Energy Market Tools

01 — Historical Context

PJM BRA Clearing Prices by Delivery Year

PJM's Base Residual Auction procures capacity in advance of each delivery year. PJM is currently operating on a compressed auction schedule as it works back toward its traditional three-year-forward cycle. Locational constraints can cause individual PJM LDAs to clear above the RTO price — in the 2025/26 BRA, BGE and Dominion cleared materially above the RTO price. The 2028/29 BRA cleared July 14, 2026.

02 — Zone Reference

Select Your PJM Zone

Click your load zone to see capacity pricing context. Prices shown are 2025/26 delivery year results — the most recent year with complete zone-specific data. For 2026/27 and later delivery years, confirm zone-specific results at pjm.com.

03 — Cost Estimator

PJM Capacity Cost Estimator

Estimates annual retail capacity charges based on a customer's PJM Capacity Peak Load Contribution (PLC) and the applicable BRA clearing price.

PJM Capacity Tag / PLC (kW) Your Capacity Peak Load Contribution, assigned by your utility or retail supplier. Check your electric bill, PLC notification, or ask your supplier.

PJM Zone

Delivery Year

UCAP Obligation Factor Adjustments from PLC to final UCAP obligation, including zonal UCAP scaling and Forecast Pool Requirement. Use 1.00 if unknown.

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BRA Clearing Price ($/MW-day)

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UCAP Obligation (MW)

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Est. Monthly Charge

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This estimator is for budgeting and educational purposes. Actual retail capacity charges may also reflect utility-specific PLC calculations, zonal scaling, Forecast Pool Requirement adjustments, supplier methodology, losses, taxes, margins, and contract terms. Consult your supplier or utility for actual charges.

04 — Cost Composition

Typical C&I Electricity Bill: What You're Actually Paying For

In the PJM footprint, capacity costs represent 15–25% of a typical C&I electricity bill — and in a high-auction year, that share grows. Most buyers focus on energy commodity pricing and miss the larger capacity lever.

05 — Power Producer Tool

Spark Spread Calculator

The spark spread is the difference between power market revenue and natural-gas fuel cost per MWh of generation. A positive spark spread means power revenue exceeds gas fuel cost before variable O&M, emissions compliance, startup costs, and other operating expenses. Negative power prices and negative gas prices occur in real wholesale markets — both are permitted inputs here.

Gas Price ($/MMBtu)

Power Price ($/MWh)

Generator Type

Dispatch Hours / Year 4,380 hrs = 50% capacity factor. 8,760 = baseload.

Plant Capacity (MW)

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Fuel Cost ($/MWh)

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Annual Gross Margin

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Gas Breakeven ($/MMBtu)

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Spark Spread at Varying Gas Prices (chart updates on calculate)

Shows gross spark spread ±$2 gas price around your input at your stated power price and heat rate. Does not include variable O&M, fixed costs, emissions, or capacity revenue.

06 — Data Center / BTM Tool

BTM On-Site Generation Economics

Compares the economics of BTM on-site gas generation against purchasing from the grid. The core inputs capture variable energy costs. Use Advanced Assumptions to include capital, fixed O&M, gas transport, standby charges, and generator availability — which are critical to a complete economic assessment. Results labeled as variable-cost difference only unless advanced costs are entered. Interconnection and project-development timelines remain a major constraint for new large loads and generation. Even as PJM and NYISO reform their study processes, permitting, network upgrades, equipment lead times, gas infrastructure, transmission constraints, and construction requirements can materially delay commercial operation.

Facility Peak Load (MW)

Facility Load Factor (%) % of time at average load (e.g. 85% for a data center baseline load). Distinct from generator capacity factor.

All-In Grid Rate ($/MWh) Include energy commodity, capacity, transmission, distribution, and all riders. Ask your supplier for a fully loaded $/MWh.

Gas Price at Delivery ($/MMBtu) Use your actual delivery-point price, not Henry Hub. See Tool 07 for Northeast basis guidance.

Generator Heat Rate (Btu/kWh)

Variable O&M ($/MWh) Typical range: $8–$14/MWh for recip engines; $3–$8 for gas turbines.

Advanced Assumptions (capital, fixed costs, availability)

Generator Availability (%) Energy not served by BTM generator during planned or forced outages is purchased from the grid at your stated rate. Default 95% is a reasonable starting estimate.

Annualized Capital Cost ($/kW-year) Divide total installed $/kW by economic life (years), or use a CRF-based levelized cost. Leave 0 to see variable-cost-only comparison.

Fixed O&M ($/kW-year)

Firm Gas Transport / Reservation ($/kW-year) Fixed annual cost of firm gas transportation to your delivery point — often the largest omitted cost in BTM estimates.

Utility Standby / Backup Charges ($/kW-year) Many utilities charge standby or backup demand rates for customers with on-site generation. Verify with your utility tariff.

