September 2020, Vol. 247, No. 9
Features
Amid Challenges, Natural Gas Remains Growing Part of Energy Mix
By Danielle C. Roberts, Energy Correspondent
In July, Dominion Energy and Duke Energy announced the cancellation of the Atlantic Coast Pipeline. Earlier this year, Williams put both its Constitution Pipeline and Northeast Supply Enhancement on hold.
Yet, amid the latest anti-gas headlines, one fact has received far less attention: Much of the electricity we use now and into the future leans on natural gas. Natural gas still makes up 38% – and growing – of the energy mix for U.S. electric generation. According to S&P Global Market Intelligence, 120,498 MW of gas-fired capacity came online between 2008 and Aug. 1, 2019. Twenty percent of that was in 2018 and 2019 alone, and roughly 200 new gas plants have been proposed or are in development right now.
The low cost of gas, coupled with its environmentally friendly properties when compared with coal, continue to make gas power plants and the pipelines that supply them an attractive investment. And most Americans still want and support gas, for both those economic and environmental benefits, said Micheal Dunn, chief operating officer at Williams.
“Long-term demand for natural gas remains strong globally and in the United States,” he said. “[And] natural gas continues to be the largest and fastest growing piece – on an absolute basis – of the electric power generation mix.”
That growth will continue – at least up to a point.
Growth of Gas
Winding its way nearly 1,800 miles (2,900 km) from hot and dusty South Texas, around the Gulf of Mexico and up the East Coast to New York City, Williams’ Transco pipeline is the nation’s largest-volume gas transmission system, reaching markets in 12 states, including many major metropolitan areas.
Dunn sees the system as a lifeline in more ways than one – a vital part of the story that the natural gas value chain can tell to answer environmental challenges.
The pipeline passes near “83 coal-fired electric power generation plants, with approximately 90 gigawatts of capacity that natural gas can potentially displace,” he said. “We are working hard to promote the role natural gas plays in providing an immediate step toward a low-carbon future by displacing high-carbon fuels currently in use such as heating oil and coal.
“The near-term benefits of additional utilization of natural gas for power generation is real; for example, the United States has reduced CO2 emissions by more than 34% between 2005 and 2019 by increased utilization of natural gas and renewables for power generation by reducing coal consumption, with the bulk of the benefit coming from natural gas.”
Today, natural gas-fired power plants are generating about 12% more energy than they were at the same time in 2019, according to a U.S. Energy Information Administration (EIA) report in April. More reduced emissions are set to come in the near future. According to EIA, 5.8 GW of U.S. coal capacity is expected to be retired this year, with 11.4 GW of capacity at natural gas combined-cycle power plants planned to be added by the end of the year in regions such as the mid-Atlantic, Midwest, New York, Southeast and New England.
Despite having to pull back two Northeast projects within the last year, Williams will be a part of that growth, through pipeline expansion projects in Kansas, Oklahoma, Alabama, New Jersey, Pennsylvania and Virginia, among other locales. “We are still in a very active mode, currently executing $2.2 billion in gas transmission projects in addition to growth in our gathering and processing footprint as well as in the Gulf of Mexico,” said Dunn. “Looking ahead, we are evaluating another $11 billion in growth opportunities to transport gas for electric power generation, liquefied natural gas, industrial and local distribution companies.”
Duke Energy, likewise, has plans to retire five coal plants – two in Indiana and three in North Carolina – over the next four years, replacing them with cleaner natural gas generation. Other Duke coal plants have been retrofitted to burn natural gas, and some gas plants are being expanded to boost electric output.
According to its Sustainability Report 2019, the energy giant used coal/oil for 60% of its power generation in 2005. By 2019, that number had dropped to 26% and is expected to fall to 12% by 2030. Natural gas, on the other hand, which was 6% of the company’s generating mix in 2005, rose to 35% in 2019 and is expected to make up 41% by 2030.
Although Duke and its partner Dominion Energy recently announced the cancellation of the Atlantic Coast Pipeline (ACP) project due to legal uncertainties, Duke is still focused on serving the economic needs of rural eastern North Carolina, which should include additional gas power plants. “We would have needed a way to get that natural gas to those power plants. We thought that the ACP was the right solution,” said Neil Nissan, a Duke spokesperson. “Right now, we’re working on what other solutions we can provide to get natural gas into those areas,” which could include updating compressor stations or adding lateral pipe.
“All of those options are available … we’re going to be working on that now and probably through the end of the year,” he said. “Just because the pipeline project isn’t there doesn’t mean the need isn’t there. The need is still there, and the lack of gas infrastructure in general is really hindering the ability of businesses to grow but also for us to attract new businesses.”
New England Story
Thomas M. Kiley, president and CEO of the Northeast Gas Association, likes to tell this story. During an extreme cold spell of about 15 days between Christmas 2017 and early January 2018, New England’s power generation market burned more oil than it had in the entire previous two-year period.
“How’s that for the environment?” he said. “That’s just one illustration of what’s happening. On real cold days, you need power. A lot of it’s going to be natural gas. Where are you going to get the capacity to run it?”
Kiley said more than 1,300 MW of gas generation was added in Connecticut in 2018, more than 1,200 in Massachusetts in 2018, and about 1,800 MW in New York State in 2019. Still, much of New England’s natural gas capacity is tied up in firm contracts to LDCs, which, in turn, limits availability to power plants.
According to EIA, at the end of 2019, pipeline capacity into the region was 5,200 MMcf/d (147 MMcm/d), and much of that is taken up during peak demand winter days. Not only does that lead to utilization of more polluting fuels such as heating oil, but open markets for pipeline capacity can lead natural gas prices to skyrocket.
