House 113-12. March 5, 2013. American Energy security and innovation. The role of a diverse electricity generation portfolio. House of Representatives. 135 pages.
- June 5, 2015. Proposed Clean Power Plan would accelerate renewable additions and coal plant retirements. U.S. Energy Information Administration
- Even without the Clean Power Plan rule (CPP), 40 GW of coal capacity is expected to retire by 2040. If the CPP is passed, between 90 to 101 GW of coal plants may retire (EIA June 5 2015).
- The EIA expects 46 to 62 GW of natural gas plant retirements replaced by 166 GW.
- Coal plant retirement 40.1 GW by 2025 EIA DOE 2015 Annual energy outlook with projections to 2040.
Even in the absence of the proposed Clean Power Plan rule, 40 GW of existing coal-fired capacity and 46 GW of existing natural gas/oil-fired capacity are expected to retire through 2040 in the Reference case. Cases that implement the proposed Clean Power Plan rule accelerate and amplify these retirements, especially for coal. In the Base Policy case, 90 GW of coal-fired capacity and 62 GW of natural gas/oil-fired capacity retire by 2040. In the Policy Extension case, as emission rates continue declining after 2030, 101 GW of coal-fired generating capacity and 74 GW of natural gas/oil-fired generating capacity retire by 2040. The timing of the coal retirements is heavily influenced by implementation of environmental rules that may require power plant operators to either incur costs to retrofit power plants or receive less revenue because of lower levels of operation. As a result, coal retirements occur during the implementation of the Mercury and Air Toxics rule (in both the Reference case and Base Policy case), and in the initial year of the Clean Policy Plan implementation.
If EPA’s clean power plan and mercury and air toxis standards passes, then 60 GW of coal plants may retire early. EIA. March 20, 2014 Planned coal-fired power plant retirements continue to increase
- Nuclear EIA DOE 2015: 19% of total electricity in 2013: 5.5 GW new by 2020 with 3.2 GW retirements by 2020
- Natural Gas 2013: 8.4 quadrillion BTU = 8.2 Tcf to 9.6 QUADS = 9.4 Tcf in 2040
- Only 3% of the nations 80,000 dams have hydropower, though more could be added.
APPA (7 million customers) Diversification is a means of risk management to prevent reliability, and low cost electricity.
40% of new plant construction is NG, 19.1% wind, 12.7% solar, 11.4% nuclear. NG is 43.4% operating capacity with coal 30%. Utilities are spending hundreds of millions to convert coal facilities to NG or new NG plants. They are also using NG to back up wind and solar. NG is subject to price volatility. Prices may be low now, but can easily rise due to increased regulation of fracking, increased utility demand, exports, and increasing use in the transportation sector. It’s not clear if there’s enough infrastrucuture or storage to accommodate greater use of ng by electric utilities.
Rules causing coal and nuclear plants to shut down:
- the utility MACT rule
- clean air transport rule (CATR) cross-state air pollution rule
- Coal ash rule (resource conservation and recovery act)
- Cooling water intake structures rule (section 316(b) of Clean water act)
- New Source Performance Standards (NSPS)
- new National Ambient Air Quality Standards (NAAQS) for criteria pollutants
- National Emission Standards for Hazardous Air Pollutants (NESHAP) for industrial, commercial, and industrial ICI boilers and reciprocating internal combustion engines (RICE) units)
Commercially available technologies can be bought from a vendor, are proven at a commercial scale, and offered with robust guarantees on performance and reliability.