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Cost Component	Annual Amount
Annual Grid Cost (baseline)	—
BTM Annual Cost Components
Gas Fuel Cost	—
Variable O&M	—
Fixed O&M	—
Annualized Capital Cost	—
Gas Transport / Reservation	—
Utility Standby / Backup	—
Residual Grid Purchases (generator offline hours)	—
Total Estimated BTM Annual Cost	—
Estimated Annual Cost Difference	—

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BTM cost includes only items entered above. A complete economic assessment requires capex, financing terms, firm gas transport, utility standby/backup rates, emissions compliance, grid interconnection costs, project permitting, insurance, and tax treatment. These inputs vary significantly by project and jurisdiction. Do not present this output as guaranteed savings.

07 — Gas Supply Reference

Northeast Natural Gas Hub Basis Reference

Henry Hub is a reference price. Your plant or data center pays what it costs to deliver gas to your specific receipt point — which in the Northeast can be dramatically higher, especially in winter. Basis risk (the price differential between Henry Hub and your delivery point) is often the largest unhedged exposure in BTM and IPP fuel supply agreements.

Illustrative Historical Winter Basis Ranges. These ranges illustrate historical basis volatility and relative regional pipeline risk over recent winter periods. They are not current forward-market quotes and should not be used as executable pricing. Actual daily basis varies materially from these ranges and can exceed them during extreme weather or pipeline outages. Source: ICE, broker market data, pipeline tariff filings.

Hub / Delivery Point	Pipeline	Region	Illustrative Non-Winter Basis	Illustrative Winter Basis Range	Notes for BTM / IPP Fuel Supply
Henry Hub Benchmark	Sabine Pipe Line	Erath, Louisiana	$0.00 (index)	$0.00 (index)	NYMEX natural gas futures benchmark. No physical delivery in the Northeast — the difference between Henry Hub and your delivery point is what you actually pay.
Transco Zone 6 NY Constrained	Transcontinental Gas Pipe Line (Transco)	New York City pricing location; parts of the NYC metro area	+$0.25 to +$1.50	+$2 to +$20+	Primary NYC city-gate pricing point on the Transco system. Note: New Jersey project delivery pricing may reference Transco Zone 6 non-NY, TETCO M-3, or other points depending on physical delivery location — do not assume Zone 6 NY applies to all NJ projects. Transco is the most heavily subscribed pipeline in the Northeast corridor; winter spikes are common when firm capacity is fully allocated.
Algonquin Citygate Highly Constrained	Algonquin Gas Transmission	New England (CT, MA, RI, NH)	+$0.50 to +$2.00	+$5 to +$35+	Historically the most constrained pipeline hub in the country during cold snaps. New England pipeline infrastructure is severely capacity-limited. Basis spiked above $35/MMBtu during Winter Storm Elliott (December 2022). Any data center or power plant in New England should treat basis hedging at contract execution as non-negotiable. Consider firm transport acquisition and/or alternative supply options.
Tennessee Zone 6 (New England) Highly Constrained	Tennessee Gas Pipeline	New England (MA, CT, NY border)	+$0.25 to +$1.50	+$3 to +$30+	Parallel path to Algonquin serving New England. Similar constraint dynamics to Algonquin Citygate; the two pipelines serve overlapping markets and typically move in tandem during cold weather events. Both should be considered in supply portfolio construction for New England generation.
TETCO M-3 Moderate–High	Texas Eastern Transmission (TETCO)	Philadelphia / South Jersey / Delmarva	+$0.10 to +$0.75	+$1 to +$8	Primary delivery point for Philadelphia-area industrial customers and South Jersey generators. Less volatile than Algonquin/Tenn Z6 but subject to winter tightness. Relevant for PJM PECO and PSEG zone generators and BTM data center projects in the Philadelphia metro corridor.
Eastern Gas South (formerly Dominion South) Appalachian Discount	Equitrans / Equitable Gas	SW Pennsylvania / WV Marcellus Basin	−$0.25 to −$2.00	−$0.50 to −$3.00	Trades at a persistent discount to Henry Hub because Appalachian (Marcellus/Utica) production regularly exceeds local takeaway capacity. A generator or data center with physical access to this point has a structural fuel cost advantage over those buying at constrained Northeast delivery points. The challenge is securing firm transport capacity out of the Appalachian basin to where the gas is needed.
Waha (Permian Basin) Often at or Below Zero	Various (El Paso, Permian Basin pipelines)	Permian Basin, West Texas	−$1.00 to −$5.00+	−$0.50 to −$3.00	Shown for comparative context. Waha traded negative on most trading days in early 2026 as Permian production exceeded takeaway infrastructure. A Northeast project cannot access Waha economics without the pipeline capacity to move gas east — but this hub illustrates how dramatically basis varies across the country and why delivery-point basis risk must be explicitly addressed in every fuel supply agreement.

These ranges are illustrative. They do not represent a specific lookback period, percentile, daily vs. monthly basis, or executable forward market quote. For firm supply structuring with basis hedging at your specific delivery point, contact Digby Ferrara at Aggressive Energy. Data sources: ICE, published pipeline market data, historical broker market references. Last reviewed: August 2026.

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