Summary — Profit and Loss Analysis

Overview: The Economics of Natural Gas Trading

This module introduces the foundational economics of natural gas trading, focusing on how prices are constructed from a base commodity index through to the final sale price — and how profit or loss is determined along the way. The core insight is deceptively simple: the cost of natural gas increases as it moves from the point of purchase to the point of sale, because every step in the logistical chain adds cost. Understanding, quantifying, and managing these costs is the heart of Profit and Loss (P&L) analysis in energy trading.

Index Pricing: Building the Price from the Ground Up

Natural gas prices are not set arbitrarily — they are constructed systematically from a series of components, each representing a real economic element of the transaction.

The Base Price: Henry Hub and NYMEX

The starting point for virtually all natural gas pricing in North America is the Henry Hub, a physical pipeline hub located in Louisiana that serves as the benchmark delivery point for the NYMEX (New York Mercantile Exchange) natural gas futures contract. The NYMEX price at Henry Hub represents the pure gas cost — the commodity value of the gas itself, stripped of any transportation, handling, or administrative costs.

• In the course model, Henry Hub is priced at $3.00/MMBtu as the base index
• This is the starting number from which all other pricing builds upward

Key principle: Henry Hub / NYMEX is the universal reference point. Every other price in the natural gas market is understood relative to this benchmark.

Locational Indexes: City Gate Prices

Gas does not stay at Henry Hub — it flows to consuming markets across the country. Each major market hub has its own basis (logistical cost) appropriate for that location." class="glossary-term">locational index, which reflects the published market price at that specific geographic location. These prices are reported in industry publications and incorporate the market's collective assessment of all the costs and supply/demand dynamics for that location.

From the spreadsheet model, the following city gate prices are shown:

The difference between the Henry Hub price and any locational index price is called the basis — a critical concept in gas trading that reflects the cost and value of moving gas from the benchmark hub to a specific location.

Supply Chain Costs: The Logistical Cost Stack

Between the point of purchase (supply point) and the point of sale (demand point), a trader or marketer incurs a series of logistical costs that must be recovered in the selling price. Together, these costs form what practitioners call the "cost stack." The module breaks these down into four distinct categories:

1. Transportation Cost

The fee paid to a pipeline company to physically move gas from Point A to Point B. This is typically a tariff-based charge expressed in $/MMBtu or $/Dth. In the Chicago example, transportation cost is $0.175/MMBtu.

2. Retained Fuel Cost (Fuel Cost)

Pipelines consume gas as fuel to operate their compressor stations. They "retain" a percentage of the gas flowing through them as payment for this fuel. This means the seller must purchase slightly more gas at the supply point than will actually be delivered at the demand point — the difference is the fuel cost. In the WACOG model, a fuel retention rate of 2.55% is shown (0.0255). In the Chicago example, retained fuel cost is $0.225/MMBtu.

• Formula for supply volumes: Landed Volumes ÷ (1 − Fuel%) = Supply Volumes required
• Example: To deliver 25,000 MMBtu after 2.55% fuel retention, you must purchase 25,654 MMBtu at the supply point

3. Administrative Cost

Overhead and administrative expenses associated with managing the transaction — scheduling, contracting, back-office processing, etc. In the Chicago example: $0.040/MMBtu.

4. Other Incurred Costs

Miscellaneous costs that don't fit neatly into the above categories — could include balancing charges, penalties, or minor operational fees. In the Chicago example: $0.005/MMBtu.

Total Logistical Cost Summary (Chicago Example)

Note that the model also includes an embedded profit component of $0.035/MMBtu within the logistical cost stack. This represents profit that is "locked in" through the cost structure itself — for example, a margin built into a transportation agreement or service contract.

The Landed Price: Arriving at Market

The landed price is the total all-in cost of gas at the delivery point, before any market pricing adjustments. It equals the pure gas cost index plus all logistical costs:

Landed Price = Gas Cost Index + Total Logistical Cost

Examples from the model:

The landed price can be thought of as the trader's "break-even" price at the delivery point — the minimum price at which they would need to sell to recover all costs (excluding any profit target).

Importantly, the landed price in these examples equals the published city gate index price for those markets. This is not a coincidence — it illustrates that market index prices at city gates are, in effect, the market's consensus landed cost for gas at that location.

From Landed Price to Sales Price: Market Premiums and Discounts

Once the landed price is established, the actual sales price is determined by applying a market premium or discount (adder) to either the landed price or the published locational index:

Sales Price = Locational Index ± Market Premium/(Discount)

These adders reflect the specific commercial terms negotiated with a buyer. A premium (+) means the seller is capturing additional value above the index; a discount (−) means the seller is offering a price reduction to win the business.