There are no commercially available technologies for the capture of CO2 from coal-based power plants. The DOE has 12 major CCS demonstration projects but not one of them has been completed or even started operating. Most are on paper, canceled, or delayed indefinitely, and AEP canceled its own project due to lack of adequate funding. Nor is CCS available abroad. Even if the technology was ready the high cost precludes commercial deployment. At best CCS technology is at least 10 years away indefinitely until projects are implemented. And since CCS equipment is so large, expensive to install, and highly energy intensive there is a real risk that project economics would discourage widespread deployment unless revolutionary technology innovations come along. On top of that CCS faces significant regulatory and legal barriers to get access to geologic repositories and liability and stewardship of the stored CO2. Lending institutions won’t risk several billion dollars without adequate assurances that CCS technology can be installed given EPA rules. Put another way, a utility operator will never select an electric generating technology that requires a control equipment retrofit of unknown technology to be installed 10 years after initial operation. As a result, EPA’s proposed rule is likely to delay for many years the development of CCS technology because new coal-fueld generation will not be built, and without the development of such new coal-based units in the future, the incentive to invest in and advance CCS technology will be greatly diminished.
Mark C. McCullough, exec VP generation, American Electric Power, 5 million retail customers.
The more fuel diversity the less risk since each fuel type and technology is different in terms of availability, reliability, cost, and performance.
Coal and nuclear plants buffer against natural gas fuel supply disruptions because they have 30-60 days of fuel on site. Baseload power runs around the clock with low fuel costs and provides the bulk of electricity. Intermediate and peaking facilities run primarily during periods of high electricity demand. Policies that prevent new or force early retirement of coal and nuclear reduce capacity diversity, risk availability, reliability, and cost.
Too great a reliance on natural gas with a history of great price volatility increases the risk of price spikes and supply disruptions. In Japan, only 2 of 54 nuclear reactors are back and heavily populated areas of the country have rolling blackouts, reduced output in manufacturing facilities, and some of them are moving abroad. NG prices tripled to make up the deficit.
Coal is solid and can an inventory of 30 to 60 days of supply can be at the plant site, unlike natural gas which is subject to disruptions of supply when pipeline infrastructure is damaged in storms and natural disasters. Nuclear power also has large reserves of fuel capacity.
AEP is concerned that a prolonged “dash” to gas will lead to over reliance on one fuel. Already there can be bottlenecks in delivery when both electric and consumer heating demands occur at the same time, especially on cold, short winter days.
Electric utilities have publicly announced plans to shut down 335 coal-fired generating units totally about 47,000 MW. It is likely that over 20% of the U.S. coal fleet will be shut down in the next few years. ACCCE “Coal Unit Shutdowns” feb 14, 2014
The grid will become increasingly reliant on Natural Gas (NG).
William Mohl, president, Entergy wholesale commodities (6 pages of mostly how safe nukes are)
NG 2013 8.4 quadrillion BTU = 8.2 Tcf to 9.6 QUADS = 9.4 Tcf in 2040
Replacing the approximately 101,000 megawatts of capacity provided by U.S. nuclear plants with gas-fired Combined-Cycle Gas Turbine (CCGT) plants would cost between $100 and $110 billion dollars, not including pipelines.
replacing all U.S. nuclear units with gas-fired generation would require an additional 14.5 billion cubic feet per day of additional gas supply, a 70% increase over the 20.8 billion cubic feet per day of gas that electric generators used in 2011. Natural gas fired generators do not have on-site fuel inventory and must be continuously supplied through a pipeline system, and while some facilities may have access to gas storage facilities to ensure continuous supply, many facilities do not. Supply issues can arise during peak times, when pipeline capacity is needed to satisfy the demands of local gas distribution companies to serve homes and businesses, in addition to the needs of power plants that may not have contracts for firm delivery. By contrast, nuclear plants have up to eighteen months of fuel supply on site and do not compete with residential and business consumers for fuel
Regional electric grids require a mix of baseload, load-following, and peaking facilities. Baseload power sources are those plants that can generate dependable power to consistently meet demand. Baseload generation typically runs at full capacity, 24 hours a day, seven days a week, unless a unit is off-line for a scheduled or unscheduled outage. Load-following power sources are typically called upon to increase or reduce output throughout the course of a day as demand for power from end users changes. Peaking units are usually called into service only when demand for electricity is especially high, such as during periods of extreme heat or cold. While each regional electric system has its own unique characteristics, in general, coal and nuclear plants have long supplied baseload power, while natural gas-fired units have been used as the predominant source of load-following and peaking capacity.
