For most Texas commercial operations, natural gas is the second-largest controllable utility line on the P&L after electricity — and the one with the wildest swings. The U.S. benchmark Henry Hub spot price closed at $9.03 per MMBtu on January 28, 2026, after Winter Storm Fern triggered the largest weekly storage withdrawal in the history of the EIA Weekly Natural Gas Storage Report. Twelve months earlier, the same benchmark settled below $3. That is the operating reality of commercial gas in Texas: the rate you pay this winter is not the rate your accountant budgeted for last summer, and the gap is rarely small.

This guide is written for plant managers, facilities directors, and CFOs running mid-size and large Texas commercial operations — restaurants, hotels, event venues, manufacturers, multi-family properties, healthcare campuses, places of worship, warehouses, and convenience-store chains — that consume enough gas to qualify as transport-rate commercial customers on their local distribution company tariff. If your facility uses gas for space heating, water heating, cooking, process heat, drying, sterilization, laundry, or backup generation, and your annual usage is 5,000 Mcf or more, this is your guide to what actually drives the rate on the bill and what you can do about it.

We are going to walk through every component of the rate — the commodity, the basis, the LDC delivery charge, the regulatory pass-throughs, and the line items most buyers never decode — show how each one moved over the last cycle, and lay out the contract structures and procurement tactics that Texas commercial buyers use to control the result. The article runs long by design. Natural gas pricing is not a one-paragraph topic and the operators who consistently buy well are the ones who understand the full stack.

The Anatomy of a Commercial Natural Gas Rate in Texas

Open a Texas commercial gas bill and the all-in cost per MMBtu (or per Mcf — Texas LDCs bill in Mcf, where 1 Mcf ≈ 1.038 MMBtu) is the sum of five distinct components, each with its own pricing logic, its own counterparty, and its own optimization opportunity. Most buyers focus on the headline rate and ignore the rest, which is exactly why most buyers leave money on the table.

1. The Commodity (Henry Hub or NYMEX)

Roughly 40 to 60% of the all-in cost is the commodity itself — the molecule of gas. In commercial procurement, the commodity is priced off the NYMEX Henry Hub futures contract, the de facto benchmark for North American natural gas. Henry Hub is a physical interconnect in Erath, Louisiana, where multiple interstate pipelines meet, and the monthly NYMEX settlement is published the business day before each delivery month begins. Virtually every commercial gas contract in Texas references this number, either as the fixed strip price (for fixed-rate plans) or as the floating monthly index (for NYMEX-indexed plans).

The Henry Hub commodity price has moved between $1.60/MMBtu (mid-pandemic 2020) and $23.86/MMBtu (Winter Storm Uri, February 17, 2021) over the last six years. The five-year average has hovered around $3.50 to $4.50/MMBtu, with January 2026 closing materially above the 2025 winter strip after Storm Fern compressed storage by 360 Bcf in a single week — an 89% overage versus the five-year average for that week. The takeaway: commodity volatility is structural, not anomalous, and it is the single largest source of variance on a commercial gas bill.

2. Basis (Houston Ship Channel, Katy, or Waha)

Henry Hub sits in Louisiana, not Texas. The molecule that physically arrives at your meter is delivered through a different regional hub — Houston Ship Channel (HSC) for East Texas, Katy Hub for the Houston metro area, or Waha Hub for West Texas and the Permian basin. The difference between the Henry Hub price and the regional hub price is called basis, and it is not a fee — it is a real market-traded differential reflecting pipeline transportation costs, regional supply-demand balance, and capacity constraints.

For most of the recent cycle, Texas hubs have traded at a discount to Henry Hub. The Houston Ship Channel averaged $0.27/MMBtu below Henry Hub through the first half of 2023; Waha averaged $0.85/MMBtu below. Discount basis is good news for Texas commercial buyers — you are theoretically buying gas cheaper than the national benchmark. But basis is volatile in its own right. When pipeline maintenance restricted flows out of the Permian in late 2022, Waha basis blew out to negative $3.02/MMBtu — Permian producers were effectively giving gas away because takeaway capacity had vanished. When LNG export demand at Freeport ramped, HSC basis tightened toward parity with Henry Hub because export-bound molecules competed with domestic Texas demand for the same pipeline space.

