The snowstorm that shut down parts of the East Coast last month had a predictable impact on electricity markets in the region, spiking power prices as pipe-constrained areas saw gas demand rise. In a region where gas sets the marginal cost of power, extreme weather tends to show up on the customer's bottom line.

There is debate over how much more pipeline capacity the Northeast needs for power generation — some environmentalists say the answer is none. But at the moment, the region relies on gas-fired generation and a cold day can send prices up.

Texas and California have very different scenarios playing out. In those states, influxes of subsidized renewable generation can often bring down energy market prices to levels where it puts pressure on baseload plants and even some gas generators. Particularly in Texas, that is leading to concerns over inefficient market signals and perhaps even reliability.

The two scenarios each reflect the need for a balanced portfolio, according to Navigant Director of Energy Gordon Pickering.

"Natural gas is a good support to renewables development," said Pickering. "Renewables will only be able to develop to a small portion of what they could be, if they don't work better with the gas industry."

In mid-April, a nor'easter dubbed Winter Storm Stella put 18 million residents on the East Coast under a blizzard warning, with states of emergency declared in New York, Pennsylvania, Maryland, New Jersey and Virginia. As is often the case, gas and power prices in the day-ahead markets moved in tandem, with higher gas demand spiking prices.

Ultimately the storm's impact was smaller than anticipated, despite knocking out power to close to a quarter million customers.

Particularly in the Northeast, "natural gas will set the market price for the forseeable future," said Pickering. "It's going to be sometime yet, before there is enough renewable capacity, if it ever gets there, to move the market."

Last year, both PJM Interconnection and ISO New England said opposition to new gas pipeline capacity is creating fuel procurement difficulties, especially in the colder months. And it has not been a good stretch for pipeline projects in the region.

Earlier this year, Spectra Energy informed federal regulators it would delay its proposed $3 billion Northeast Access pipeline. The company said the problem is not demand for the gas, but the need to "solidify the commercial foundation" of the project. Last year, the Massachusetts Supreme Judicial Court blocked regulators from approving contracts that would fund the line through a charge on electric bills.

Massachusetts Attorney General Maura Healey has also questioned the need for the pipeline, arguing the region's energy needs should be met with efficiency and demand response instead.

And just this month, the New York State Department of Environmental Conservation rejected National Fuel Gas' proposed Northern Access pipeline, a roughly-100 mile pipeline that would have moved gas from the Marcellus shale to markets in Western New York, the Midwest and Canada.

That decision drew a strong rebuke from National Fuel President and CEO Ronald Tanski, who pointed out that 60% of New York's generation is gas fired.

"We are highly concerned about the ability of utilities in the state to meet the future energy needs of their consumers and the businesses and industries that drive the state’s economy," Tanski​ wrote. "New York’s continued denial of permits for energy infrastructure projects is simply not sustainable, as it will have the effect of reducing New York’s energy reliability, lead to higher costs for consumers and be a limiting factor in the ability for industry to locate or expand in the state."

Price impacts are already being seen in New England. The grid operator for the region recently issued an analysis of the February wholesale power market, finding prices were 2.4% higher this year compared to last, averaging $28.05/MWh, in response to higher natural gas prices.

ISO-New England said natural gas prices were acctually 6.7% higher, but lower power demand helped keep power prices from rising more.

Renewables move California, Texas prices

It is the opposite scenario in Texas and California, where wind and solar are, respectively, disrupting the marketplace. 

Last month, NRG CEO Mauricio Gutierrez shocked the merchant sector when he called the independent power producer model "obsolete and unable to create value over the long term." His company owns a dozen coal, gas and nuclear plants in Texas, and generation revenues for that region dropped more than $90 million last year, primarily because of lower power prices in the state.

And last year, the La Paloma gas plant filed for bankruptcy in California, unable to recover its costs in the face of cheap solar energy. In Northern California, gas and power prices have been moving in opposite directions in recent weeks.

Pickering said the growing wind generation in Texas is pressuring gas-fired generation "that has been a mainstay of the system forever. And the same disruption is happening in California."

The Electric Reliability Council of Texas, the grid operator for most of the state, has more than 18 GW of nameplate wind resources — and could add 10 GW within three years. ERCOT has set several new records in the past year for wind generation and penetration. Just last week, the system hit 16,141 MW at about 9 p.m. on March 31. Wind accounted for almost 40% of total system load at the time.

There and in California, the influx of subsidized renewables is pushing down energy market prices, stoking fears that the markets may not produce sufficient returns to incentivize the building of new generation. California real-time prices routinely dipped into negative territory last month, a phenomenon seen as far back as 2015 in ERCOT. 

Growing wind penetration has led ERCOT officials to develop a new "reliability desk," with a goal of better predicting predict renewable generation as well as addressing its variability. But with thousands of megawatts of wind and solar in the queue, even ERCOT President Bill Magness says it is a "fair question" whether the market will retain incentives for new generation needed to meet demand in years to come. 

Export market could spell trouble for gas generators

For gas generators already under pressure, the situation is unlikely to improve in the near-term. Gas prices are widely expected to be higher this year, and the growing export market — both in the form of liquefied natural gas tanker exports, and pipeline exports to Mexico — could raise fuel prices for plants further in the coming years. 

Ultimately, Pickering said this will be the big story for gas generators in Texas. If renewables continue to push down the clearing price in energy markets, margins for gas plants could get even thinner. 

"While a lot of focus seems to be on the wind market and some of the disruption to gas generation, that is not the key driver in the Texas market," Pickering said. "The key driver is additional pipeline capacity being built out of the burgeoning gas supply regions in the Permian Basin."

The first two trains at the Sabine Pass export facility are now online, with a nameplate capacity of 1.4 Bcf/d. It is the first terminal to liquefy and export gas in the United States, but more are expected to follow — and the facility itself will ultimately expand to six trains.

A study commissioned by the Natural Gas Supply Association and completed by Energy Ventures Analysis concluded four other projects are under construction and by 2020 total U.S. LNG export capacity will reach 8.6 Bcf/d.

Once Permian pipeline capacity is complete, the Mexican market matures and LNG exports ramp up, Pickering said the price of gas for generators would likely remain strong. "That will be far more impactful on prices in Texas and that will translate into gas prices at the California border," he said.