Panelists at the ELECTRIC POWER Keynote and Roundtable Discussion in Baltimore in May wrestled with a range of issues. But despite calls for a “balanced portfolio,” an “all-of-the-above” energy strategy, and predictions of “more changes in the next 10 years than in the last 100,” the focus of attention appears to be the decidedly mundane displacement of coal by natural gas.
It may not rival the newest iPad for cool technology, but the power generation industry is embracing pragmatism as low-cost natural gas from shale resources turns the dispatch order on its head. The challenges posed by natural gas, as well as forecasts for electric power demand for the next 25 years, were the primary focuses of attention during the 2012 Keynote Session and Roundtable Discussion during ELECTRIC POWER, which was held in Baltimore from May 14 to 16.
Arshad Mansour, senior vice president, research and development (R&D) at the Electric Power Research Institute, kicked off the session with a presentation that focused on transformative technologies. He said the power industry had gone from 4,000 MW to 47,000 MW of wind energy in 10 years, that 10,000 MW of demand-side capacity had entered the markets, and that the real cost of electricity, adjusted for inflation, is lower today than it was 30 years ago. “The system is being turned upside down, and we will see more change in the next 10 years than in the last 100 years,” Mansour said. The industry, he said, is built on innovation.
Mansour used the phrase “nodes of innovation” to refer to materials, environmental controls (including those for water), and consumer technology. With respect to the last, he noted that three million “new iPad” tablet computers were ordered the first weekend they were offered.
But perhaps change is not the same as innovation. When asked during the Roundtable Session to list the top three things that keep him up at night, Mansour responded, “operating existing plants in new operating modes,” referring to the need for coal-fired plants to become more flexible now that gas-fired plants enjoy a competitive price advantage and the fact that wind energy largely enjoys “must-take” contracts. Flexible lay-up procedures, for example, are needed for coal units forced out of the dispatch queue due to new market dynamics.
Clearly, a world of difference exists between an iPad rollout and flexible layup procedures for coal-fired boilers as examples of innovation. In fairness, however, considerable innovation is wrapped up in how the power industry keeps aging power plants in service. Remote inspection using robotics, embedded sensors, and advanced nondestructive evaluation techniques all are examples Mansour shared. And new materials technologies, he said, are being applied to ultrasupercritical coal-fired boilers. “At some point, the U.S. will build new coal plants,” he predicted.
Demand Growth Crawls
At least two things are needed to innovate: money, especially patient capital, and a business model that encourages innovation and new technology adoption. Arguably, the electricity industry has neither right now.
One reason for the lack of money was mentioned in keynote remarks by Dr. Howard Gruenspecht, acting administrator of the U.S. Energy Information Administration (EIA). Electricity demand growth has declined so much that the country’s existing capacity base could suffice for the next 20 years, he said. For an industry that makes money by investing in infrastructure and earning a rate of return on invested capital, his comments may not be an encouraging message.
Gruenspecht relied on the EIA’s final release of the Annual Energy Outlook 2012, which had not yet been made public when he made his remarks. He noted that demand growth averaged 1.0% a year between 2000 and 2010 and is expected to average 0.8% a year between 2010 and 2035. He said energy consumption is not forecast to return to pre-recession levels until 2022. With regard to EIA estimates of expected coal plant retirements—30 GW to 70 GW through 2035—he emphasized that the EIA reference cases do not take into account future policy decisions. This means potential carbon restrictions are not reflected in EIA retirement estimates. Non-hydro renewable sources also are forecast to more than double in the time period.
The big change in the U.S. electricity generation energy source mix is that coal’s share drops to 39% from 45%. At the same time, natural gas increases its share from 24% to 27%, and renewable energy’s share rises from 10% to 16%, with hydroelectricity making up the lion’s share of that total.
None of this suggests an industry changing at an iPad-like rate of innovation. The fact is, the industry has relied on government-sponsored R&D to supplement what the industry spends, which, compared to other industries, is paltry when viewed as a percentage of total revenue. Taxpayers already made a substantial investment through the American Reinvestment and Recovery Act for smart grid, renewable energy development, and electric vehicle projects. With the policy-making machine in Washington and many of the states bogged down over partisan wrangling, funding for innovation is more likely to shrink than grow.
Following the two keynote presentations, Mark Crisson, president and CEO of the American Public Power Association, and Richard McMahon, vice president of energy supply and finance with the Edison Electric Institute, joined Gruenspecht and Mansour for a panel discussion moderated by POWER magazine Editor-in-Chief Dr. Robert Peltier.
Breaking in Line
Peltier asked the panel to discuss what he referred to as the “trickle-down effects” of shale gas. Not surprisingly, $2/MMBtu gas has changed the dispatch order, said Crisson, and some coal plants now have lower capacity factors than gas plants. He called shale gas a “disruptive technology” as well as an impediment to fuel supply diversity. MacMahon said that gas plants are now being operated as baseload units but that low-cost natural gas has provided “headroom” in electricity prices, which has helped utilities pursue “significant capital spending” plans with little risk of rate shock. Mansour said that coal plant maintenance strategies have to be revised, because their long-term operating duties have changed.
The panelists all argued for preserving the ability of retired coal plants to run again in the future, rather than be permanently shut down. McMahon reminded the audience that fossil plants in Texas were mothballed for many years but were restarted when the state faced a supply crunch. “You need to be nimble and go between coal and gas,” he said.
