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With More Wind Energy, PJM Could Save Customers $7 Billion per Year

The PJM Interconnection could save its customers $6.9 billion if it more than doubled the amount of wind energy it currently plans to build. This is according to a study by Americans for a Clean Energy Grid and Synapse Energy Economics.

By the end of 2012, about 3.4 percent of PJM's total installed capacity was generated from wind. Over the next 13 years, with the advent of renewable portfolio standards, states within the PJM system will expand their wind energy capacity to 11 percent of their total installed capacity.

Bob Fagan, an economist with Synapse Energy Economics who worked on the report, said in a conference call that the study allowed for a significant build-out of transmission to allow this proposed new wind energy development to flow throughout the grid.

"Most of the wind resource is in the eastern portion of PJM," Fagan said. "A significant transmission build-out will be required in the western part of PJM to bring this electricity to market."

A large portion of the consumer savings come in by phasing out fossil fuel-fired generation, particularly coal power, which must buy their fuel, and replacing it with wind energy, which does not. Even with the capital costs of building wind turbines, the study shows the benefits more than balance out in favor of wind energy, he said.

The study disputes the notion that wind energy is too expensive to be used widely, said Joe Kelliher, executive vice president of NextEra Energy and former FERC Chairman under former President George W. Bush.

"This is a very important study and it challenges the common wisdom about wind energy, particularly with regard to the idea that wind is expensive," Kelliher said. "There's a common wisdom that wind is less reliable than other forms, but this study shows that wind could actually create a more reliable system for PJM."

In response to the case presented by the study, he said, state and federal-level energy policy needs to provide support to a variety of power generation technologies and not only the ones that appear to be the most cost effective at the moment.

"Both political parties embrace a common slogan of being 'all of the above,' but to me that means that public policy must encourage fuel diversity instead of placing all of our bets on natural gas," he said.

Grid policy, as determined by independent system operators and other regional, state and federal regulators, need to take changing economics into consideration, he said.

"Like it or not, U.S. electricity supply is changing. Not everyone likes that. The driver is state policy. National policy is merely there to support state-level policy. Our electricity supply is sometimes seen as deregulated, but in reality it is regulated. Grid policy is important," he said.

James Hoecker, counsel and advisor to WIRES and another former FERC Chairman said the study is quite conservative in its scope.

"The principal finding from my point of view is if wind installations were built at twice the current level required by state RPSs, and transmission were built out in such a way as described in the study, customers would see benefits on the order of billions." Hoecker said. "The build out of transmission would be quite economical, and the study reinforces that a high-voltage transmission grid as an enabler of new technology."

Under the study's model, about 5,800 MW in additional transmission capacity would need to be built within PJM Interconnection states of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia and West Virginia.

An improved transmission grid provides a wide variety of benefits, many of which are quantifiable, including enhanced reliability, market competition, market liquidity, storm hardening and operational flexibility, he said.

"Transmission, is in my view, the most important thing that none of us think about, so I appreciate that this study shows us the benefit of a stronger grid," he said.

"The grid has to be flexible enough to handle a variety of different energy futures, and this study shows us what one of those would look like."


The study is based on an extensive assumption set, including load, resource mix, transmission system configuration, fuel prices, and operational constraints. The model output includes generation by resource type, marginal prices, and transmission flows for hourly periods of the year 2026.

Synapse Energy Economics used a capital investment spreadsheet tool to track projected overall costs associated with generation, transmission and demand response in each of the cases. It also tracked additional offshore wind capital costs for a sensitivity case.

Using the production cost modeling and capital investment accounting tool, Synapse computed production cost and energy market impacts from the wind cases, relative to the base case; and determined the incremental revenue requirements needed to pay for the increased capital investment of the wind cases. Researchers then estimated the net impacts in 2026 of the alternative wind cases, relative to a base case using less wind (and more natural gas).

An additional production cost simulation run was executed to test the sensitivity of the results to increased levels of offshore wind. Additional model runs were conducted to help determine how the power system responds to different sets of resource addition or transmission addition assumptions.


Production cost efficiency gains from improved average wind resource performance (from a portion of wind resources sourced from the higher-performing MISO region) are roughly offset by the increased transmission costs to deliver those resources to PJM.

PJM carbon emissions in the wind scenarios are 14 percent lower than base case emissions. Sulfur dioxide emissions are 6 percent lower and nitrogen oxide emissions are 10 percent lower than base case levels. Base case levels include the effect associated with retiring roughly 58 GW of coal-fired plants in PJM.

Load-weighted average annual energy market prices in the PJM zones are lower under the wind cases. Average annual energy prices differences for the PJM zones in aggregate are roughly $1.74/MWh lower for the wind cases, relative to base case prices. The price differences are greatest in the non-summer months, when wind output is highest, load is lowest and supply margins are greatest.

The wind cases see more summer peak period energy from "peaking" fossil resources, and less summer peak period energy from base-loaded and intermediate-loaded fossil resources, relative to the base case. This is a consequence of using economically optimal unit commitment and dispatch while respecting fossil-fuel plant operating constraints and the time profiles of wind output.

If all production cost efficiency gains flow to consumers based on consumers paying the annual revenue requirements for incremental wind installed in the PJM region, then consumers are clearly much better off economically with increased wind resources, relative to a base case with less wind and more gas.

Increasing the amount of "PJM wind" that is sourced from further west regions, in this analysis modeled as MISO-sourced wind, leads to incrementally greater wind performance and higher production cost efficiencies. These savings are roughly offset by increased transmission costs associated with delivering more of this wind to PJM via HVDC lines, the proxy delivery method used in this analysis.

Adding this amount of wind energy would benefit the environment by reducing PJM carbon emissions by 14 percent, lower sulfur dioxide emissions by 6 percent, and nitrogen oxide emissions by 10 percent compared to the baseline.

This article was originally published on Electric Light & Power and was republished with permission.

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