In the Chicago case, the seller is offering a slight discount to the market to be competitive. In Washington DC, the seller commands a small premium.

Profit and Loss Determination

With the sales price and the landed cost both known, the profit or loss per unit is straightforward:

Profit/(Loss) = Sales Price − Landed Price

Or equivalently, since the landed price incorporates an embedded profit margin:

Profit/(Loss) = Sales Price − (Gas Cost Index + Logistical Cost)

Note: The embedded profit of $0.035 is already baked into the logistical cost stack. The net P&L shown ($0.030 for Chicago) reflects Sales Price minus the cost stack including embedded profit, meaning the trader earns $0.030 above all costs including the embedded margin layer.

WACOG and WAPOG: Blended Cost Analysis

When a trader is purchasing gas from multiple supply sources at different prices and volumes, the simple per-unit cost from any single transaction is insufficient for P&L analysis. The module introduces two blended cost metrics:

WAPOG — Weighted Average Price of Gas

The WAPOG represents the volume-weighted average purchase price of gas across all supply contracts, before any logistical costs are added. It answers the question: "What did we pay for the gas itself, on average?"

WAPOG = Σ(Volume × Price) ÷ Σ(Volume)

From the WACOG spreadsheet:

WAPOG = $332,941.01 ÷ 102,617 = $3.2445/MMBtu

WACOG — Weighted Average Cost of Gas

The WACOG is the "flowing" cost of gas — it adds all logistical costs to the WAPOG to arrive at the true all-in cost per unit at the delivery point. This is the most important cost metric for P&L analysis because it reflects what was actually spent to deliver gas to the customer.

WACOG = (Total Supply Cost + Total Logistical Cost) ÷ Landed Volumes

From the spreadsheet:

• Total supply cost: $332,941.01
• Total fuel cost: −$2,617 (volumes lost to fuel retention)
• Total transportation charges: $17,500
• Landed volumes: 100,000 MMBtu
• WACOG = $350,441.01 ÷ 100,000 = $3.5044/MMBtu

The WACOG is the benchmark against which the selling price is compared to determine actual profitability. If the sales price exceeds the WACOG, the position is profitable.

Real-World Significance

In practice, a gas marketer may be blending supply from Oklahoma wells (cheaper, but farther from some markets), Mississippi production (moderate price, different pipeline access), and spot purchases on various pipelines. The WACOG tells the marketer their true blended cost regardless of the complexity of the supply portfolio.

The module illustrates a simple two-supply example:

• Oklahoma gas: $3.20/MMBtu + $0.15 logistical = $3.35 landed
• Mississippi gas: $2.95/MMBtu + $0.50 logistical = $3.45 landed

Despite Oklahoma gas being more expensive at the wellhead, its lower logistical cost means it lands cheaper in certain markets. This interplay between supply price and logistical cost is what makes WACOG analysis essential.

Inside FERC vs. Gas Daily: Monthly vs. Daily Index Pricing

The module briefly introduces the distinction between two types of published price indexes used in the industry:

• Inside FERC (IF) — A monthly price index published at the beginning of each month. Contracts priced at "IF" are settled at a single monthly price. In the ANR pipeline example, the IF monthly price is shown as $3.7227/MMBtu.

• Gas Daily (GDD — Gas Daily Daily) — A daily price index published for each gas day. Contracts priced at "GDD" float with daily market conditions. The spreadsheet shows daily prices varying around the monthly IF price:

This distinction matters for P&L analysis because a position priced on GDD will have daily P&L fluctuations, while an IF-priced position locks in the monthly settlement price at the start of the month.

Connecting P&L to the Broader ETRM Framework

P&L analysis sits at the intersection of multiple ETRM disciplines:

• Nominations and Scheduling establish the physical volumes flowing, which determine the volumetric basis for all cost calculations
• Contract Management defines the pricing terms (index, adder, volume) that feed into sales price calculations
• Risk Management uses P&L metrics to assess exposure — a negative or thin margin position may trigger hedging activity
• Settlement and Invoicing converts the per-unit P&L calculations into actual cash flows
• WACOG tracking is an ongoing operational accounting function, updated daily as gas flows and costs are confirmed

The supply chain cost model taught in this module is not merely theoretical — it is replicated in ETRM systems as the cost-of-gas (COG) or cost-of-service (COS) module, which automatically calculates landed costs and margins for each deal in the portfolio.