Panelists agreed that although the natural gas industry is different from the electric power industry, issues around natural gas fracking are manageable. Gruenspecht said no “show stoppers” have emerged from among shale gas producers, but that poor performers affect the industry overall because they influence public perceptions. Crisson added that the Federal Energy Regulatory Commission is focusing on gas deliverability aspects such as storage, scheduling, and curtailment. As with electric transmission lines, new gas pipelines are required to get shale gas to market.
Other Options Stumble
In the face of low natural gas prices, competing options for power generation have stumbled. Peltier mentioned cost overruns and scheduling delays at the only two nuclear units under construction in the U.S., Southern Co.’s Vogtle Units 3 and 4, and said the experience appears to follow the pattern for new nuclear construction cost and scheduling overruns in Europe. However, MacMahon opined that a proposal in Congress to institute a clean energy standard (which would replace a renewable portfolio standard) could bring more nuclear into the mix.
When a question from the audience was raised about carbon capture and sequestration and natural gas prices versus integrated gasification combined cycle (IGCC), Peltier said that Duke Energy’s Edwardsport IGCC project has had difficulties, and Gruenspecht conceded, “not everything is going to win.” Mansour said that “no line of sight” to a federal carbon policy and sustained low gas prices “both hinder IGCC.”
The one option with a realistic short-term shot at giving gas-fired power a run for its money is wind energy, which is waiting for its all-important production tax credit (PTC) to be renewed. Gruenspecht asked what happens to state-level renewable portfolio standards if these credits are not extended. Currently, wind energy development planning beyond the end of 2012, when its current PTC expires, has ground almost to a halt.
Not All It’s “Fracked Up” to Be?
Whether $2/MMBtu gas is a temporary aberration or a phenomenon more like the “gas bubble” of the 1980s and 1990s is the question that everyone must answer but no one can. Gruenspecht said the gas industry isn’t used to being “under the microscope,” referring to the public protests and outcries over issues like fracking chemicals, water contamination, and fugitive emissions. New environmental regulations could begin to eat into the fuel’s current price advantage. And now that coal appears down for the count, foes of fossil fuels in general are likely to focus more on shale gas production.
Peltier asked about states such as New York that have banned fracking, and MacMahon said that some states like Pennsylvania have tapped into the revenue stream from shale gas production (with the implication that the new revenue would make them more hospitable to fracking). Mansour pointed to the use of natural gas as a key raw material in manufacturing and as a substitute for petroleum-based sources of transportation fuel. Expanded natural gas use could be aided by forecasts of a long-term price that is between $4/MMBtu and $6/MMBtu, he said.
Whether the U.S. begins exporting natural gas as liquefied natural gas is another long-term pricing issue. Crisson said political uncertainty exists around exports. Gruenspecht cautioned that it would “take a long time [for the country] to become a net exporter.” The EIA’s forecasts show that supplies will grow faster than consumption for many years and that the most likely export market will be Mexico. “Gas markets are not globally integrated,” he said.
End State for Coal
Low natural gas prices tie one of the coal industry’s hands while onerous environmental laws tie the other. The panelists’ view was that things will not turn around any time soon. Though it’s almost impossible to imagine the country forsaking its largest energy resource forever, it is becoming harder to see how that resource can be extricated from its Gordian knot.
Crisson added another big unknown for coal: The EPA plans to issue a New Source Performance Standard for carbon for existing coal plants, in addition to its recently issued rules on carbon emissions for new coal plants. That’s only one of many reasons why the EIA’s forecasts show no new conventional coal plant buildout. “Carbon costs will impact at some point,” Gruenspecht said.
When asked by an audience member whether a change in administration or Congress might “move the needle” after the November elections, only Crisson offered a specific response, saying that extending the PTC could have a direct and quick impact on the industry. However, he also said that fiscal and tax reform can impact the industry as well as the pace of the infrastructure buildout. MacMahon underscored that remark: “The last thing you want is to tax capital formation.”
If you needed a takeaway to bet on from this year’s Keynote Session, it would be that gas-fired capacity will displace coal in the near term. The results from PJM’s recent capacity auction validate that conclusion, as 95% of the resource bid was natural gas–fired. If your appetite for risk is a little greater, you also might bet on solar photovoltaic ramping up during the next five years in a manner similar to wind over the past five.
But a more subtle conclusion was evident in the closing remarks. Peltier asked the panelists to list the top three things that keep them up at night. Gruenspecht, the lone panelist directly employed by the government, jokingly said concerns about “continued appropriations” for his agency. Given the stalemate in budgeting, that may not be so humorous. MacMahon mentioned getting the rules right under Dodd-Frank financial reform legislation to minimize the cost of hedging. Crisson mentioned access to capital, maintaining the ability to hedge fuel supply, and especially the specter of gas price volatility. He also noted that banks losing $2 billion on a single trade (referring to J.P. Morgan’s loss in the derivative market that was in the news during the conference) doesn’t help. Finally, Crisson mentioned perverse market pricing caused by wind energy being part of the market.
What’s keeping them up at night (perhaps unfortunate news to a room full of power engineers) isn’t technological innovation, but financial innovation, regulation, and reform. Given that rising housing prices—“as far as the eye can see” in Wall Street models—ultimately collapsed the financial services industry, it might pay to keep a jaundiced eye on equally optimistic gas price projections in electricity industry business models.
— Jason Makansi (email@example.com) is president of Pearl Street Inc., a technology deployment services firm.