Your contract should disclose basis as a transparent line item — usually expressed as "Henry Hub plus $0.45 basis" or "HSC index plus $0.12 marketer fee" — rather than burying it inside an all-in headline rate. A supplier who refuses to break out basis is either hiding margin or absorbing basis risk they will eventually pass through to you with a force-majeure or regulatory-pass-through clause when the market moves against them.

3. LDC Delivery (Atmos, CenterPoint, Texas Gas Service, CPS)

Texas does not have a single deregulated gas market the way it has a deregulated electric market under ERCOT. Gas delivery is owned and operated by regulated local distribution companies — Atmos Energy across the Dallas-Fort Worth metro, North Texas, the Texas Panhandle, and parts of South Texas; CenterPoint Energy in Houston, Beaumont, and East Texas; Texas Gas Service in Austin, Rio Grande Valley, El Paso, and Central Texas; and CPS Energy as the municipal utility in San Antonio. The LDC owns the pipelines that physically run to your meter, and the LDC charges you a delivery rate that is set by the Railroad Commission of Texas under regulated tariffs.

For transport-rate commercial customers — typically 5,000+ Mcf per year — the LDC tariff splits into a fixed customer charge ($50 to $400+ per month depending on rate class and territory) and a per-Mcf delivery charge that usually runs $0.50 to $2.50/Mcf depending on rate class, territory, and time of year. The delivery charge is regulated. It is the same whether you buy your commodity from the LDC's default supplier, from a third-party marketer through a broker, or from any other licensed counterparty. What you can negotiate is the commodity portion; what you cannot negotiate is the LDC's pipe-and-meter charge.

For larger industrial customers — generally above 30,000 Mcf annually or with specific peak-demand thresholds — many LDCs offer alternate rate classes (sometimes called Transport Service, Choice Gas, or similar) that unbundle delivery from supply. The customer arranges supply separately through a marketer or broker, the LDC delivers the molecules, and the rate split is fully transparent. This is the rate class that most commercial buyers should be on if they are serious about shopping the market. Many businesses sit on the default bundled tariff for years without realizing transport service would cut their all-in cost by 10 to 20% just from the structural change in how they buy.

4. Pipeline and Storage

Between the upstream commodity price (Henry Hub or the regional hub) and the LDC city gate, there is interstate pipeline transportation and seasonal storage. For most commercial customers, these costs are bundled into either the basis differential (if the marketer is delivering at the city gate) or the LDC's delivery charge (if the LDC is the responsible party). For very large industrial customers with their own pipeline capacity contracts, these are negotiated separately as firm transport (FT) or interruptible transport (IT) contracts directly with the interstate pipeline operator.

Storage matters more than most commercial buyers realize. Texas LDCs and marketers withdraw from underground storage during winter peak demand to avoid buying expensive spot gas. The cost of injecting gas in summer (cheap) and withdrawing in winter (expensive) is built into commercial rate structures. The EIA's weekly storage report — published every Thursday at 10:30 ET — is the single most important data point traders watch, because it determines short-term basis and forward-strip pricing. A surprise withdrawal of 200+ Bcf in a winter week can move the front-month NYMEX by $0.50 to $1.50/MMBtu in a single trading session.

5. Taxes, Riders, and Pass-Throughs

Texas state sales tax does not apply to natural gas used in manufacturing or qualifying production processes, but it does apply to commercial gas used for space heating, water heating, and other non-production applications. Many municipalities also assess local gross-receipts taxes or franchise fees on commercial gas service, which show up as separate line items on the bill. Additionally, the LDC tariff includes mandated riders for energy efficiency programs, weatherization recovery, GRIP (Gas Reliability Infrastructure Program) surcharges in Atmos territory, and securitization charges related to Winter Storm Uri — the Texas Public Finance Authority issued bonds to spread the Uri commodity cost spike across 16 years of customer billing, and that recovery factor is on every commercial gas bill in the affected territories.

None of these are negotiable. They are pass-through items mandated by state law or the Railroad Commission. But they should be itemized on your bill, and they should match the rate filings posted by your LDC. A surprising number of commercial accounts get billed at incorrect rate-class designations or with stale rider rates, and a periodic audit catches these errors.

Units, Conversions, and Why Your Bill Confuses You

Texas commercial gas is billed in Mcf — one thousand cubic feet — while the wholesale market trades in MMBtu (one million British thermal units) and the kitchen-table conversation uses therms. The three units are related but not identical, and reading a commercial gas bill requires keeping the conversions straight.

