Natural gas is seen as the bridge to solving the intermittency of supply issues that renewable energy faces as it contends to take an ever-larger share of the generation load. But is there enough infrastructure available to get gas to peaking and other plants when wind and solar resources inevitably back off? And, if there aren’t who pays for the new supply lines?

An international consultancy started thinking about those questions and wrote a white paper that presents different scenarios related to the topic.

ICF International wrote “Integrating Variable Renewable Electric Power Generators and the Natural Gas Infrastructure,” to explore the implications of increased renewable penetration.

“There really hasn’t been a lot of public dialogue about this,” Steve Fine, one of the paper’s authors told this reporter.

ICF said it finds that natural gas will play a significant role in supporting the continued expansion of renewable generation, which will have impacts in the form of operational changes, infrastructure requirements, and cost recovery issues.

New facilities may need to be constructed at some locations to guarantee reliable on-demand gas service to support changing generator needs resulting from increased renewable generation, the firm adds.

“As we continue to roll out more renewables onto the power grid, we’re going to have the need for additional fast ramping capability,” Fine said. “And we have to think about who pays for the gas service that we need for those new generators.”

For example, if a new gas line is needed to serve plants that back up renewables but also it is used transport gas for home or commercial heating, who pays how much, or what share of the recovery for the owner? That isn’t a question that has been addressed yet, to the report authors’ knowledge.

Scenarios

ICF described three hypothetical power industry scenarios that illustrate the potential impacts of variable renewable generation on natural gas-fired power plants and gas infrastructure. Scenario I addresses long-term utility planning, in which utilities plan to meet 800 MW of demand growth with gas-fired capacity, but changing circumstances result in 800 MW of wind additions. 

Scenario II looks at utility Renewable Portfolio Standard (RPS) planning, in which utilities add 800 MW of wind to meet RPS requirements in the absence of forecast electric load growth.

Scenario III differs from the first two scenarios in that the integration is not handled in the context of a utility system with supply and demand interactions. Rather, the renewable producers─because of contractual, regulatory, and/or system conditions─must arrange to eliminate the deviation in wind output from forecasted output within a day or less.

The question could be particularly acute on the coasts.

In California, an aggressive 33 percent renewable portfolio standard could rely on increased gas generation to augment wind and solar plants.

In New England, already at the end of a long gas pipe, heavy reliance on natural gas for electricity and winter heating often stretches available supplies, even while RPS targets are low.

Fortunately, there are a few years to work this out. But it’s something regulators will need to address eventually.

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