Gas Supply Constraints

The Supply Chain

Nova Scotia has produced zero natural gas since 2018, when the last offshore fields (Sable Island and Deep Panuke) shut down permanently. Every molecule of gas consumed in the province now arrives via the Maritimes & Northeast Pipeline (M&NP), a 1,100 km mainline that was originally built to export Maritime gas south to New England. Since 2017, flow has reversed: the pipeline now imports U.S. gas northbound from Appalachian Basin production (Marcellus and Utica shale) through the New England pipeline network.

There is no underground gas storage in Nova Scotia or New Brunswick. The province depends on continuous pipeline flow, with no buffer against supply disruptions. This is fundamentally different from jurisdictions like Ontario (Dawn Hub storage) or the U.S. Northeast (various storage fields) where stored gas can meet short-term demand spikes.

Maritime Pipeline Capacity and Utilization

The M&NP has a design capacity of approximately 471 MMcf/d (13,335 thousand m³/d). On average, winter utilization has ranged from 35% to 44% over recent years, which sounds like ample headroom. But peak-day utilization tells a different story: single-day spikes have reached 57–67% of capacity, and the all-time peak northbound day was March 3, 2021, at 347 MMcf/d (73.7% utilization).

Winter	Winter Avg (MMcf/d)	Winter Utilization	Peak Day (MMcf/d)	Peak Utilization
2019–20	166	35.3%	280	59.5%
2020–21	171	36.4%	316	67.2%
2021–22	165	35.1%	308	65.4%
2022–23	171	36.4%	253	53.7%
2023–24	208	44.1%	283	60.0%
2024–25	191	40.7%	269	57.1%

What Two New Plants Would Mean

Nova Scotia currently consumes 77.2 MMcf/d of natural gas. The two proposed plants, at full capacity, would require approximately 120 MMcf/d combined - more than 155% of the province's entire current gas consumption. This gas would have to come through the same M&NP pipeline that already serves all of New Brunswick and Nova Scotia.

The pipeline has technical headroom: 42% utilization leaves room on paper. But the gas must transit through New England first, during the same winter conditions that cause supply constraints and price spikes there. The M&NP has never carried more than 347 MMcf/d northbound. Adding 120 MMcf/d of peaker demand to existing consumption means the pipeline would need to consistently deliver 200+ MMcf/d - achievable on average, but well above recent historical norms, and subject to the same upstream constraints that affect the entire U.S. Northeast.

Winter Supply Challenges

Peaker plants exist to run during grid emergencies - overwhelmingly winter events. But winter is precisely when gas supply is most constrained. The gas these plants would burn originates in the Appalachian Basin and must traverse the New England pipeline network before reaching Nova Scotia. During cold snaps, every pipeline in that network is under strain from heating demand, and the capacity left over for power generation shrinks dramatically.

New England Price Spikes

The Algonquin Citygate, the key pricing point for New England gas, demonstrates what happens when pipeline capacity hits its limits. During normal conditions, gas trades at a modest premium over the Henry Hub benchmark. During cold snaps, that premium explodes.

Event	Date	Algonquin Citygate Price	Context
Polar Vortex	Jan 2014	$80/MMBtu	6,000+ MW gas generation unavailable in ISO-NE
Bomb Cyclone	Jan 2018	$78.98/MMBtu	Gas dropped to 17% of ISO-NE gen mix; 2M+ barrels oil burned
Winter Storm Elliott	Dec 2022	$45+/MMBtu	90,500 MW unplanned outages nationwide
Winter Storm Fern	Jan 2026	$121.56–$122.58/MMBtu	All-time record; 79 national spot records broken

Gas Plants Fail During Cold Snaps

The historical record is unambiguous: gas-fired power plants systematically fail during the winter events when they are needed most. This is not a theoretical risk - it has happened repeatedly across every major grid in eastern North America.

