Gas & Power Generation

Natural gas is one of the key fuel inputs for electric power generation. New technology, particularly combined-cycle technology, has made the natural gas power plant the energy system of choice in recent years-and gas remains a leading fuel of choice for future power plants as well.

Gas Plant Advantages: Lower Emissions, Higher Efficiency

Power generation is one of the leading natural gas consuming sectors in the Northeast region. Shown here is a natural gas combined-cycle power plant (674 MWs) in Salem, MA that went online in mid-2018.

The comparative advantages of natural gas power generation include higher efficiency, lower heat rate, shorter construction lead times, and reduced air pollutant emissions compared to other fossil fuels.

The rise in natural gas use in power generation is leading to lower air emissions, from sulfur dioxide to carbon dioxide. In November 2020, U.S. EIA noted: "U.S. electric power sector emissions have fallen 33% from their peak in 2007 because less electricity has been generated from coal and more electricity has been generated from natural gas (which emits less CO2 when combusted) and non-carbon sources."

At the regional level, the same dynamic is in play. In New York State over the last 20 years (from 2000-2019), NY ISO reports that emissions rates from the power sector dropped by 55% for CO2, 92% for NOx, and 99% for SO2. ISO-NE reports that since 2001, emissions from power plants in New England dropped by 99% for sulfur dioxide (SO2), 78% for nitrogen oxides (NOx), and 42% for CO2.

Chart: NY ISO, May 2020

PJM emissions data indicates a significant drop in SO2, NOx and CO2 for its entire region, which includes declining trends for all three pollutants in both New Jersey and Pennsylvania.

Natural gas generation also increases average plant efficiency. As noted by EIA in July 2020: "In recent decades, the U.S. electric power grid's fuel mix has shifted from mostly coal to a more diverse selection of fuels, including natural gas and renewable energy. In particular, the shift toward newer, more efficient natural gas-fired power plants with combined-cycle generators has resulted in an increase in the average efficiency of fossil fuel-fired electric power plants and in lower levels of overall conversion losses."

Gas Seen as Central Power Sector Input in Coming Decades

Natural gas is positioned to be among the leading fuels for electric power generation in the next decade (and beyond), along with renewables. Gas is also a key fuel input for new technology options like fuel cells, combined heat and power, and distributed generation.

Natural gas is also seen as the key "back-up fuel" to offset the variability and intermittency of some other resources. As the U.S. EIA noted in August 2020: "Natural gas is a key power generation resource because it has the flexibility to supply electricity at any time, including at times of peak demand. In contrast, some renewable energy technologies and nuclear power plants may be nondispatchable and not able to adjust their generation to meet load. For example, nuclear power plants may already be running at or near maximum capacity and may be unable to respond to shifts in load."

Some examples of recently-added natural gas generation capacity include the 805 MW CPV Towantic plant in Oxford, CT (June 2018); the 674 MW Salem Harbor station in Salem, MA (June 2018); the 680-MW CPV Valley Energy Center in Wawayanda, NY (October 2018); the 485 MW PSEG Bridgeport Harbor Station Unit #5 in Bridgeport, CT (June 2019); the 333 MW single-cycle unit added to NRG's Canal 3 Generating Station in Sandwich, MA (June 2019); the 1,050 MW CPV Fairview Energy Center in Jackson Township, PA (December 2019); and the 1,100 MW Cricket Valley Energy Center in Dover, NY (April 2020).

The New York Independent System Operator (NYISO) noted in its June 2020 report "Power Trends 2020" that the power grid is in transition. Natural gas currently plays a major role in the system's energy mix. Indeed, the portion of New York's generating capability from natural gas and dual-fuel facilities grew from 47% in 2000 to 62% in 2020.

In its 2019 "Regional System Plan," released in October 2019, ISO-NE stated that "Natural-gas-fired generation's proportion of the system capacity mix is expected to grow from 49.5% in 2019 to approximately 54.4% by 2023 but decrease to 48.6% by 2028. Further retirements of coal and oil generators are expected over the next 10 years due to generally low natural gas prices, renewable energy additions, and pending environmental regulations. The Pilgrim nuclear plant in Massachusetts retired in 2019. Although renewable resources are anticipated to grow over the long term, the ISO expects natural gas resources to continue to set the marginal price for wholesale electricity in most hours over the planning horizon." Thus, for the next decade natural gas will continue to represent essentially 50% of the regional power mix.

Photo: Exelon Generation

In its 2020 state profiles released in February 2021, PJM reports that natural gas represents approximately 67% of total installed capacity in New Jersey, and 22% of new interconnection requests in the state (as of 12-31-20). For Pennsylvania, natural gas represents 44% of total installed capacity statewide, and 32% of new interconnection requests. PJM notes in its "2020 Regional Transmission Expansion Plan," released in early 2021, that its "interconnection process is showing trends of increasing renewable generation." At the same time, one of the other key trends in its "changing capacity mix" is "new generating plants powered by Marcellus and Utica shale natural gas."

In April 2020, the U.S. EIA reported that the three leading sources of new electric generating capacity added in the U.S. in 2019 were wind, natural gas and solar. EIA notes:

  • "Low natural gas prices, a rapid decline in construction costs for solar and wind systems, and an increase in renewable portfolio standard requirements in many states have led to more generation from natural gas-fired and renewable resources in many regions."
  • "In the Northeast region, access to abundant natural gas supply from the Marcellus and Utica shale plays in Pennsylvania and Ohio has led to increases in natural gas-fired power plant capacity."

Natural Gas Impact on Electricity Prices

The increase in U.S. domestic production of natural gas engendered a much lower commodity price position for the fuel in recent years. This is good news for consumers of natural gas at all end-uses, including power plants.

