In the aftermath of last winter’s polar vortex, and the consequent spike in natural gas prices, some independent system operators (ISO) are reconsidering plans to retire coal-fired generators that proved critical to maintaining system reliability, according to a report by ScottMadden Inc.

In a 42-page report, ScottMadden, a management consulting firm based in Raleigh, NC, said last winter’s polar vortex impacted gas and electricity markets in the upper Midwest, the Northeast and the Southeast for several days. A loss of power generation in some regions, especially in the Mid-Atlantic, pushed gas pipeline capacity to its limits and almost led to emergency conditions.

“Pipeline capacity was an issue in New England, even without significant gas burn for power generation. For example, at five key gas delivery points in the North, utilization was more than 92% on Jan. 22-23,” the report said, adding that many outages were not fuel-related. “In some cases, combustion turbines would not start.”

Fuel diversity proved critical for utilities to weather the storm, but ScottMadden said it found available gas capacity in the Mid-Atlantic, New England and the Midwest “was far less than ‘advertised’ capability.” The researchers also found that in some cases oil-fired units were dispatched before gas-fired generators, and coal and nuclear sources of energy also proved essential.

“[The] mismatch between gas and power days led generators to assume gas price risk in advance of dispatch, even as gas prices soared to $100/MMBtu,” the report said.

ScottMadden said it was unclear if ISOs will be ready for the next intense winter season. To illustrate the point, the firm said PJM sought demand response (DR) of more than 2,000 MW on three separate days during last season’s polar vortex.

“It is unclear how system reliability might have been had that DR not come through,” the report said. “A significant amount of coal and oil capacity is slated for retirement beginning this coming winter. After last winter’s experience, further consideration is being given by ISOs of which units may need to be maintained, at least for an interim period, for reliability.”

The report said it was unclear what impact tougher federal regulations on emissions could have on ISOs considering holding onto coal-fired plants a little longer.

In April, the Supreme Court upheld a rule adopted by the Environmental Protection Agency (EPA) that limits smokestack emissions in 28 central and eastern states that affect air quality of other states located downwind (see Daily GPI, April 29). Meanwhile, the EPA’s mercury and air toxics standards (MATS) are set to take effect in April 2015 (see Daily GPI, March 18).

“[The] new CO2 [carbon dioxide] regulations could scramble the calculus of planned investment in back-end air quality control systems, adding to already costly plans for installations and upgrades and leading owners to the conclusion that their coal generators are simply too expensive to operate,” the report said. “Or, in lieu of the fact that the investments have already been made to comply with MATS, coal generators could stick it out, particularly if it looks like implementation will be delayed by litigation for years.”

ScottMadden also analyzed natural gas midstream infrastructure and based its findings on a report released in March by the Interstate Natural Gas Association of America (INGAA). In that report, INGAA concluded that nearly $641 billion would need to be invested in North American midstream infrastructure over the next 20 years to keep pace with production (see Daily GPI, March 18).

But the firm cautioned that building that infrastructure “is harder than it sounds.”

“Siting in areas like the northeastern U.S. — where much of the unconventional gas supply is coming from — is challenging,” the report said. “NIMBY and environmentalist objections slow development, as environmental groups oppose gas infrastructure as prolonging fossil fuel dependence and encouraging [hydraulic fracturing]. Environmental reviews and permitting also create additional time and expense as FERC [Federal Energy Regulatory Commission] permitting and planning can take three or four years.”

ScottMadden added that INGAA’s calculation that new pipelines could cost $3.7 million per mile, some industry experts believe it could cost as much as $5.5 million per mile, especially in the Northeast.

“Moreover, new pipeline is not always the answer,” the report said. “Some long-haul pipelines are under-capacity as supplies are redirected to other locations. Pipeline companies can also leverage line reversals (backhaul), conversions to transport different products — e.g., natural gas liquids [NGL] — and abandonment of existing lines.”

The report added that many existing transmission lines in the U.S. are at least 40 years old and will also need to be replaced, simultaneous with the need to build new pipelines.

“Finally, dry gas prices must recover enough to justify the transport of commodity to demand centers, especially for dry plays that do not have NGLs to help fund production,” the report said.