Event	Gas Plant Impact
Polar Vortex, Jan 2014	Gas plants were 40% of installed capacity but 55% of all failures. Fuel supply issues caused ~40% of all outage MW. PJM saw 40,000+ MW of generation outages.
Bomb Cyclone, Jan 2018	Gas dropped to 17% of ISO-NE generation (from ~50% normal). Oil surged to 27%. New England burned 2M+ barrels of oil in two weeks - more than double all of 2016.
Winter Storm Uri, Feb 2021	Texas gas production declined 70%. A feedback loop: plants tripped, cutting power to gas compressor stations, further reducing supply. 246 deaths.
Winter Storm Elliott, Dec 2022	90,500 MW coincident unplanned outages. Gas plants were 42% of capacity but 63% of failures. Gas fuel issues caused 20% of all MW losses. Even ~10 GW of plants with firm gas contracts lost supply.
Winter Storm Fern, Jan 2026	ISO-NE shifted to majority oil generation for multiple days. Petroleum generation peaked at 8.0 GW. DOE issued Emergency Order 202-26-03.

How Gas Is Procured for Peaker Plants

A peaker plant must start generating electricity within 10–30 minutes of a dispatch instruction. But the natural gas system operates on a day-ahead nomination cycle where the primary scheduling window closes the day before gas flows. These two systems are fundamentally mismatched.

The Nomination Cycle

North American gas pipelines operate on a standardized "gas day" (9:00 a.m. to 9:00 a.m. Central Clock Time) with five nomination cycles established by FERC Order 809 (2015):

Cycle	Nomination Deadline	Gas Effective Flow	Notes
Timely (primary)	1:00 p.m. CCT, day before	9:00 a.m. next day	Main scheduling window; most gas is scheduled here
Evening	6:00 p.m. CCT, day before	9:00 a.m. next day	Adjustment window; can bump lower-priority shippers
Intraday 1	10:00 a.m. CCT	2:00 p.m. CCT	Same-day adjustment
Intraday 2	2:30 p.m. CCT	6:00 p.m. CCT	Same-day adjustment
Intraday 3	7:00 p.m. CCT	10:00 p.m. CCT	No-bump cycle - cannot displace existing shippers

The problem is straightforward: a peaker plant dispatched at 3:00 p.m. Eastern that did not nominate gas in the Timely cycle (deadline 2:00 p.m. Eastern) may have to wait until the Intraday 2 or Intraday 3 cycle for confirmed gas flow - hours after it was needed. The electric grid dispatches generators in 5-minute intervals; the gas system operates on day-ahead timelines with limited intraday adjustment.

Firm vs. Interruptible Transportation

Gas plants procure pipeline capacity through two primary contract types, each with a critical trade-off for peaker operations:

Firm transportation guarantees pipeline capacity. The plant pays a reservation charge year-round whether it runs or not, plus a per-unit usage charge. For a 200 MW peaker consuming ~2,000 MMBtu/hour, firm reservation charges translate to roughly $365,000–$730,000/year - a significant fixed cost for a plant that may run only 500–1,500 hours per year.

Interruptible transportation costs less (no reservation charge - you pay only for gas shipped), but the shipper is curtailed first when the pipeline fills up. During winter peaks, interruptible shippers may receive no gas at all. The pipeline confirms firm nominations first, allocates remaining capacity to interruptible shippers pro-rata, and if nothing remains, interruptible shippers get zero - with no advance warning beyond the confirmation cycle result.

What Peakers Actually Do

In jurisdictions with mature gas-electric markets, peaker plants use several strategies to bridge the nomination gap. Most of these strategies are unavailable or severely limited in Nova Scotia:

Strategy	How It Works	Available on M&NP?
No-notice service	Premium firm service allowing gas draws without advance nomination. Pipeline maintains storage to buffer variable demand. Created by FERC Order 636 (1992) for LDCs.	No. Requires storage infrastructure. M&NP has no underground storage.
Park-and-loan	Short-term storage: "park" gas on the pipeline during low demand, draw it during dispatch. Or "loan" gas now and repay later.	No. Requires storage or substantial linepack. M&NP has no storage and limited linepack since offshore production ended.
Linepack buffer	The pipeline itself holds compressed gas. An unexpected draw is absorbed by pipeline pressure for some hours.	Limited. M&NP operates at low throughput relative to design. Linepack is modest; unauthorized draws would affect system pressure quickly.
Speculative nomination	Nominate gas day-ahead based on weather/price forecasts, even without certainty of dispatch.	Yes, but requires firm transportation (reservation charges are sunk). If dispatch doesn't materialize, the shipper must sell excess gas or accept imbalance risk.
Dual-fuel (oil backup)	Bypass the gas system entirely by burning stored diesel or fuel oil. 41% of New England gas capacity has this capability.	Required. The Tolling Agreement mandates the generator "maintain the dual Fuel capability of the Facility." Light fuel oil (diesel) is stored on-site, with up to 25% of operating hours on LFO permitted. Fuel is defined as "Natural Gas and Light Fuel Oil."