We recommend running your annual usage in both units before shopping. A 12,000 Mcf annual account is roughly 12,456 MMBtu. A 1-cent/MMBtu difference in the commodity quote is $125 per year on that account. A 10-cent/MMBtu difference is $1,250 per year. The commercial gas market is won and lost on small numbers multiplied by big volumes — which is why understanding the unit conversion is not academic.

The Five Forces Driving Commercial Natural Gas Rates Right Now

Five structural forces determine where commercial gas rates clear in any given month, and understanding them is what separates buyers who time the market well from buyers who get whipsawed at every renewal.

1. Weather (the dominant short-term driver)

Heating-degree days in winter and cooling-degree days in summer (because gas-fired power plants are the marginal generator on hot afternoons) drive gas demand more than any other variable. The January 2026 spike to $9.03 at Henry Hub happened because Winter Storm Fern dropped overnight lows below 10°F across the Texas-Oklahoma corridor, driving combined residential, commercial, and power-generation gas demand to record levels while wellhead freeze-offs cut production at the same time. The same structural pattern played out during Winter Storm Uri in February 2021, when Panhandle Eastern's Texas/Oklahoma delivery point printed $224.56/MMBtu on a single day — versus $2.55 two weeks earlier. Weather risk is the largest single risk in a commercial gas contract, and it is the risk a fixed-price contract is designed to transfer to the supplier.

2. LNG Exports

The U.S. became a net LNG exporter in 2017 and is now the world's largest LNG producer. Texas hosts Freeport LNG, Corpus Christi LNG, and is bringing additional capacity online through 2027-2028. Every Bcf/day of new export capacity tightens the domestic market and lifts U.S. gas prices toward import-parity levels in Europe and Asia. When Freeport LNG returned to service in February 2023 after its 2022 outage, Houston Ship Channel basis narrowed dramatically — the export terminal pulled molecules eastward and out of the domestic market. For Texas commercial buyers, LNG matters because Texas hubs (especially HSC) are directly upstream of export demand. The structural floor under HSC prices is rising every year that LNG capacity grows.

3. Permian Associated Gas

Roughly 40% of Texas natural gas production is associated gas — gas produced as a byproduct of oil drilling in the Permian Basin. Permian producers care about oil economics, not gas economics, and they will produce gas at almost any price (sometimes flaring it when takeaway capacity is constrained). This is structurally bearish for Waha basis and contributes to the long-running Henry-Hub-to-Waha price gap. When new pipelines come online (Matterhorn Express in late 2024, Blackcomb in 2026), Waha tightens and West Texas gas flows east and south. When pipelines are full or under maintenance, Waha collapses — sometimes to negative prices, where producers pay to have gas taken away. For commercial buyers in West Texas, in San Antonio, or with multi-site portfolios that include Waha-influenced rate zones, this is a material factor in basis-related contract clauses.

4. Storage Position

The EIA Weekly Natural Gas Storage Report is published every Thursday at 10:30 a.m. ET. It reports the change in working gas in underground storage in the Lower 48 versus the prior week. The market trades almost entirely off the difference between the printed number and the consensus forecast — a "build" of 50 Bcf when traders expected 75 will rally prices; an injection of 100 Bcf when 75 was expected will sell off. The five-year storage average for any given week is the benchmark. As of the January 30, 2026 report, working gas stocks were 8% below the five-year average, prompting EIA to raise its Henry Hub forecast for February and March by 40%. Storage carries the highest information density of any single weekly data release in commercial gas.

5. Production

Dry natural gas production from U.S. shale plays — Appalachia (Marcellus and Utica), Haynesville, Eagle Ford, and Permian associated — sets the supply curve. After two years of stagnant growth, production responds slowly to price signals: drilling activity, well completions, and pipeline expansion all run on multi-quarter lead times. When producers cut activity in late 2023 in response to sub-$3 gas, the resulting supply tightness contributed to the 2025-2026 price recovery. Commercial buyers signing long-dated fixed contracts in mid-2024 captured the low forward strip; buyers waiting until late 2025 paid materially more for the same term length.

Contract Structures: Fixed, NYMEX-Indexed, Hybrid, and Trigger

Once a Texas commercial buyer is on a transport-rate tariff and shopping the commodity portion of the bill, four contract structures cover essentially every real-world commercial gas procurement program. Each has a different risk-reward profile, and the right answer depends on your business's risk tolerance, load shape, and view of the forward NYMEX curve.

