Why natural gas hedging in Mexico matters
Natural gas hedging in Mexico has become a survival discipline for industrial buyers. Natural gas powers a major share of Mexico’s industrial output. Manufacturers in glass, steel, ceramics, chemicals and food rely on it both as energy source and feedstock. Yet most of that gas does not come from domestic production. Roughly 75% of the natural gas consumed in Mexico is imported from the United States, mainly through pipelines crossing the northern border from Texas. That dependence makes Mexican industry directly exposed to American gas market dynamics.
Three U.S. price indexes determine what Mexican buyers pay. Henry Hub is the national benchmark in Louisiana. Houston Ship Channel or HSC is the Gulf Coast hub. Waha is the Permian Basin hub in West Texas. Mexico also uses EPSM as a domestic reference for some regulated tariffs. The price at each of these indexes moves daily, sometimes violently.
The February 2021 winter storm in Texas showed how violent that movement can become. During the storm, HSC reached 400 dollars per MMBtu and Waha hit 206 dollars per MMBtu, against normal levels around 3 dollars in the days before. For comparison, normal prices that month would have been below 5 dollars. Companies without hedging saw multi-million dollar cost overruns in a matter of days. The CFE itself ended up in a 300 million dollar settlement over a contract structure that did not protect against this kind of event.
Hedging natural gas is not a speculative bet on prices. It is a discipline to convert a volatile cost into a predictable one, so industrial budgets and operating margins survive even when the market turns extreme.
How the HSC price is formed
The Houston Ship Channel index, known as HSC, reflects the price of natural gas delivered around Houston, Texas. It is a regional spot price, calculated daily by agencies like Natural Gas Intelligence and Platts based on actual physical transactions among buyers and sellers in the area.
HSC matters more than other regional indexes for Mexico because of geography. The Gulf Coast pipelines that supply gas to central and southeastern Mexico originate near the HSC delivery area. When a Mexican buyer signs a supply contract for gas coming through Texas to Mexico pipelines like Sur de Texas Tuxpan, that contract is usually indexed to HSC plus a basis differential.
Beyond the physical spot market, HSC has a parallel financial market through basis futures and swaps listed on the Intercontinental Exchange (ICE) and traded over the counter. These instruments let buyers lock prices for future months without taking physical delivery. The standard hedge structure for HSC exposure combines a NYMEX Henry Hub futures contract for the base price with an HSC basis swap covering the differential. Liquidity in HSC instruments is lower than in Henry Hub futures, but it is sufficient to build hedging positions for industrial volumes one to twelve months out.
What moves the HSC daily? Several elements. Weather patterns in the U.S. Southeast and Mexico. LNG export demand from terminals like Freeport and Sabine Pass. Pipeline maintenance schedules. Hurricane risk during the Atlantic season. And overall Gulf Coast industrial demand from petrochemical plants and refineries. To understand HSC behavior in depth, the standalone analysis of the Houston Ship Channel index offers further detail for natural gas hedging in Mexico.
HSC vs Henry Hub differences
Henry Hub is the national U.S. benchmark for natural gas. It sits at a pipeline intersection in Erath, Louisiana, and serves as the underlying for NYMEX futures contracts that the entire industry uses as reference. Houston Ship Channel is regional. It only reflects conditions in the Gulf Coast around Houston. The two prices behave similarly most of the time, but they are not identical.
The price gap between the two is called basis. Under normal conditions, HSC trades at a small premium or discount to Henry Hub depending on the season. The typical range is between minus 20 cents and plus 30 cents per MMBtu. When demand surges in the Gulf Coast or when LNG terminals run at full capacity, the HSC basis can widen to plus 1 dollar per MMBtu or more. During major weather events or pipeline outages, it can move much further.
For a Mexican company, this distinction is practical. If a supply contract is indexed to HSC plus a fixed differential, the buyer is exposed to HSC movement, not to Henry Hub. Hedging the wrong index, even by a small amount, creates basis risk that defeats the purpose of the cover. The right hedge matches the index in the supply contract.
This is also why some Mexican buyers use combined strategies. A Henry Hub hedge for the bulk of the exposure because it has more liquidity, plus a separate basis swap to cover the HSC to Henry Hub differential. The combination delivers protection at lower cost than a pure HSC hedge.
Spreads Waha HSC and Henry Hub as market signals
Three indexes mean three sources of information. Each spread between them carries a different message about what is happening in the U.S. gas market. Reading these spreads correctly can tell a Mexican buyer when to hedge, what to hedge, and even what is about to change in the market.
The Waha vs Henry Hub spread reflects pipeline capacity out of the Permian Basin. When Permian gas production grows faster than take away pipeline capacity, gas gets stuck in West Texas and Waha trades at deep discount to Henry Hub. The numbers tell the story. In 2021, Waha averaged 4.23 dollars and Henry Hub averaged 3.86, so Waha was at a slight premium because production was constrained. By 2024, Waha had collapsed to an annual average of 0.08 dollars while Henry Hub stood at 2.18, a gap of more than two dollars driven by oversupply and pipeline bottlenecks. When the spread widens this much, it is a clear signal of too much gas, not enough pipeline.
