Summary — Profit and Loss Analysis

Overview and Purpose

This module introduces the foundational concepts of how profit and loss are calculated in the natural gas trading industry. The instructor emphasizes that while real-world trading can be highly complex, understanding the core mechanics — how gas is priced, how costs accumulate along the supply chain, and how margins are calculated and protected — enables meaningful participation in industry conversations. The module blends conceptual explanation with live spreadsheet walkthroughs and a practical lab exercise using a simulated ETRM system.

Index Pricing" data-glossary-def="A pricing methodology in which the transaction price is tied to a published market index (such as Henry Hub NYMEX, Inside FERC, or Gas Daily) rather than a fixed negotiated price. Most physical gas transactions in North America use index pricing with adders." class="glossary-term">Index Pricing vs. Fixed/Flat/Spot Pricing

One of the most important distinctions in natural gas trading is the difference between fixed (flat/stated/spot) pricing and index pricing.

• Fixed price (also called flat price, stated price, or spot price) is straightforward: two parties agree on a specific dollar amount per unit before the transaction. The price is known, agreed upon, and does not change. For example, "I will sell you gas at $3.25 per MMBtu" — that is the deal.
• Index pricing is fundamentally different: the buyer and seller agree to a transaction today, but the actual price is not known until it is published the following day or at the start of the month. This is unusual compared to most industries — as the instructor notes, you would never buy a truck today without knowing the price until tomorrow. However, in natural gas, this works because both the buy side and the sell side are typically both indexed, meaning the unknown price flows through both legs of the transaction simultaneously, canceling out price risk and leaving only the margin exposed.

Key insight: If you buy at index and sell at index, the fluctuation in the underlying gas cost is irrelevant to your profit. Your profit is determined solely by the spread or margin you added. If, however, you buy at a fixed price and sell at index, you are exposed to price movement in the wrong direction.

The NYMEX Price and Henry Hub as the Pure Gas Cost Benchmark

The NYMEX (New York Mercantile Exchange) price, anchored at Henry Hub in Louisiana, serves as the universal benchmark for pure natural gas commodity cost in the United States.

• Henry Hub was chosen as the pricing benchmark because it is an enormous compressor and processing station through which approximately seven major pipelines converge, making it the most liquid and representative point for establishing a commodity price.
• The instructor uses the analogy of a truck manufactured in South Carolina: the factory cost (manufacturing cost) stops the moment the truck leaves the factory gate. Any additional cost to transport the truck to Chicago or California is a logistical cost. Similarly, the pure gas cost stops at Henry Hub (NYMEX), and everything beyond that point is a logistical cost.
• Henry Hub / NYMEX price is the same across all locations in the country in terms of its commodity component. What changes between locations is the logistical (transport and fuel) cost layered on top.

Important nuance — the fracking disruption: When hydraulic fracturing (fracking) unlocked large natural gas reserves in Pennsylvania, Ohio, and New York, it disrupted the traditional south-to-north flow model. Gas that once had to travel from Louisiana/Texas northward (accumulating logistical costs along the way) now competed with locally produced frack gas at lower landed prices. This forced traders and analysts to recalibrate their pricing models because the assumption that gas always gets more expensive as it moves north was no longer universally true.

The Two Components of Gas Price

Every natural gas price at any location is composed of exactly two components:

The sum of these two components is the locational index price for that market area. Index publishers such as Platts and Natural Gas Intelligence (NGI) aggregate actual transaction data from buyers and sellers in each region and publish these index prices, effectively capturing both the gas cost and the logistical cost in a single number.

Transportation and fuel loss as the two primary logistical cost sub-components:

• Transportation charges — the tariff paid to the pipeline for moving the gas from point A to point B.
• Fuel loss (fuel retention/shrinkage) — pipelines consume a portion of the gas flowing through them to power compressors. This gas is physically burned and is gone. The shipper must purchase extra gas upfront to account for this loss.

Gas Daily (Daily Index) vs. Inside FERC (Monthly Index)

There are two primary published index types that the industry relies on:

Gas Daily (Daily Index)

• Published every business day.
• The price reflects transactions that took place in that market area on that specific day.
• On weekends (Saturday, Sunday, Monday), a single three-day price is published because the markets are closed on Saturday and Sunday — meaning Friday's price covers Friday, Saturday, and Sunday, and Monday's price is set on Friday as well.
• Risk profile: Using gas daily pricing means your cost changes every single business day. If you believe prices will be lower on a daily basis than the monthly index, you can potentially save money. However, an unexpected cold snap or supply disruption can spike daily prices significantly above the monthly index, resulting in substantially higher costs.

Inside FERC (Monthly Index) — abbreviated as IF

• Published once per month, at the start of the month (first of the month index).
• The price is fixed for the entire calendar month.
• Risk profile: Much lower price volatility for the buyer. The same unit price applies to every day of the month regardless of market conditions. If the daily market drops significantly mid-month, the inside FERC buyer misses out on those savings. Conversely, if prices spike, the inside FERC buyer is protected.