Procurement Economics

The economic tension facing a peaker plant is stark: firm gas transportation is expensive but essential, while interruptible service is cheap but unreliable precisely when it matters most.

The Cost of Firm Supply

A peaker plant runs at 2–20% capacity factor (175–1,750 hours per year). Firm pipeline transportation requires paying a reservation charge every month, all year, regardless of whether the plant runs. For a 200 MW simple-cycle plant consuming ~2,000 MMBtu/hour, this translates to roughly $365,000–$730,000/year in reservation charges alone - before any gas commodity is purchased.

For a Nova Scotia plant, the cost is worse. Gas must travel from the Appalachian Basin through multiple pipeline segments to reach Pictou County. Each segment carries its own transportation charges. The delivered cost at a Nova Scotia receipt point includes the full Algonquin basis premium (the New England price spike) plus additional M&NP transportation charges on top.

The Risk of Interruptible Supply

Without firm transportation, a peaker plant faces curtailment during winter peaks. During cold snaps in the Northeast, interruptible gas transportation becomes completely unavailable for days at a time. The pipeline operator confirms firm nominations first and allocates any remaining capacity to interruptible shippers. If zero capacity remains, interruptible shippers get zero gas.

Plants that take gas without nominating - or that exceed their nominations - face escalating penalties: typically 150–200% of the daily index price under normal conditions, rising to 200–300%+ during Operational Flow Orders (OFOs). During Winter Storm Uri (2021), Panhandle Eastern assessed $75 million in OFO penalties. FERC upheld every dollar, rejecting all waiver requests.

Dual-Fuel: The Only Real Backstop - And the Likely Default

In every major winter crisis since 2014, the plants that kept running were the ones with dual-fuel capability - the ability to switch from gas to on-site fuel oil. During Winter Storm Fern (January 2026), petroleum generation reached 44% of total generation in NYISO and 35% in ISO-NE. Oil became the primary fuel in the ISO-NE generation stack for multiple days.

The Marshdale and Salt Springs plants are required to have dual-fuel capability. The Functional Specifications (Exhibit T) state explicitly: "Each unit shall be capable of starting on either natural gas or light fuel oil and performing online fuel transfer between natural gas and light fuel oil seamlessly." Each site will store approximately 9 million litres of diesel - enough for 5 days at full load (75,000 litres per hour).

This creates a paradox at the heart of the project. These are marketed as "natural gas" plants, but the operational reality of fast-acting dispatch means diesel is the likely startup fuel for most dispatches. The community is being asked to host 9 million litres of diesel storage at each site - next to residential areas - for plants that will burn that diesel as their primary fuel during exactly the emergency conditions they were built for.

Canaport LNG Is Not a Backstop

Canaport LNG (Saint John, NB) is sometimes cited as a potential backup gas supply for the Maritimes. It is Canada's only large-scale LNG import terminal, with a design capacity of 1 Bcf/d send-out and 7.5 million tonnes per year. But five facts make it irrelevant as a supply backstop for Nova Scotia peaker plants.

1. It is 100% owned by a Spanish company with no Canadian supply obligation

Repsol SA (Spain) acquired full ownership in November 2021 when it purchased Irving Oil's 25% stake. Repsol is a global LNG portfolio trader that describes its strategy as "opportunistic" - cargoes go where margins are highest. There is no contractual obligation to supply Canadian customers. No Nova Scotia entity (not NSPI, not Eastward Energy, not IESO Nova Scotia) has a known supply contract with the terminal.

2. The terminal operates at a fraction of capacity

Imports have collapsed since the early 2010s as U.S. shale gas made LNG uneconomic. The terminal was built to unload two ships a week. CBC reported one winter where only three ships arrived the entire season. Boil-off losses from sitting idle are now significant enough that Repsol contracted Galileo Technologies (June 2024) for a reliquefaction system to recover ~10 MMcf/day of evaporating LNG.