There are 1031 operating nuclear power plants in the United States generating approximately twenty percent (20%)2 of the Nation’s electricity. Those nuclear plants operate as baseload, high capacity factor (approximately 89% in 20111) units that power — and help stabilize — the electric grid in or near many major American cities, including New York, Boston, Philadelphia, Pittsburgh, Baltimore, Washington, D.C., Chicago, Detroit, Cleveland, Charlotte, Miami, New Orleans, and Phoenix, among others. Almost half of U.S. nuclear reactors are located within 50 miles of a metropolitan area that has a population of more than half a million. Throughout the Nation, nuclear generators help keep wholesale electricity prices lower than they otherwise would be.
A misconception about nuclear power plants we sometimes encounter is that they remain as they were when they first began operating. To the contrary, many key components are upgraded or replaced periodically, incorporating technological innovations that have been tested and proven suitable. One example is digital instrumentation, which has replaced other types of instrumentation for multiple systems and sub-systems at Entergy plants. Where digital instrumentation has been installed after rigorous analysis and testing, it generally allows plant operators to exercise finer control of systems and provides more immediate feedback. Another example is replacement components made from innovative new materials, such as working components of feed-water pumps and the turbine blades that are driven by steam to produce power. Components such as these, which often cost much more than the components they replace due to their use of cutting-edge materials, last longer and increase plant reliability
American chemistry council. the US chemical industry is the nation’s largest user of combined heat and power (CHP) with 82 GW of installed capacity at 3,700 sites. CHP is significantly underused. ORNL has estimated there are 130 GW possible in U.S. commercial and industrial applications.
ED WHITFIELD (KENTUCKY). At today’s hearing, we are going to be focusing on the role of a diverse source of fuel for electricity generation. We frequently all hear a vocal chorus about the need for ‘‘all of the above’’ to meet our Nation’s demand for electricity at an affordable cost so that we can be competitive in the global marketplace, create a strong economy, and create jobs.
Robert Mann, the Sierra Club President, was quoted as saying ‘‘Fossil fuels have no part in America’s energy future. Coal, oil, and natural gas are poisoning us. The emergence of natural gas as a significant of our energy mix is particularly frightening, because it dangerously postpones investment in clean energy at a time when we should be doubling down on wind, solar, and energy efficiency.’’
Americans are fortunate to have a variety of electricity sources available to us. Each source brings its own unique mix of assets and liabilities. Some are inexpensive, while others are not. Some are reliably available 24 hours a day and seven days a week and ideal for baseload power, while others are not. Some can be quickly ramped up or down to match quick changes in demand, while others cannot. Some can be located almost anywhere, while others are geographically limited. Some can be easily integrated into the existing electric grid, while others would necessitate costly new infrastructure investments. As a result, there is no one ideal means of generating electricity. The best approach for affordability and reliability is a broad mix of generation sources, be it coal, natural gas, nuclear, or renewables. Each source can serve a purpose in the electricity mix, and each has strengths that can compensate for the other’s weaknesses.
BOBBY L. RUSH (ILLINOIS). If we are going to be able to be a manufacturing country and actually create jobs here, it is going to take energy to do it, and under the current breakdown we have today, roughly 87 percent of the electricity that is generated in this country comes from coal, from nuclear power, and from natural gas, and unfortunately, all three are under attack by this administration. The war on coal has been duly noted, you know, you see so much coal being exported because you can’t even use it in this country today, yet it represents over 37 percent of the electricity that is generated. How you can continue to enjoy the standard of living we have as a country today when the administration is attacking 37 percent of that resource, and then in addition, it is all of the other things that are produced in this country. You can’t just do it on wind and solar. We support the advancement of those technologies, but when 87 percent of your electricity comes from the other sources and you are going after them, that is truly the government picking winners and losers and ultimately, the losers are families who are paying higher electricity costs when this kind of policy goes into effect.