Spreadsheet illustration from the module: The instructor demonstrated a side-by-side comparison. A buyer purchasing 10,000 MMBtu/day at Inside FERC of $3.1575 pays exactly that price every day, resulting in a predictable monthly total. A buyer on gas daily daily might experience prices lower than $3.1575 on some days and higher on others. In a scenario where a cold snap pushed prices to $4.00 mid-month, the gas daily buyer could incur approximately $87,000 to $120,000 more than the inside FERC buyer over the same period.

How Indexes Are Constructed: Liquid vs. Non-Liquid Points

Not every geographic location in the pipeline network has enough transaction volume to generate a statistically valid index. The industry distinguishes between:

• Liquid points — locations where a large number of buy and sell transactions occur every day, providing a robust dataset for index calculation. Examples include the Houston Ship Channel and the Katy Hub in Texas. Platts and NGI can reliably publish an index for these locations.
• Non-liquid points — locations with too few transactions to independently calculate an index. These locations are priced relative to the nearest liquid index point, expressed as that index plus or minus a differential (basis).

Directional pricing logic:

• If you are buying gas at a location upstream (further from the market) of the liquid index point, and you still need to move that gas toward the market, you should pay less than the index price by the amount of transport and fuel you will incur to reach the index point. Otherwise you overpay.
• If you are buying gas at a location downstream (already past the index point, closer to the market), you should pay more than the index because those sellers have already incurred the cost of moving the gas to that point.

This is expressed in trading as "index plus" or "index minus" differentials, which also reflect supply/demand tightness: in a seller's market, sellers charge index plus; in a buyer's market (oversupply), sellers may accept index minus.

The Supply Chain Cost Stack: WAPOG → Logistical Costs → WACOG

Understanding how costs accumulate from the supply point to the delivery point is central to calculating whether a trade is profitable. The instructor introduces a specific terminology sequence:

WAPOG — Weighted Average Price of Gas

• WAPOG represents the blended, weighted average price paid for all gas purchased from multiple suppliers.
• Formula concept: Sum of (Volume × Price) for each purchase ÷ Total Volume = WAPOG
• Example: Purchasing 25,907 MMBtu at $3.35 from Supplier A, additional volumes at different prices from Suppliers B and C — the WAPOG is the volume-weighted average across all three.
• WAPOG is the price of gas, not the cost of gas. This distinction is important.

Logistical / Transport Costs

• These costs are incurred between the supply point and the delivery point.
• Primarily composed of transport charges (the pipeline tariff) and fuel loss (the volume of gas consumed by compressors).
• The fuel loss does not appear as a separate dollar line item in the traditional sense — it is a silent cost embedded in the WAPOG calculation because you paid for those volumes, burned them, and can no longer sell them. The remaining volumes must carry the cost burden of the burned fuel.

WACOG — Weighted Average Cost of Gas

• WACOG is the all-in landed cost per unit at the delivery point.
• It combines WAPOG + transport charges + the embedded cost impact of fuel loss.
• Formula concept: (Total purchase cost + Total transport cost) ÷ Delivered volume = WACOG
• This is the true cost floor below which you cannot sell gas without losing money.

Numerical example from the module:

The difference ($3.3452 vs. $3.2525 = ~$0.0927) is entirely attributable to fuel loss. When 309 MMBtu are burned as fuel, their $927 cost does not disappear — it is redistributed across the 10,000 MMBtu that were delivered. Each remaining MMBtu absorbs approximately $0.0927 of additional cost burden, driving the WACOG above the simple sum of purchase rate + transport rate.

Key insight for tests: The WACOG is always higher than the sum of WAPOG + transport rate when there is fuel loss, because the fuel loss reduces the denominator (delivered volume) while the numerator (total cost paid) remains unchanged.

Margin Calculation and the P&L Structure

Once WACOG is established, the trading entity must add a margin to earn a profit. The margin is the difference between the sales price and the landed cost.

• Margins in natural gas trading are typically quoted in cents per MMBtu (e.g., $0.02, $0.05, $0.13).
• At scale (e.g., 10,000 MMBtu/day × 30 days × $0.05/MMBtu), small per-unit margins generate meaningful absolute dollar profits.
• The competitive market naturally constrains margins — other marketers will undercut any company that tries to charge excessive margins, taking their customers.

Index-indexed deal structure — margin stability: When both the purchase and the sale are tied to the same index family, the gas cost component flows through both legs neutrally:

• If gas prices rise from $3.15 to $3.50: the purchase cost increases, but the sales revenue increases by exactly the same amount. Margin (in $/MMBtu) stays constant.
• If gas prices fall to $2.90: same logic — cost falls, revenue falls, margin stays constant.
• The only variable is the margin, which is set at deal time. This is one of the primary advantages of index-on-index trading structures.

Index plus/minus as margin management:

• In a slow market: sell at index minus (e.g., index − $0.02) to move gas and avoid being stuck with supply.
• In a tight market: sell at index plus (e.g., index + $0.03) to capture additional value.
• Marketers continuously manage this spread based on supply availability, weather forecasts, and competitive intelligence.