Fixed-Price Contracts

A fixed-price contract locks the full $/MMBtu (commodity plus basis) for the entire term, typically 12, 24, or 36 months. Your monthly commodity charge is the same in July and February. The supplier absorbs the market risk and prices a risk premium into the rate — usually 5 to 15% over the prevailing forward NYMEX strip plus expected basis. You are paying for certainty.

Fixed contracts are the right answer for tight-margin businesses where a winter spike would damage operations — restaurants, hotels, places of worship, small manufacturers, multi-family operators, and any business that needs predictable utility costs to support a board-approved budget. They are the wrong answer if you have a strong view that NYMEX is overvalued and you can stomach a 12-to-24-month bet against the curve. The risk premium is real money on a 30,000 MMBtu/year account.

NYMEX-Indexed Contracts

An indexed contract ties your monthly commodity charge to the NYMEX Henry Hub monthly settle plus a transparent basis differential and a small marketer fee. If the NYMEX March contract settles at $4.20/MMBtu and your contract is "NYMEX + $0.35 basis + $0.08 marketer fee," your March commodity rate is $4.63/MMBtu. April resets to the next month's settle.

Indexed pricing means you capture market downside — when NYMEX falls, your bill falls. It also means you carry full market risk on the upside. In a winter like January 2026, the indexed customer paid $9+/MMBtu commodity for the month, while the fixed customer paid whatever they locked when they signed. For buyers with the cash-flow flexibility to absorb monthly variance and the conviction that the forward strip is overpriced, indexed contracts have historically outperformed fixed over multi-year holding periods. The catch is that historical outperformance is computed on portfolios that did not have to write a $40,000 check for a January gas bill.

Hybrid (Block-and-Index)

A hybrid contract splits your load — typically 50/50 or 70/30 — between a fixed block and an indexed remainder. The fixed block insulates you from the worst of a winter spike; the indexed portion lets you participate in market downside the rest of the year. For most mid-size commercial buyers between 5,000 and 50,000 MMBtu/year, hybrid structures are the practical middle ground. You give up some upside in exchange for sleeping through winter.

The way to think about hybrid sizing is to fix the portion of your load that you absolutely cannot afford to overpay for. If your facility has a $25,000/month commodity budget at $4 NYMEX and a winter spike to $9 would create a $40,000+ bill that breaks the budget, fix enough volume so that the indexed portion alone, at the worst-case winter price, fits inside the monthly budget. The leftover is fixed. This is the same logic insurance companies use to calibrate deductibles, and it works because commercial gas exposure is a tail-risk problem, not an average-cost problem.

Trigger / Managed Hedge

Trigger contracts and managed-hedge programs sit on top of an indexed base contract. The customer pre-sets target prices at which fixed-price blocks will execute automatically. If you set a target of $3.80/MMBtu for the calendar 2027 strip and NYMEX prints below it for any settlement day during the program window, your supplier executes a fixed block at that level — converting that portion of your indexed exposure to fixed at the target price. You can layer multiple triggers at different levels, building a fully fixed position over time as the market gives you the prices you want.

Triggers are the most sophisticated retail structure available to commercial gas buyers. They are well-suited to facilities and energy committees with a structured procurement policy and the operational discipline to set targets and stick to them. They are not well-suited to buyers who set targets based on emotion or who second-guess the program every time the market moves. We have seen trigger programs save sophisticated industrial customers 8 to 15% versus straight fixed-price benchmarks. We have also seen them sit unfilled for the full program window because the buyer set targets below where the curve ever traded.

Rate Classes and Why Most Commercial Accounts Are on the Wrong One

Before you shop any commercial gas contract, the highest-leverage move is checking that you are on the right LDC rate class. Texas LDC tariffs typically include a sequence of commercial rate classes — small commercial, medium commercial, large commercial, and transport service — each with progressively lower fixed monthly customer charges, lower per-Mcf delivery rates above the threshold, but stricter minimum usage requirements and demand-charge structures.

We routinely audit accounts that have been sitting on a small-commercial rate class for years while consuming enough gas to qualify for medium or large commercial — paying 15 to 30% more on the delivery portion of every bill purely because the LDC never proactively moved them to the cheaper tariff. The LDC has no obligation to move you; you have to ask, in writing, and provide 12 months of usage history to justify the reclassification.