3. Emergency cargo lead times make it useless for winter crises

Even from the closest LNG source (Trinidad, ~2,400 nautical miles), sailing time alone is 6–7 days. Before that: identify available supply, charter or divert a vessel, secure a loading window (24–48 hours). Under long-term supply agreements, cargoes are planned via Annual Delivery Programs 12–18 months ahead. Spot cargoes take 3–6 weeks from decision to delivery for Atlantic basin routes. A winter cold snap in Nova Scotia lasts days, not weeks - any emergency cargo would arrive after the crisis is over.

4. Winter LNG competition makes diversion to Canada irrational

When Nova Scotia needs gas most, every LNG buyer in the Northern Hemisphere is competing for the same spot cargoes. European TTF prices hit ~$100/MMBtu during the 2022 energy crisis. A cargo that Repsol can sell in Europe at those prices will not be sent to Saint John at North American prices. Repsol is a profit-maximizing Spanish multinational, not a Canadian public utility with a service obligation.

5. Repsol's instinct during a crisis is to export, not import

When the 2022 European energy crisis hit, Repsol proposed converting Canaport to an LNG export terminal to ship gas to Europe. The plan was abandoned in March 2023 only because piping western Canadian gas to Saint John was too expensive. Their first response to an energy crisis was to extract gas from the region, not supply it.

Nova Scotia's own gas distributor, Eastward Energy (formerly Heritage Gas), formally objected to the CER about Repsol's export license, citing supply security concerns for Atlantic Canada. The CER overruled them and granted Repsol a six-year export license extension to 2032.

What Happens When the Pipeline Is Full?

When upstream production collapses or pipeline capacity is fully subscribed, the consequences cascade in a specific order - and peaker plants are among the most vulnerable.

The curtailment hierarchy

When a pipeline cannot meet all nominations, shippers are curtailed in priority order:

1. Unauthorized overruns - curtailed first, with penalties of 150–500% of the daily index price
2. Interruptible shippers - curtailed next; they receive zero gas if no capacity remains after firm nominations
3. Firm shippers - curtailed last, only in genuine emergencies (force majeure)

But even firm contracts failed to protect plants during Winter Storm Elliott: approximately 10 GW of gas-fired generation with firm transportation contracts lost supply because the problem was not pipeline capacity but upstream production collapse. Marcellus shale production dropped 23% and Utica shale dropped 54%. Firm transportation guarantees pipeline space - it does not guarantee that gas exists to fill it.

No one regulates gas reliability

The electric grid has mandatory reliability standards enforced by NERC. Gas pipelines and gas production have no equivalent. FERC regulates pipeline rates and construction; states regulate gas production. No entity has comprehensive authority to mandate that gas infrastructure perform reliably during winter peaks. The December 2025 National Petroleum Council report confirmed: "The governance of the gas-electric interface is fragmented across multiple regulatory and operational entities" and "neither [FERC nor NERC] has comprehensive authority to enforce alignment between the two sectors."

Nova Scotia's Unique Vulnerability

A peaker plant in Nova Scotia would face a combination of disadvantages that no other jurisdiction in North America shares simultaneously:

1. End of the pipeline - gas must traverse the entire U.S. Northeast pipeline network (already constrained in winter) before reaching Nova Scotia via M&NP
2. No local production - offshore production ended permanently in 2018
3. No gas storage - no underground storage in NS or NB; no buffer against supply disruptions
4. No no-notice service - the M&NP system cannot offer this because it has no storage infrastructure
5. No park-and-loan service - same reason: no storage
6. Limited linepack - M&NP at low throughput relative to design capacity
7. Dual-fuel is required but limited - the Tolling Agreement caps LFO at 25% of operating hours, and on-site diesel storage provides days of backup, not weeks
8. Canaport LNG declining - 88% import decline since 2011, foreign-owned, no supply obligation to NS

In the U.S. Northeast, 41% of gas-fired capacity can switch to oil when gas is unavailable. New York assumes 6,400 MW of gas generation will be unavailable during winter peaks and plans accordingly. ISO-NE spent over $800 million keeping Mystic Station running specifically because it burned LNG from an adjacent terminal rather than pipeline gas. These jurisdictions have learned, at enormous cost, that gas supply cannot be taken for granted during winter - and they have invested in backstops.

The proposed Nova Scotia plants would sit at the extreme end of the same constrained supply chain, with none of the backstops that other jurisdictions have developed, in a province that has never operated gas peaker plants before.

