23-125, November 1, 2023; DPU order, October 25, 2024.
5. NSTAR Gas Company, Long-Range Forecast and Supply Plan, D.P.U. 24-106, July 19, 2024; DPU order, July 14, 2025.
6. Office of Management and Budget, OMB Bulletin No. 23-01, Revised Delineations of Metropolitan Statistical Areas, Micropolitan Statistical Areas, and Combined Statistical Areas, July 21, 2023.
7. Massachusetts DPU, joint order, D.P.U. 25-133 and D.P.U. 25-134, January 30, 2026; DPU notice.
8. U.S. Energy Information Administration, EIA-860M Preliminary Monthly Electric Generator Inventory, September 2026 (Planned sheet), and Federal Register notices of the Federal Energy Regulatory Commission searched by county, October 2026.

Figures are as reported in the sources above as of October 2026. Utility statements and DPU findings are kept separate. Nothing here is a decision, a score or a cost estimate.