For accounts above roughly 30,000 Mcf annually (numbers vary by LDC and territory), transport service is almost always the correct answer. Under transport service, you arrange your own commodity supply through a marketer or broker — bypassing the LDC's default-supply markup entirely — and the LDC delivers your nominated volumes at the regulated delivery rate. The all-in savings versus the bundled tariff are typically 10 to 20%, and they compound year after year because the cheaper rate class is also the foundation that lets you shop competitive commodity contracts at all.

The LDC territories you will deal with

Reading a Commercial Natural Gas Bill: A Line-by-Line Walkthrough

Every Texas commercial gas bill, regardless of LDC, contains the same logical components even if the line-item names differ. We have audited thousands of these bills and the pattern is consistent.

  1. Customer charge. Fixed monthly fee, $50 to $400+. Independent of usage. Set by tariff for the rate class.
  2. Consumption (Mcf or MMBtu). Actual metered volume for the billing period, BTU-adjusted to the LDC's published heat content.
  3. Commodity charge. The commodity portion — either the LDC's pass-through default-supply price (PGA, or Purchased Gas Adjustment) for bundled customers, or your marketer's contracted price for transport-service customers. This is what you negotiate.
  4. Delivery charge. Per-Mcf charge for use of the LDC's distribution system. Set by tariff. Not negotiable.
  5. GRIP / pipeline rider. In Atmos territory specifically, the Gas Reliability Infrastructure Program surcharge recovers pipeline-replacement capex on accelerated terms. Other LDCs have analogous riders.
  6. Securitization / Uri recovery. A small per-Mcf rider funding the bond issue that securitized the Winter Storm Uri commodity-cost shortfall in 2021. Will continue until approximately 2037.
  7. Energy efficiency rider. Mandated funding for state-approved demand-side management programs.
  8. Local gross-receipts tax / franchise fee. Varies by municipality. Houston, Dallas, Fort Worth, and Austin all assess different rates.
  9. State sales tax (if applicable). 6.25% Texas sales tax plus local sales tax (up to 2% additional), applied to non-manufacturing commercial gas use.
  10. Imbalance / nomination charges (transport-service customers only). If your actual usage diverges from your monthly nomination by more than the tariff-defined tolerance band, the LDC charges (or credits) the imbalance at a tariff-specified rate. Well-managed transport-service accounts keep imbalance charges near zero.

A common pattern we see on commercial gas bills: a single mis-coded line item, or a rate class that doesn't match the customer's actual consumption profile, costs the customer $3,000 to $15,000 per year for months or years before anyone catches it. A 60-minute bill audit on the first quarterly bill of every supplier relationship pays for itself many times over.

What Commercial Natural Gas Rates Actually Look Like in Texas Right Now

We deliberately do not quote a single number for "the" Texas commercial natural gas rate, because there isn't one. The rate any specific business pays is a function of LDC, rate class, contract structure, contract date, annual consumption, basis assignment, and the marketer's competitive position on the day the contract was priced. But we can give the orientation ranges that buyers should expect, current to May 2026.

For benchmarking your own account: divide your annual gas spend by your annual Mcf consumption. That gives you all-in $/Mcf. Divide by 1.038 for $/MMBtu. Compare that to the commodity strip on the date you signed your current contract — if the gap is more than $2.50/MMBtu, you are very likely either on the wrong rate class, on a bundled tariff that should be transport, or on a stale contract that needs to be re-shopped.

Why Winter Is Different — and What Uri and Fern Taught Us

Texas commercial gas buyers learned two lessons the hard way in the last five years. Winter Storm Uri in February 2021 took the Panhandle Eastern Texas/Oklahoma delivery point from $2.55/MMBtu to $224.56/MMBtu in two weeks. The Oklahoma Corporation Commission documented spot prices spiking from $3 per Mcf to over $1,200 per Mcf in the worst of the event. Texas residential and small commercial gas customers were buffered from the full hit by the securitization program — the state authorized a 16-year bond issue to spread the cost across decades of customer billing — but mid-size and larger commercial customers, especially those on indexed contracts without basis caps, took the spike directly to the income statement.

Winter Storm Fern in January 2026 was a milder repeat. Henry Hub spiked to $9.03/MMBtu and EIA raised its February-March price forecast by 40% in a single STEO revision. Working storage closed the heating season 8% below the five-year average, leaving the market tight heading into the summer injection cycle. Texas commercial buyers on indexed contracts who had not built any fixed protection were paying 200%+ of their normal commodity rate for the month.