The Bigger Picture: Gas Plants as the Anchor for Domestic Fracking

Every supply constraint described on this page - no local production, no storage, end-of-pipeline vulnerability, winter price spikes, dependence on U.S. imports - points to an obvious question: where will the gas come from? The Premier has already answered it.

In February 2025, the Houston government introduced legislation to lift Nova Scotia's decade-long moratorium on hydraulic fracturing (fracking) for onshore natural gas - a ban that had been in place since 2014 following years of community opposition and an independent scientific review. The legislation passed in March 2025 over opposition from the Assembly of Mi'kmaw Chiefs, who threatened legal action, and despite significant public pushback.

The Premier has been explicit about the connection between gas plants and domestic gas supply:

"Right now, all the natural gas we use in Nova Scotia is extracted elsewhere and sold to us from the United States. This is despite us having enough natural gas to power Nova Scotia for thousands of years."
- Premier Tim Houston, Canadian Gas Association interview

"Nova Scotia has natural gas right here at home. It's time we use it. If we develop our resources responsibly, we can increase supply, rely less on imports, and help lower energy costs for families and businesses. Shipping energy in from far away drives up the price."
- Premier Tim Houston, social media post

In December 2025 - the same month the Marshdale and Salt Springs EARDs were filed - the province announced a $30 million partnership with Dalhousie University to kickstart onshore natural gas exploration. More than $24 million of that is earmarked for exploration incentives to private developers, with a call for proposals in Q1 2026. The government cites "7 trillion cubic feet" of recoverable onshore reserves, equivalent to "three Sable gas projects" or "80 years of supply."

The timeline is not a coincidence

Date	Action
Feb 2025	Legislation introduced to lift fracking ban
Mar 2025	Fracking ban lifted, over Mi'kmaw and public opposition
Oct 2025	IESO-NS issues Request for Expressions of Interest for 300 MW gas plant
Dec 2025	Marshdale and Salt Springs EARDs filed (9 days before CER deadline)
Dec 2025	$30M onshore gas exploration program announced with Dalhousie
Mar 2026	Draft RFP released for two 300 MW gas plants
Q1 2026	Call for gas exploration proposals issued

Two 300 MW gas plants consuming up to 120 MMcf/day - 155% of current provincial gas demand - create a permanent, government-guaranteed market for natural gas in Nova Scotia. That demand does not exist today. Once it does, the economic case for domestic gas production becomes self-evident, and the Premier has already made the political case.

What about Alton Gas?

The Alton Natural Gas Storage project - a plan to create underground gas storage in salt caverns near the Shubenacadie River - was decommissioned by AltaGas in 2021 after years of determined opposition led by Mi'kmaw water protectors and the Grassroots Grandmothers. The project was halted on both economic and environmental grounds.

But the economic calculus that killed Alton was specific: offshore production had ended, gas demand was declining, and there was no anchor customer to justify the investment. Two 300 MW gas plants would fundamentally change that equation. If domestic gas production restarts via fracking, seasonal gas storage becomes an economic necessity - you cannot produce gas year-round for a customer that only runs part of the year without somewhere to store it. The same policy that creates the gas plants creates the conditions that revive the case for gas storage.

No one in government has proposed reviving Alton Gas. But the logic of the supply chain leads there. Build the plants, lift the fracking ban, start domestic production, and the storage question answers itself.

Unanswered Questions

• Will the plants hold firm or interruptible gas transportation on M&NP?
• Who bears the cost of firm reservation charges - the generator or ratepayers (via the tolling agreement)?
• What is the fuel procurement plan during winter peaks when the upstream New England pipeline network is constrained?
• How many days of on-site light fuel oil storage will each plant maintain? Is it sufficient for a multi-day pipeline disruption?
• Has any entity secured or attempted to secure a supply contract with Canaport LNG?
• What gas price assumptions underpin the project economics? Do they account for Algonquin basis blowouts of $80–$122/MMBtu?
• How will the plants nominate gas for real-time dispatch given the day-ahead nomination cycle and the absence of no-notice service on M&NP?
• Is the government's $30M onshore gas exploration program intended to supply these plants? If so, what is the timeline for domestic production, and what happens in the years before it materializes?
• Has the government assessed whether 120 MMcf/day of new gas demand would create economic pressure to revive gas storage projects like Alton Gas?
• Was the decision to lift the fracking ban made in coordination with the decision to build gas plants? Were these evaluated as a combined policy, or separately?