AEC Market Education - Module #3
Market timing, hedging, and why we fix pricing
The market doesn't care when your contract expires. But the businesses that treat energy like a manageable risk rather than an inevitable cost consistently pay less over time. Here's why — and how.
Part 1
First, a reframe: which one is actually the gamble?
Common misconception
“Locking in a fixed rate is risky”
The concern goes: what if prices fall after I lock in? I’ll be stuck paying above market. This feels like the cautious position — staying flexible, keeping options open. It isn’t. It’s the position of someone who has decided to bet on the market moving in their favor, without necessarily knowing they’ve made that bet.
What’s actually true
Doing nothing is the gamble
Every month you operate without a fixed price is a month your energy cost is determined entirely by whatever the market happens to be doing. That’s not flexibility — it’s exposure. A deliberate decision to fix pricing at a point of value is a hedge. An undermanaged contract that auto-renews at whatever rate the market offers is a gamble, dressed up as the status quo.
The core insight
“Hedging doesn’t mean predicting where prices go. It means deciding how much risk your business can absorb — and managing to that number.”
A refinery hedges jet fuel. A restaurant chain hedges cooking oil. An airline hedges aviation fuel. None of them know exactly where commodity prices are headed. They hedge because price certainty has operational value — it lets them plan, budget, and compete without energy cost volatility undermining the rest of the business. Commercial electricity is no different.
Part 2
Auto-Renew Inc. vs. Market-Timed LLC: five years of difference
Usage size:
Forward curve at renewal windows
Auto-Renew Inc. — locked rate
Market-Timed LLC — locked rate
Rates and savings are illustrative and percentage-based. Actual results vary with market conditions, usage profile, and timing. Not a forecast or guarantee.
Auto-Renew Inc. — avg rate
—
5-year average
Market-Timed LLC — avg rate
—
5-year average
5-year cost difference
—
illustrative · not a guarantee
Part 3
What market timing actually looks like in practice
01
Watching the curve, not the calendar
The forward curve tells you what the market thinks electricity will cost in the future. A good advisor watches that curve continuously — not just when your contract is about to expire. When the curve dips to an attractive level, that’s the signal. Your expiration date is a constraint, not a trigger.
02
Knowing your seasonal windows
ERCOT forward prices tend to be most favorable during two windows each year: late September through mid-November, and mid-February through mid-March. These shoulder periods follow peak summer and winter risk and typically offer the flattest, most competitive forward curves. Renewing inside a summer or winter risk window almost always costs more.
03
Starting early enough to have options
A contract that expires in August and isn’t shopped until July has no timing flexibility at all — it’s renewing at whatever the curve shows during peak summer risk. Meaningful market timing requires lead time of 3 to 12 months depending on contract size and market conditions. The larger the account, the more lead time matters.
04
Understanding that “lock in” isn’t binary
Sophisticated buyers don’t always go fully fixed or fully floating. Some lock in a base position and leave a portion floating. Some layer in tranches over time rather than committing all at once. The right structure depends on your budget tolerance, your usage stability, and your view of where the market is headed relative to the curve.
05
The hidden cost of doing it yourself
Monitoring forward prices, tracking Henry Hub, interpreting EIA storage data, managing vendor outreach, comparing bids, and reviewing contract language takes time — and that time belongs to someone on your payroll. For a facilities manager or CFO, even 10 hours per renewal cycle is a real number. The comparison between self-managed procurement and working with an advisor is only accurate when both sides of the ledger are fully loaded. Use the calculator below to see what your internal procurement cost actually looks like.
Internal procurement cost calculator
What does your time actually cost — per renewal cycle?
Decision-maker hourly rate
Fully-loaded cost of the person managing procurement — facilities manager, CFO, VP of Operations, etc.
Contract term
Longer terms reduce annualized procurement cost — but require more upfront market analysis to get right.
Select procurement tasks your team handles internally
Total hours per cycle
0
selected tasks
Cost per renewal cycle
$0
at your hourly rate
Annualized cost
$0
amortized over term
Per-MWh equivalent
—
select tasks above
For context: a residually-compensated broker on a typical commercial account generally earns somewhere in the range of $0.50 to $5.00 per MWh built into the energy rate — with most arrangements landing around $3.00/MWh absent an exclusive arrangement. No separate invoice, no direct cost to the customer. The per-MWh figure above is what your internal procurement cost translates to on the same basis. The two numbers are worth comparing directly.
Part 4
Three positions — only one of them is a hedge
Part 5
When to hedge: target prices, runway, and why smart buyers still get burned
The honest version
“If you’ve watched the market for over a year and you’re inside 90 days with no position, you haven’t been hedging. You’ve been at the casino — and you just haven’t admitted it yet.”
At that point the question isn’t fixed vs. float. The hedge window is closed. The only remaining decision is which index product limits the damage — and whether you can live with that outcome on a June start date staring into summer risk.
The target price trap
Setting a target price before the procurement window opens is sound practice. The problem is what happens next.
Step 1
$51.00/MWh
Forward curve today
You’ve done your homework. The curve is at $51 and your target was $52. This is the window. The rational move is to lock.
Within target — actionable
→
Step 2
$49.00/MWh
Two weeks later
Prices dipped. Now the brain recalibrates: “If I’d just waited, I could have locked at $49. Maybe $47 is possible.” The target moves. This is anchoring.
Target revised downward
→
Step 3
$56.00/MWh
Six weeks later
Gas moved. A cold front hit the forecast. The curve jumped. Now you’re above your original target with 60 days to expiration and no position. This is the nightmare — and it’s not rare.
Above original target — exposed
The runway clock: how much time do you actually have?
Meaningful market timing requires lead time. The larger the account and the more complex the approval chain, the earlier the clock starts. These are working guidelines — not guarantees. Inside these thresholds, the hedge window is effectively closed and index pricing deserves serious consideration.
Account type
Recommended runway
Inside this = index territory
Notes
Large commercial / industrial
1,000+ kW
12–18 months
6 months
Interval metering, complex load shapes, and tranche strategies require extended lead time
Mid-market commercial
100–1,000 kW
6–9 months
3 months
Most ERCOT commercial accounts fall here; the seasonal window matters most at this tier
Small commercial
<100 kW
3–6 months
60–90 days
Less curve sensitivity but same psychological traps; simpler to execute when the timing is right
Non-profits, churches, schools, HOAs
Any size
Add 2–3 months
to any tier above
6 months minimum
Budget cycles are rigid, approval chains are slow, and there’s rarely a market-literate decision-maker in the room
Index pricing isn’t inherently bad — it’s uninformed exposure to index pricing that creates problems. A buyer who understands real-time market mechanics and has the operational flexibility to absorb price swings can make a rational case for floating. The issue is the buyer who ends up on index by default, having run out of runway without realizing it, facing a summer expiration with no plan. Those two situations look identical on the bill. They aren’t.