The lesson for commercial procurement: Texas weather risk is not a tail event you can dismiss as once-a-decade. Uri was 2021. Fern was 2026. The forward curve does not adequately price the cost of these events because the market views them as statistically rare; the operating reality is that they cluster, and a commercial gas program that has no fixed-price protection going into any winter is taking a structural risk that does not match what most CFOs would write into a board-level risk policy.

Practically: most Texas commercial buyers should carry at least 50% fixed-price exposure for November through March. The remaining 50% can sit at index for the rest of the year and through milder shoulder months. This is essentially the same logic we apply to electricity hedging, and the same logic that pricing desks at the major suppliers use to manage their own books.

Contract Terms That Matter More Than the Headline Rate

Commercial gas contracts run 5 to 20 pages, and the headline $/MMBtu rate is one number on the front page. The other 4 to 19 pages contain provisions that determine whether the rate on page one is actually what you end up paying. The clauses to read before signing:

Swing Bandwidth

A swing clause defines the range of monthly consumption around your nominated volume within which the fixed price applies. Outside the bandwidth, the supplier reprices the excess (or shortfall) at the prevailing spot market price — which can be 3x to 10x the contracted rate during winter. A typical commercial bandwidth is plus-or-minus 15 to 25%. If your business has seasonal load — a restaurant with patio heaters and outdoor seating, an event venue with variable booking patterns, a hotel with seasonal occupancy swings — you need a wider bandwidth or a non-bandwidth contract structure. Locked into 100% take-or-pay on a fixed nomination, you can lose all the savings of the negotiated rate in a single overconsumption month.

Force Majeure and Material Adverse Change

Every commercial gas contract includes a force-majeure clause that suspends supplier obligations under defined extreme events. The Material Adverse Change (MAC) clause is more subtle: it permits the supplier to reprice or terminate the contract if the market moves against them by more than a defined threshold. After Winter Storm Uri, some Texas suppliers invoked MAC clauses to pass through commodity costs that customers thought their fixed contracts protected against. The MAC clause is buried, narrowly worded, and rarely triggered — but when it triggers, it can cost a commercial customer their entire annual budget in a single month. Have your broker or counsel review the force-majeure and MAC language before signing.

Pass-Through Clauses

Almost every commercial gas contract permits the supplier to pass through certain regulatory, tariff, or pipeline-tariff cost increases. The question is which costs and how much. A well-drafted contract limits pass-throughs to LDC tariff changes filed with the Railroad Commission. A poorly drafted contract gives the supplier broad discretion to pass through "any cost increase" — which has been used historically to absorb pipeline-capacity reservation cost increases, basis-differential widening, and even credit-charge increases on the supplier's own balance sheet.

Early Termination Penalty

If you sign a 24-month fixed contract and the market drops 30% six months in, you are not allowed to just rip up the contract — the supplier has already hedged your forward exposure in the wholesale market and would lose money on the hedge if you walked away. Early termination penalties are typically the greater of (a) a stated dollar amount per Mcf of remaining volume, or (b) the supplier's actual liquidation loss on the wholesale hedge. The (b) formulation can be punitive in falling markets. Read the formula carefully before signing.

Auto-Renewal / Evergreen Clauses

Many Texas commercial gas contracts default to month-to-month at a tariff or default-supply rate after expiration unless the customer signs a new contract or provides written termination notice 30 to 90 days before expiration. The default rate is almost always materially higher than the contracted rate — sometimes 50 to 200% higher. We see commercial accounts roll onto auto-renewal evergreens for 6 to 18 months at a time, paying winter spot prices through a full heating season before anyone catches it. The fix is calendar discipline: every commercial gas contract end date should be in the procurement calendar, and re-shopping should begin 4 to 9 months before expiration. This is the exact same discipline that drives electricity renewal timing, and the same penalty math applies in both markets.

Which Commercial Operations Get the Biggest Wins From Optimizing Gas

Not every Texas commercial business has the same upside from active gas procurement. The accounts where the math works hardest:

The common thread: any Texas commercial operation consuming 5,000+ Mcf annually has enough volume to make the contract structure decision meaningful, and any operation above 30,000 Mcf has enough to make transport service the obvious right answer.

How to Actually Shop the Commercial Natural Gas Market

The shopping process for commercial gas is mechanically similar to commercial electricity, but the timing windows and the data inputs differ.

