Montour’s Average Congestion Discount Nearly Doubled

PPL’s proposed Montour grid upgrade covers 29.3 miles of an existing 230-kV corridor in Pennsylvania. On September 24, DOE selected it for up to $71.5 million in federal support. The work would replace conductors and demonstrate fiber-based sensing along the corridor.

At PJM’s Montour 230-kV load node, the average real-time congestion component fell from −$8.75/MWh to −$16.84/MWh between January–September 2025 and the same dates in 2026. The average local discount nearly doubled while the total electricity price rose. It deepened in every monthly comparison, and the increase survives removal of extreme hours.

The price record measures Montour’s local exposure. Identifying how much of it PPL’s proposed upgrade could change requires a study of the specific constraints the corridor would relieve.

Ask the Grid compared 6,528 settled hourly real-time prices per year, from January 1 through September 29 in UTC, with no missing price or congestion observations. Montour’s mean total price rose from $34.83 to $45.87/MWh, an increase of 32%. Its mean congestion component moved in the opposite direction.

PJM’s nodal price combines system energy, congestion and losses. A negative congestion component lowers the local price when system energy and losses are held constant. A location can therefore become more heavily discounted and still pay more for electricity overall. Reading only the total-price chart would miss the growing local separation; reading only the congestion component would miss the higher total price.

Reducing a negative congestion component’s magnitude would, with system energy and losses held constant, raise the local nodal price. A move from −$16 to −$8/MWh would add $8/MWh to that price.

Each of the nine monthly mean congestion components was more negative in 2026 than in 2025. September’s discount rose from $15.76 to $31.75/MWh through the 29th. February moved from $5.49 to $20.12/MWh. June’s change was smaller, from $13.27 to $15.36/MWh, but it pointed in the same direction.

A separate check at PJM’s Susquehanna 500-kV node found the same direction in all nine monthly comparisons. Its period mean congestion component fell from −$8.43 to −$16.01/MWh. Two locations establish a broader observation than Montour alone; they still do not identify the transmission facility responsible.

At Montour, hours with an absolute congestion component above $100/MWh increased from 40 to 248—from 0.6% to 3.8% of the matched record. Those extreme hours pull the average well away from the typical hour: the median discount rose from $3.15 to $4.25/MWh, much less than the mean.

Removing the extreme hours reduces the increase in the mean discount from 92% to 34%. The remaining averages are $7.99/MWh in 2025 and $10.72/MWh in 2026. The change is smaller, but it remains.

September 17, when PJM called emergency demand response in parts of its footprint, is another useful check. Remove that Eastern-Time day from 2026 and the average congestion discount is still $16.59/MWh, close to the unfiltered $16.84. The deeper discount extends beyond that episode.

PPL’s selected application combines advanced conductors with a fiber-based sensing demonstration. The proposed work concerns existing transmission equipment; it is not a new generating plant. PPL said it would negotiate the award terms with DOE over the coming months, so selection precedes a finalized funding agreement.

For an offtaker exposed to real-time prices at this node, total nodal LMP is the relevant wholesale energy-price measure. Procurement costs also depend on consumption timing, day-ahead positions, contracts and other charges, as PJM’s billing guide explains.

For a generator or a hedge settled against a hub price, local congestion is one part of the exposure. The full hub-to-node price difference requires comparing both settlement locations’ congestion and loss components in the same market and interval. Project benefits require identifying the constraints the rebuilt equipment changes and testing dispatch under comparable conditions.

Montour is one of 31 selected SPARK applications. Ask the Grid reconciled their federal requests to $1.893 billion, against $5.252 billion in total project values. Two Eastern–Western interconnection projects account for $500 million, or 26.4%, of the federal requests.

The Colorado-to-Texas intertie modernization proposal and Oklahoma’s Three Corners Connector each request $250 million. Colorado proposes modernizing an existing interconnection; Three Corners proposes a new connection between SPP in Oklahoma and the Western Interconnection in Colorado. The Texas geography in the Colorado project’s name concerns the Eastern–Western seam, not an assumed connection to ERCOT.

Their operating test differs from Montour’s. An interconnection project adds or modernizes exchange between separate electrical systems; a regional corridor changes delivery within a system. The Montana seam analysis measured how prices on opposite sides can remain out of step. Neither that pattern nor Montour’s discount can be multiplied by a project’s MW rating to obtain savings: new transfer capability changes the prices and flows against which it is evaluated.

PPL’s negotiations with DOE will establish the final award terms. For readers evaluating the Montour investment, the next useful evidence is the finalized equipment scope, commissioning schedule and study of the constraints it is intended to relieve.

The operating baseline is already measurable: higher total prices, deeper average congestion discounts, more extreme hours and the same direction of change across nine months. Once the work enters service, those are comparisons to repeat under matched operating conditions. The grant amount alone cannot establish whether local price exposure improves.

Funding figures are calculated from the DOE selected-applications document, counting each of its 31 applications once. Selection and award timing come from the DOE program page. PPL’s project scope and pending negotiations come from its September 24 release.

Price calculations use PJM’s settled hourly real-time series at Montour 230-kV load node 49130, with equal UTC windows and no missing price or congestion observations. A check at Susquehanna 500-kV node 52467 shows the same direction. PJM labels the latter EHV; Ask the Grid classifies it as a bus node. Averages are simple hourly means, not load-weighted prices or settlement revenues. Project descriptions and figures are current to September 30, 2026.