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. Air emissions from power generation in the region have dropped in the past decade thanks in part to the use of cleaner-burning and more efficient fuels such as natural gas.
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 substantially lower air emissions, from sulfur dioxide to carbon dioxide. Energy-related carbon dioxide (CO2) emissions in 2012 were the lowest in the United States since 1994, at 5.3 billion metric tons of CO2. One of the central reasons has been the decline in coal-fired electric generation and the rise of natural gas for power generation, resulting in lower carbon emissions. In 2013, after years of decline, U.S. carbon emissions rose, as higher natural gas prices resulted in greater coal-burning by power plants. The U.S. EPA in mid-2014 introduced its proposed "Clean Power Plan" regulation. When implemented, this regulation is expected to lead to retirements of older and dirties power plants, to be replaced by by newer and more efficient plants, such as natural gas and renewables.
At the regional level, the same dynamic is in play. In New York State, from 2000 to 2014, NY ISO reports that emissions rates from the power sector dropped by 39% for CO2, 78% for NOx, and 94% for SO2. ISO-NE reports that from 2001 to 2013, total emissions from power plants in New England dropped by 91% for sulfur dioxide (SO2), 66% for nitrogen oxides (NOx), and 23% for CO2.
This is good news for the environment.
Gas Seen as Leading 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 wind power and other renewables.
Source: U.S. EIA, Mar. 2015. Metric tons.
Gas plants today remain the leading fuel type for new proposed power generation capacity in the generator queues in New Jersey, New York and New England. As the fossil fuel with the lowest carbon content, and with an outlook of abundant North American (and global) supplies, gas appears well-positioned as a reliable, cost-effective, environmentally responsible option.
As one example of the increasing recent role of gas in power generation, and its potential for growth, The New York Independent System Operator (NYISO) in its June 2015 report entitled "Power Trends 2015," noted:
To support such growth, additional pipeline capacity is needed. Infrastructure projects are under construction in NY and NJ, and several are proposed in New England. The long-standing inability of the power market to invest in pipeline capacity, however, especially in New England, remains a market (and reliability) challenge.
- "Power projects using natural gas and dual-fuel power plants that can run on gas and/or oil account for 56 percent of New York's generating capacity."
- "More than 70 percent of all proposed generating capacity in New York would use natural gas (gas-only and dual-fueled gas/oil units)."
|Chart: U.S. EIA, 11-13
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.
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 of the summer and especially the winter.
The Northeast spot price volatility reflects delivery constraints during high-demand periods of intense hot or cold 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 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. As the U.S. FERC observed in March 2015: "Natural gas remained a major driver of electricity prices, with regional prices reflecting, in part, variations in natural gas prices."
Recent winters resulted in high power prices in the region, most especially in the "polar vortex" winter of 2013-14, when regional natural gas points yielded a daily spot price at historic levels - from $80 to $120 per MMBtu on several occasions. The regional economic impact of high electric prices was summarized well by ISO-NE: "For the three months of winter 2013/2014 (December, January and February) the wholesale cost of power totaled about $5 billion in New England. By comparison, for the entire 12 months of 2012, when natural gas prices were at record lows, the wholesale cost of power totaled $5.2 billion, with winter 2011/2012 making up $1.2 billion of the total. The following winter, 2012/2013, which included a January cold snap and Winter Storm Nemo, totaled $2.9 billion."
The winter of 2014-15, by contrast, saw reduced wholesale power prices despite extended cold weather in Jan./Feb. 2015 due to a number of factors, including lower gas commodity prices, high gas production levels, more LNG imports, and use of alternate fuels for power generation, including coal and oil. Electric customers in the region nevertheless saw high retail electric bills, owing in great part to the lag from the high-cost previous winter, and the impact of regional energy system delivery constraints.
Additional pipeline capacity into the region would help to alleviate constraints and mitigate the regional price volatility.
The regional power generation fleet in the region has become highly reliant on natural gas and may well become more so. There are however several unresolved power market issues that continue to challenge the market.
A central challenge is that - especially in New England - most power generators do not contract for firm gas pipeline capacity under their unilateral control and instead rely on "if and as available" gas non-firm capacity, or, in some cases, capacity held by third parties. Pipeline capacity has routinely been added to meet the needs of gas customers who desire firm service and are willing to execute firm contracts for such service.
The majority of gas-fired power generators in New England opt for non-firm gas transportation services. The generators have long observed that the electric market does not provide the proper incentives to enable them to contract for firm transportation. NGA has encouraged the development of solutions to this power market dilemma, which causes uncertainty for the entire regional energy market.
(Also, as many generators are more reliant on interruptible capacity it is extremely critical that parties comply with pipeline operating rules, as well as the pipeline's tariff-required gas scheduling rules, so that system integrity is maintained to ensure that those customers that do contract for firm capacity receive that service.)
The U.S. Federal Energy Regulatory Commission (FERC) initiated in 2012 a comprehensive proceeding on gas and electric market coordination. The FERC issued a final order on this topic in April 2015. The Final Rule declined to adopt the NOPR proposal to move the 9 a.m. CCT start of the gas day to 4 a.m. CCT. The Commission concluded that, while certain efficiencies could be achieved through a better alignment of the natural gas and electric operating days, the record in this proceeding did not justify changing the start time for the nationwide natural gas day. The Final Rule recognizes that several regional efforts continue to address the misalignment between the gas day and the regional electric days.
The New England region continues to be seen as the area facing the most immediate coordination challenges owing to the "interruptible" nature of most of its natural gas-fired power generation capacity. Discussions and studies have been underway on this topic for well over a decade. In February 2014, the New England Natural Gas Industry, representing pipelines, LNG importers, LDCs, and NGA, filed joint comments with FERC on a New England electric market issue. In that filing, the gas participants noted this key point: "Many if not all of the problems with gas-fired electric generation units... [cited by the electric market] are actually problems of gas-fired units that lack firm transportation, not problems of gas-fired generation per se. If gas-fired generation seems like "just-in-time" delivery, it is because generators are contracting for just-in-time delivery or relying on just-in-time delivery from a spot capacity release market. Natural gas can play a valuable long-term role if parties contract for firm transportation and develop the requisite pipeline infrastructure that comes along with that firm contracting."
In 2014, a proposal was made by the New England Governors to the regional electric grid operator to try to resolve this and other energy infrastructure issues. The New England Governors announced that they were seeking to develop transmission infrastructure that can deliver clean energy into the region's electric system and expand pipeline capacity to bring more natural gas to New England. As the region's power generation becomes increasingly reliant on natural gas, noted the governors, infrastructure investments will help ensure adequate and competitively priced supplies of gas and clean energy from diverse sources while lowering the cost of electricity for residents and businesses. This proposed initiative, which remains under discussion, represents an opportunity for New England to resolve its decade-long irresolution over gas power plants and insufficient pipeline capacity. The Governors continue to assess together how best to achieve "regional energy solutions" - including convening a forum on this topic in Hartford in spring 2015.
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
FERC Proceeding on Natural Gas-Electric Coordination
NESCOE Web Page on New England Natural Gas-Electric Discussion Group
NGA Background Paper: "Gas-Electric Market Challenges in New England, April 2012" [pdf]
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)