The HSC vs Henry Hub spread reads differently. It reflects Gulf Coast demand pressure, mainly from LNG export terminals like Freeport, Sabine Pass, and Corpus Christi. When LNG terminals run at full capacity and exports surge, HSC starts trading at premium to Henry Hub. The typical range is narrow, between minus 20 cents and plus 30 cents, but it can widen to plus 1 dollar or more during periods of intense LNG demand or hot Gulf Coast summers. A persistent HSC premium is a signal that domestic gas is competing harder against export demand.
Several events move these spreads in predictable ways. Hurricane season between June and November disrupts Gulf Coast production and pipeline flows. Pipeline maintenance schedules announced by interstate operators temporarily reroute volumes. LNG plant commissioning or ramp up adds new layers of demand. Cold snaps in the U.S. Midwest pull gas away from the Gulf Coast.
For Mexican buyers, monitoring these spreads is a natural gas hedging discipline, not an academic exercise. The InHedge Intelligence monthly HSC report tracks these dynamics with forward curves and supply demand balances. The next section covers the instruments that translate this market reading into actual hedges.
Natural gas hedging instruments
Natural gas hedging in Mexico does not mean a single product. It means a small toolkit, and each tool fits a different need. For Mexican industrial buyers, the most useful are six structures.
A fixed swap is the simplest instrument. The buyer pays a fixed price for a defined volume and period, and receives the floating market price. If the market rises, the swap pays the buyer the difference. If the market falls, the buyer pays. The result is a known price for that volume, no upside, no downside. Swaps work well when the goal is absolute budget certainty.
A bought call gives the buyer the right to buy at a strike price without the obligation. The buyer pays an upfront premium. If the market rises above the strike, the call pays. If the market stays below, the call expires worthless and the buyer keeps the lower market price. Calls are the standard tool when the goal is a ceiling with full participation in price decreases.
A sold put is the inverse. The buyer accepts the obligation to receive a higher cost if the market falls below a floor, in exchange for a premium received. Used alone it adds downside risk, so it is rarely sold by itself. Its main use is to finance the cost of a bought call.
A collar combines a bought call and a sold put. The call sets a ceiling, the put sets a floor. The premium paid on the call is partly or fully offset by the premium received on the put. The result is a price band where the buyer pays no more than the ceiling and no less than the floor. Collars are popular because they can be structured at zero net cost.
A three way collar adds a sold call at a higher strike to further reduce the cost. The buyer protects against moderate price increases but gives up protection against extreme spikes. This structure suits buyers who want cheaper coverage and accept that black swan events remain unhedged.
A swaption is an option to enter a swap at a future date. It gives flexibility on timing when the buyer is not yet sure when to lock the price. Useful when budget cycles or board approvals are not synchronized with the optimal market moment.
The right instrument depends on three things. How much budget certainty the buyer needs. How much premium the buyer is willing to pay upfront. And what view, if any, the buyer holds about the direction of the market.
When to hedge and when not to
The decision about natural gas hedging is not binary. It is a calibration between three forces. Price level relative to history, the shape of the forward curve, and the buyer’s internal constraints.
Price level matters because hedging at the bottom of a cycle locks in a good deal, while hedging at the top of a spike locks in pain. Look at where current prices sit relative to the 5-year average and the 25th to 75th percentile range. If HSC is trading at the 25th percentile of the last 5 years, hedging is cheap insurance. If it is at the 90th percentile, the buyer is paying for fear premium.
The shape of the forward curve gives another signal. When the curve is in contango (future prices higher than spot), the market expects prices to rise and the cost of locking is built into the swap. When the curve is in backwardation (future prices lower than spot), the market expects prices to fall and the swap effectively locks in a discount. Backwardation is often a better moment to hedge than contango.
Internal constraints close the picture. Some buyers operate under annual budgets approved by boards in November or December. They need to hedge before budgets are signed, regardless of market signal. Others operate under quarterly reviews and can be more opportunistic. Some have hedge accounting documentation in place under IFRS 9 and can use derivatives freely; others without documentation face P&L volatility that limits how much they can hedge.
Different consumer profiles weigh these factors differently. A combined cycle power generator with a 20-year offtake contract will hedge differently than a glass manufacturer optimizing quarterly margin. Importers focused on cross border logistics weigh basis risk more heavily than industrial consumers focused on absolute price.
When not to hedge? When the buyer cannot define exposure, when the budget cannot absorb the cost of premiums, or when board approvals are not in place. Hedging without these foundations creates a different kind of risk.
Lessons from the CFE case
Mexican industry has a textbook example of what happens without hedging discipline. During the February 2021 Texas winter storm, CFE International held a natural gas supply contract with Goldman Sachs in which the two parties were exposed to different price indexes. Goldman’s obligations were tied to a monthly Waha index. CFE was tied to the daily Waha index. When the storm pushed daily Waha to 206 dollars while the monthly index stayed near 5 dollars, the gap between the two created an instant liability for CFE.
Four years of litigation followed. The case went to the London Court of International Arbitration. Goldman initially claimed 400 million dollars. CFE eventually settled for 300 million dollars in January 2025. The full story is documented in the CFE vs Goldman Sachs case analysis on this site.