Hedge Trading as Risk Insurance

The module introduces hedge trading as a mechanism to protect against adverse price movements, particularly relevant when dealing with fixed-price or forward commitments.

• The analogy used is car insurance: just as you insure your car against the risk of an accident, a trader can insure a gas position against the risk of prices moving adversely.
• How it works: A trader agrees with a financial counterparty (a bank or hedge trader) to buy gas at a locked-in price (e.g., $3.00/MMBtu) for a future period. If the market price rises to $3.20, the counterparty pays the trader $0.20/MMBtu to compensate. If the market price falls to $2.90, the trader pays the counterparty $0.10/MMBtu. In both cases, the trader's effective cost is $3.00.
• The cost of hedging: If gas falls to $2.00, the hedged trader still pays an effective $3.00. The financial upside of cheap gas belongs to the hedge counterparty, not the trader. This opportunity cost is the "premium" of the insurance.
• Hedge trading is described as making a position "flat" — neutralizing directional price exposure.
• The instructor notes that institutions (banks, financial trading desks) will write these hedges, and that some customer positions can extend 35 years into the future.

Forward Pricing and NYMEX Futures

• The NYMEX exchange also provides forward price curves — published estimates of what natural gas prices will be in future months (e.g., November of next year = $3.4745/MMBtu).
• These forwards are constructed using economic analysis: GDP outlook, natural gas reserve data, pipeline infrastructure investments, weather patterns, and other macroeconomic factors.
• Physical gas deals are often benchmarked against NYMEX settlement prices, with the last few trading days of the month being critical settlement periods.

Platts and NGI as Index Publishers

• Platts (now part of S&P Global Commodity Insights, historically owned by Dun & Bradstreet) is the primary publisher of natural gas daily and monthly indexes. Platts receives transaction data from market participants and publishes indices for each major trading hub and pipeline zone multiple times per day.
• NGI (Natural Gas Intelligence) is another major index publisher serving the same function.
• These organizations publish indexes three times daily: an early estimate, a revised estimate, and a final settled index.
• Companies that use these indexes (e.g., traders, marketers, utilities) pay subscription fees to receive automated index feeds that can be integrated directly into ETRM systems.

Transco Zones as an Example of Location-Based Indexes

The Transcontinental Gas Pipe Line (Transco) runs from South Texas to New York City along the Eastern Seaboard. The pipeline is divided into numbered zones (Zone 1, 2, 3, 4, 5, etc.), and each zone has its own published index price because the logistical cost of delivering gas changes as it moves up the pipe.

• Zone 1 (southern end) has a lower index than Zone 5 (northern end) because more transport cost has been incurred by the time gas reaches Zone 5.
• Traders reference these as, for example, "Transco Zone 4 plus three cents" to communicate a price offer.

Lab Exercise: Multi-Pipeline Scheduling (Pool, Transfer, Transport)

The module includes a hands-on lab in an ETRM simulation system involving three pipelines: Northern Natural Gas (NNG), Natural Gas Pipeline Company (NGPL), and ANR Pipeline. The lab introduces the concept of pooling and inter-pipeline transfers.

Workflow sequence:

1. Enter buy and sell transactions on all three pipelines (fixed/spot prices as specified in the lab spreadsheet).
2. Pool all supply purchases on NNG into a single aggregate supply pool at a pooling point (D-Mark). No transport contract is required for the pooling step itself.
3. Satisfy NNG sales by transporting gas from the pool to the delivery customer using the appropriate transport agreement (system calculates fuel automatically).
4. Transfer remaining NNG gas to ANR via the interconnect.
5. Pool all supply purchases on NGPL into a mid-continent pool similarly.
6. Satisfy NGPL sales (to Centerpoint at the ANR interconnect) using the transport agreement.
7. Transfer remaining NGPL gas to ANR.
8. Schedule ANR using the transferred volumes from NNG and NGPL plus the direct purchases made on ANR, delivering to customers in the specified order.

Critical scheduling rules emphasized:

• Always schedule pipelines in dependency order — you cannot schedule ANR before completing NNG and NGPL because ANR depends on the transferred volumes.
• Always satisfy your own pipeline's customers before transferring surplus to another pipeline.
• Schedule transport links one at a time, not in bulk, to avoid incorrect gas tracing (cross-purchase/cross-sale contamination between counterparties).
• Verify results in the student portal after completion — the scheduling screen alone does not confirm correctness.

A "supplier pipe" vs. a "demand pipe": A pipeline that produces more supply than it needs internally to satisfy its own customer deliveries becomes a supplier pipe — it has surplus gas available to transfer to other pipelines. A pipeline that has more customer demand than its own supply sources is a demand pipe — it requires an incoming transfer to fulfill its delivery obligations.

Storage Pricing and WACOG

• WACOG has a secondary application in storage valuation. Rather than tracing the exact historical cost of every molecule injected into storage (which is operationally complex), companies may use the current WACOG as a proxy estimate for the value of gas in storage.
• This provides a consistent, defensible per-unit cost basis for gas held in inventory.