“During some of those cold periods, the consumer in the Northeast, including New England, pays billions of dollars more on their electric bill than they would have, had we had more pipeline capacity to bring in that Marcellus shale gas,” said Kiley. Regions such as the greater New York City area and Massachusetts in particular have felt the strain of these bottlenecks.
2030, 2050 and Beyond
In 2019, New England also saw the completion of the Eastern System Upgrade to the Millennium pipeline and Williams’ Riverdale South to Market project and its Gateway Expansion projects. Several more pipeline projects are planned for 2020 and 2021. But, it’s a fact that single large projects are facing more challenges than ever.
As of last November, seven states and the District of Columbia passed laws to mandate that 100% of the electricity sold in the state or district come from renewable or zero-carbon resources by 2050 or before. Multiple other states are considering legislation or are voicing clean energy commitments.
An atmosphere that negates the need for pipelines is “frustrating,” said Kiley, especially when you consider the U.S.’s enormous gas resources. “It’s tantalizingly close … but constraints on the interstate pipelines don’t allow us to get that gas here.”
“We have seen states, particularly in the Northeast, take a hardline position against all fossil fuels, which has impacted our projects in those regions from a permitting perspective,” added Dunn. “It’s unfortunate and ironic that these sweeping no-fossil fuel mandates will actually increase emissions and perpetuate the use of high-carbon fuels like heating oil and diesel.”
Clean energy planners looking out to 2050 are wagering that new technology will be in place to allow them to cost-effectively move to renewable power gen sources, like wind or solar. But even they say that for all practical purposes, gas has to remain the long bridge out to 2050 – and possibly even beyond.
Pathway 2045 is Southern California Edison’s (SCE) plan to achieve carbon neutrality following the guidelines of the state’s SB 100, which limits the amount of natural gas used for power generation to about 10%. Currently, natural gas provides 46% of in-state generation; the plan outlines a reduction by 50% by 2045, with 40% of the remaining fuel transitioning to hydrogen or biomethane.
One of the key takeaways, however, says Erica Bowman, director of resource planning and environmental strategy at SCE, is that “even as we are working toward that decarbonization vision of California, the natural gas facilities that we have in our state still play a role in keeping that transition affordable.”
Reliability during extended cloudy weather or peak periods is another key factor. When planners took a look at the cost to install resources to supply reliable power should natural gas be completely retired from the 2045 vision, “we found that on an annual basis it basically cost 40% more to install the resources needed,” said Bowman. “That’s a big cost differential. So, we’re also thinking about the context of affordability. There is value to having that natural gas capacity.”
But, she added, everything is dependent on technology and how it could impact those costs. “Hydrogen might move in and be the energy carrier of choice at that point in time,” she said, even possibly leveraging the same infrastructure as natural gas.
Over on the East Coast, Duke has set a net-zero carbon goal by 2050, with a 50% reduction by 2030. And likewise, “we see natural gas as very important to get to those goals,” said Nissan, “primarily because it allows us to retire our coal plants … [and] at the same time keep adding renewables onto our system.”
Nissan says that gas will become a larger part of Duke’s generation mix out to 2030 but agrees that the two decades after that will prove to be a defining time. Currently, the state follows only California in its solar investments, and it has invited conversations with environmental groups and other stakeholders as it has developed its plans and processes.
“Between now and 2050, I assume we’re going to have carbon capture technology; we’re going to have small modular nuclear reactors. Part of our strategy is to have renewables for all of our nuclear fleet,” he said.
Still, he added, “It [depends on] what time period you’re looking at, but we see gas as a very important part of how we’re retiring coal and also part of our climate goals because it does allow you to retire coal and add renewables.”
Balancing Act
In other words, there’s a fine line that planners and policymakers have to dance upon as they are making decisions today that impact our energy and economic climate years into the future.
There’s no question that building any kind of infrastructure is “challenging in this day and age,” said Nissan, from permitting and legal challenges to environmental activism. “Putting anything in the ground whether it’s transmission lines, pipelines or power plants is always going to be difficult.”
Williams was heavily involved in the “National Petroleum Council’s Dynamic Delivery: America’s Evolving Oil and Natural Gas Transportation Infrastructure” report, released in late 2019.
“The study found that there is an overwhelming need to streamline the permitting process for large-scale infrastructure projects,” said Dunn. “An efficient National Environmental Policy Act process will allow us to continue protecting the environment, meet growing demand, serve our customers and ultimately continue to keep the nation’s homes warm and well lit.
“The report also includes recommendations to remove barriers experienced during infrastructure siting and construction, as well as to speed the adoption of new technologies that will improve safety, reliability and environmental performance.”
For utilities and other stakeholders, sharing key benefits with policymakers and community leaders has high value. “[Think of] the benefits of these investments in terms of jobs or tax revenues,” said Nissan. He points to Duke’s Citrus County, Florida, power plant as one example, which brought in tax revenues that have helped offset that county’s unexpected economic downturn due to COVID-19, along with providing permanent jobs.
The technology argument also has to allow for the fact that in the next decades, improvements to gas facilities could be such that gas remains the clean solution. “Every time you build [a power plant], it’s a better version. The combustion engines are becoming more efficient … they’re saving in terms of reducing carbon emissions – nitrogen oxide, sulfur oxide, any emissions that come from the power plant,” said Nissan. “The technology is improving so quickly that when you build one today, you can honestly say this is one of the most fuel-efficient power plants in the country.”
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