The lesson is not that CFE was incompetent. The contract was structured before the storm became conceivable, and the daily vs monthly index mismatch was not flagged as a critical risk at the time. The lesson is structural. When buyer and counterparty are exposed to different indexes, the contract carries an embedded basis risk that only shows up in extreme events.
For industrial buyers in Mexico, the takeaway is concrete. Always match the hedge index to the supply contract index. If the supply contract references HSC, hedge HSC. If it references Waha, hedge Waha. Mixing indexes to gain liquidity is acceptable only if a separate basis swap covers the differential. Cutting corners on this matching is what generated the CFE liability, and it is the same trap most natural gas hedging programs in Mexico fall into when they substitute the wrong index for convenience.
Common mistakes that cost money
Most natural gas hedging failures in Mexico do not come from picking the wrong instrument. They come from procedural errors that quietly compound until an extreme event reveals them. Six mistakes appear over and over in industrial hedge programs.
Hedging the wrong index. The CFE case shows how this looks at scale, but it happens at smaller scales too. A glass plant in Monterrey signs a supply contract indexed to HSC plus a fixed differential, then hedges with Henry Hub futures because they have better liquidity. The hedge will move with Henry Hub, the cost will move with HSC, and the gap between them is the loss the hedge was supposed to prevent.
Not updating the hedge when volume changes. A plant ramps production, an offtake contract expires, a new line opens. If the hedge does not move with the physical exposure, the company is either overhedged (paying for protection it does not need) or underhedged (uncovered on the new volume).
Ignoring IFRS 9 documentation. Without proper hedge accounting documentation, the mark to market of the derivative hits P&L while the underlying exposure does not. The result is accounting volatility that scares boards and auditors, even when the economic exposure is well covered. Many treasuries scale back hedging because of this rather than fixing the documentation.
Confusing hedging with speculation. Locking a price for a known volume is hedging. Locking a price for a directional bet without an underlying volume is speculation. Some treasuries cross this line without realizing it, often under pressure to do something about prices.
Bad timing under pressure. When a CFO panics after a price spike and demands immediate hedging, the company often hedges at the worst possible moment, locking in the spike rather than protecting against the next one.
No periodic review. A hedge policy written three years ago may no longer match current exposure, current supply contracts, or current market regime. Without regular review, the hedge program drifts away from the business it is supposed to protect.
Monthly HSC report from InHedge
Hedging discipline requires data that is timely, comparable across months, and translated into operational decisions. Generic news coverage and government statistics do not solve this. Treasuries need a structured product that arrives every month, covers the same indicators, and connects what happened to what to do about it.
The InHedge Intelligence monthly HSC report is built for this purpose. Each month it covers forward curves out 12 to 24 months, supply and demand balance for the U.S. natural gas market, basis dynamics between HSC, Henry Hub and Waha, correlations against macro indicators, and a narrative section connecting the data to recent news (pipeline maintenance schedules, LNG terminal activity, weather forecasts, regulatory updates).
The audience is specific. It is designed for treasury directors, CFOs, energy procurement managers, and risk officers at industrial companies and power generators in Mexico and LATAM. It is not designed for retail traders or for general market commentary.
The report is part of InHedge Intelligence, the firm’s subscription platform. Members also receive access to interactive dashboards, daily updates on key indicators, and direct contact with the research team for ad hoc questions. Pricing and access are explained on the membership page.
For a CFO building a hedge program, the report removes the time cost of monitoring three indexes, multiple pipeline operators, and a steady stream of news. The CFO sees the conclusions, the supporting data, and the recommended posture for the month, in one document.
How InHedge executes natural gas hedging in Mexico
Building a natural gas hedging program is not a single transaction. It is a continuous practice with four moments, and InHedge is structured around them.
The first moment is diagnosis. The team starts by mapping a company’s real exposure. How much gas is consumed monthly, where is it sourced, which index does the supply contract reference, what is the budget tolerance, and what is the hedge accounting setup. The output is a hedging policy document that the board can approve and that auditors can review.
The second moment is execution. InHedge operates as an introducing broker through Cargill, one of the largest commodity counterparties in the world. This means the actual hedges trade through Cargill’s regulated markets and OTC desks, but the relationship, advisory, and structuring stay with InHedge. The client gets institutional access without operating a desk in house.
The third moment is monitoring. Hedges do not run by themselves. Markets move, volumes change, supply contracts rotate. InHedge issues periodic reports tracking each position, mark to market evolution, and required adjustments. The client never wonders where the hedge stands.
The fourth moment is training. Most industrial treasuries do not have a derivatives specialist on staff, and they do not need one if their advisor is doing the work. But the CFO and procurement team should understand what is being done in their name. InHedge runs structured sessions for client teams covering instruments, market behavior, accounting treatment, and red flags to watch for.
When extreme events arrive, a hurricane, a pipeline failure, a winter storm, the relationship is what holds. Clients reach the team directly, not a call center. The next storm will come. The question is whether the program is built to weather it.
For a first conversation about your exposure, the contact page is the starting point.