The impact of natural gas prices on power markets is summarized well in these two quotes from ISO New England:

    "Wholesale electricity prices rise and fall in real time based primarily on fuel prices (which are generally the biggest cost for power plants), demand for power, and transmission system conditions."

    "With about 50% of the region's generators able to run on natural gas, the price of this single fuel sets the energy market price most of the time. The high efficiency of natural-gas-fired generators and the generally low cost of nearby domestic shale gas (which emerged as a resource in 2008) are largely responsible for the significant decrease in the average annual price of New England's wholesale electricity over the past 10 years. After plummeting almost 50% a decade ago, average wholesale energy prices have remained consistently low since then. Lower wholesale prices translate into lower power-supply charges for consumers."

However, while the regional price can be quite low at certain months of the year, the delivery price of natural gas to Northeast markets can be quite volatile and high during strong-demand periods, especially in the winter.

The Northeast spot price volatility reflects delivery constraints during high-demand periods of intense cold (or even hot) weather. Natural gas utility customers are generally protected from the daily impact of spot prices, thanks to long-term contracts and storage resources held by local gas distribution companies. On the other hand, the power market in the region operates with high levels of interruptible gas capacity and is thus subject to spot market fluctuations, and that in turn impacts electricity customers.

Even with variations in winter weather, natural gas spot price fluctuations can have a real impact on electricity prices where natural gas sets the margin (as in most of the Northeast).

In March 2017, the U.S. EIA observed: "Historically, both the Boston and New York natural gas markets have experienced winter price spikes because of pipeline constraints during periods of peak demand. Natural gas pipeline expansion projects that were completed in recent years may have reduced, but did not eliminate, sharp price increases with anticipated cold weather."

The Northeast region has experienced periods of high gas and power spot market price volatility in the U.S. over several recent winters - in 2013/14, 2014/15, and 2017/18. In February 2021, U.S. EIA noted: "Natural gas prices in the United States tend to spike in winter months, particularly in New England, when natural gas supply becomes constrained during cold spells, resulting in correspondingly higher prices at the Algonquin Citygate near Boston, Massachusetts." It remains an ongoing challenge.

Market Challenges

There are several unresolved power market issues that continue to challenge the market.

As of early 2021, natural gas has become the essential energy source for power generation in the Northeast region. In recent years, as noted above, there has been a steady retirement of many coal, oil and even nuclear units in the region; their reasons for retirement range from age to lower efficiency to safety concerns to the inability to compete with low natural gas prices. Meanwhile, the increased reliance on natural gas provides some challenges for the electric grid operators, who now have fewer options in their supply resource portfolios. The states in the region want "clean energy" projects going forward but the arrival of offshore wind and/or long-range electric transmission is still three to five years away. Natural gas provides a reliable "glide path" in the meantime for the power grid, but the increasing difficulty in adding new gas supply infrastructure can mean constrained supplies at peak periods, particularly on cold winter days.

As the region continues to rely on natural gas for baseload generation, and for providing support for more intermittent resources like renewables, the lack of sufficient pipeline infrastructure to meet power sector needs remains an unresolved issue - most notably in New England. Most power generators in New England do not contract for firm gas pipeline capacity and instead rely on "if and as available gas" non-firm capacity, or, in some cases, capacity held by third parties. Pipeline capacity is added to meet the needs of gas customers who desire and are willing to execute contracts for such firm service. This reliance of the power system on non-firm gas transportation capacity for the majority of its gas units has proven very challenging in several recent winters, including the winter of 2017/18. The FERC noted in its pre-winter energy market assessment in November 2020:

"Because the [New England] region's supplying pipeline capacity is somewhat limited, consumers of natural gas tend to compete for supply when demand induced by cold weather soars. Due to the high winter demand and limited pipeline capacity, winter natural gas prices often peak during the coldest days of the year."

Looking ahead, public policy and legislative initiatives in the region are increasingly prioritizing non-fossil fuel units for new generation and encouraging electric utilities to contract for substantial amounts of offshore wind and imports of Canadian hydro. (The Northeast states alone are looking to add over 23 GW of offshore wind capacity in the next decade-and-a-half.) Solar continues to make inroads behind-the-meter as its technology costs decline.

Fuel security, resource adequacy and grid resilience remain key topics for the RTOs. At the same time, some state government leaders are expressing concern that the power markets are not facilitating the clean energy transition on a fast-enough timetable. In October 2020, for example, five of the six New England governors called for a "modernized grid."

All these issues are complex: the future of nuclear, the uncertainty over increasing pipeline infrastructure in areas like the Northeast, the balancing of intermittent renewable resources on the system, the valuing of capacity in power markets, onshore connectivity, solar acreage, and affordability, among others. The debate continues into 2021 and beyond as the Northeast region's power markets evolve to reflect the changing policy and regulatory environment.

Electric & Gas Industry Coordination

The natural gas and electric system operators in the Northeast continue to increase communications and coordination. NGA and ISO New England, for instance, jointly administer an Electric & Gas Operations Committee (EGOC) to increase understanding and information exchanges (on publicly-available information). The EGOC includes the NY ISO and PJM as well as other stakeholders.

NGA also updates the electric grid operators regularly regarding the coordinating work of NGA's Gas Supply Task Force.

With natural gas remaining a significant fuel going forward for electric generation, coordination efforts such as these - both regionally and nationally - are to be encouraged.

For Further Information


Northeast interstate pipelines' electronic bulletin boards (EBBs)

ISO New England

New York ISO


Northeast Power Coordinating Council (NPCC)

North American Electric Reliability Council (NERC)

Interstate Natural Gas Association of America (INGAA)

North American Energy Standards Board (NAESB)