1. Pull 12 months of usage history

Your LDC will provide a 12- or 24-month consumption history under a Letter of Authorization (LOA) that gives a third-party broker or marketer permission to request the data. The LOA is not a contract and does not commit you to switching. It is the first step in any honest procurement process — without 12 months of actual Mcf data, no supplier can quote competitively, and any rate they do quote is based on assumed load shape that may not match yours.

2. Confirm your rate class is correct

Pull your current LDC tariff filing (publicly available on the Railroad Commission website for Atmos, CenterPoint, Texas Gas Service; on CPS Energy's website for San Antonio). Identify which rate class your annual consumption qualifies for. If you are sitting on a small-commercial tariff and your consumption qualifies you for medium or large commercial, file the rate-class change request first. Then shop the commodity contract on the correct, lower-cost rate base.

3. Decide your structure

Before requesting quotes, decide whether you want fixed, indexed, hybrid, or trigger. Mixed quotes across structures are confusing and make it harder to compare suppliers apples-to-apples. If you cannot decide, a broker can run a short cost-of-risk analysis comparing the historical hindsight outcome of each structure against your specific load history — usually a one-day exercise.

4. Solicit competitive bids

Texas has roughly 8 to 15 licensed natural gas marketers that quote competitively for commercial business across the major LDC territories. Each will price differently depending on their balance-sheet capacity, their hedge portfolio, and how badly they want your specific load shape. The spread between the best and worst quote on the same RFP is usually 10 to 25%. Without competitive bids, you cannot know whether a single supplier's quote is competitive.

5. Compare on all-in cost, not headline rate

Make sure every quote includes: commodity rate, basis, marketer fee, swing bandwidth, force-majeure language summary, pass-through scope, early termination formula, and contract end date. Two quotes at "the same" headline $4.50/MMBtu rate can produce wildly different all-in costs depending on bandwidth, basis assignment, and pass-through scope.

6. Sign and calendar the renewal

Sign, then immediately put the contract end date in your procurement calendar with a 6-month-before reminder. Re-shop starts 4 to 9 months before expiration — early enough to capture favorable market windows, late enough that the forward strip is meaningful for your delivery period.

Why Most Texas Commercial Buyers Use a Broker for Gas

The same logic that drives most Texas businesses to use a broker for electricity applies to commercial gas, with two extra reinforcing factors specific to the gas market.

First, the natural gas commercial marketplace is less transparent than the electric ERCOT market. There are fewer licensed marketers, contract terms vary more widely, and basis differentials introduce a pricing dimension that is genuinely difficult for non-specialist buyers to evaluate. A broker who quotes gas every week across multiple LDC territories has the live pricing reference points that a single business doing a once-every-two-years RFP simply cannot have.

Second, the bill audit and contract-management workload on the gas side is heavier than electric. Rate-class changes, GRIP rider updates, basis assignments, swing nominations, transport service paperwork, monthly imbalance reconciliations on transport accounts — none of these are difficult, but they require attention every month, and most facilities teams do not have the time or the energy-market context to do them well.

Brokers are paid by the supplier — the fee is a transparent $/Mcf adder built into the price, fully disclosed. There is no out-of-pocket cost to the customer for the brokerage service, and the market-aggregate volume that a broker carries usually produces commodity pricing that is at or below what a single business gets going direct. The broker fee is not added on top; it is part of how suppliers price commercial gas to the channel.

The Commercial Natural Gas Procurement Mindset

Commercial natural gas in Texas is a structurally volatile market sitting on top of a regulated delivery system, with five interacting price drivers, four contract structures, and a stack of LDC tariff complexity that most facilities teams do not have the bandwidth to navigate on their own. The buyers who consistently outperform are not the ones who get lucky with timing — they are the ones who put structural protections in place (correct rate class, transport service, hybrid contracts with meaningful fixed exposure into winter, audited bills) and then re-shop on a disciplined calendar.

Every winter, Texas commercial gas customers split into two groups: the ones who had a fixed-price layer on November 1 and the ones who did not. The first group runs the same P&L in January that they ran in October. The second group has a hole in the budget that gets explained at the next board meeting. The cost of being in the first group is the risk premium baked into fixed pricing — meaningful, but bounded. The cost of being in the second group is unbounded and shows up exactly when you can least afford it.

For Texas commercial operations of any meaningful gas-consumption scale, this is the single most important call in the utility procurement calendar — and the one most facilities teams have the least time to make well.

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