Mr. Shimkus of Illinois. the State of Illinois is a 50 percent nuclear, 50 percent coal, so we have the benefits,
HENRY A. WAXMAN (CALIFORNIA). Cheap natural gas is also helping to transform our electricity sector. This market reality is driving a shift away from the use of polluting coal to generate electricity. Even boosters of coal acknowledge that it is not cost effective to build new coal plants today.
Mr. Mark McCullough, Executive Vice President, Generation, at American Electric Power
Energy diversity plays an important role in reducing the potential exposure of our company and our customers to major fluctuations in markets, costs, regulations, and electric demand. This allows for the use of the lowest cost resources possible while enabling rapid response to demand changes. However, policies that could prevent the construction of new base load generating units or force the retirement of existing capacity could lead to significant shifts to this balanced energy mix and reduce capacity diversity.
For example, the proposed CO2 NSPS for new sources effectively prohibits the construction of any new coal-fired power plant because of a lack of commercially available CO2 control technology. Due to these regulations, as well as numerous other challenges facing nuclear energy, our Nation’s electric grid will become increasingly reliant on a single fuel for new base load generation capacity, likely eliminating both diversity and flexibility in new power plant builds. Federal policy should support fuel diversity, not preclude it.
The importance of fuel diversity cannot be overstated
Too great a reliance upon any one energy source creates a significant risk of exposure to electricity price spikes and supply disruptions. Among other benefits, coal and nuclear plants buffer against fuel supply disruptions because they can inventory months of fuel on site, a fundamental value to any energy security solution with national security benefits.
Over the past 12 years, AEP has added more than 5,000 megawatts of natural gas fuel diversity, enabling our company to switch between fuel sources based on price fluctuations. While we recognize the value that natural gas brings to the diversity equation, AEP is concerned that a prolonged ‘‘dash’’ to gas will lead to over reliance on one fuel and have adverse consequences for the balance and diversity of the power sector and the economy.
With the current low cost of natural gas, coal, and uranium, now is the ideal time to look to the future and adjust the focus of technology development to truly innovative, revolutionary paradigms for energy conversion and use. We support commercialization of Small Modular Reactor, or SMR, technology for the next generation of nuclear power. For fossil fuels, the United States must invest in technologies that show promise of a step change move of the needle regarding cost, fuel efficiency, and environmental performance.
With success, technologies like chemical looping and other new revolutionary technologies will enable our next generation of power plants to use coal with extremely high efficiency and ultra-low emissions, while producing a pure stream of CO2 with no added energy penalty. These technologies can open a vast, yet untapped, oil reserves in this country to enhanced oil recovery production by making enormous quantities of low-cost CO2 available for EOR purposes, bringing an even higher level of energy security. These technology innovations require attention now to enable industry to overcome the high cost of commercialization. Encouragingly, as stated in the CURC–EPRI Technology Roadmap, the necessary funding to develop and commercialize these concepts is not beyond the levels invested in recent years with DOE’s Fossil Energy clean coal programs. This funding just needs to be focused on the proper technologies.
SMR development could address nuclear risk that prevents its broad deployment today.
William Mohl, President of Entergy Wholesale Commodities.
Entergy is one of the largest nuclear operators in the United States. We currently operate 11 nuclear power facilities in New York, Vermont, Michigan, Massachusetts, Arkansas, Louisiana, and Mississippi.
Nuclear plants are an essential part of this Nation’s energy portfolio. Regional electric grids require a mix of base load, load-following, and peaking facilities. While each regional electric system has its own unique characteristics, in general, coal and nuclear plants have long supplied base load power, while natural gas-fired units have been used as the predominant source of load-following and peaking capacity. There are 103 operating nuclear power plants in the United States, generating approximately 20 percent of the Nation’s electricity. Those nuclear plants operate as base load, high capacity factor units that power and help stabilize the electric grid in or near many major American cities. Throughout the Nation, nuclear generators help keep wholesale electricity prices lower than they otherwise would be.
A simple way of looking at the economic value of the existing nuclear generation fleet is to consider the potential cost of replacing it. Using data from the Energy Information Administration, we have calculated that replacing the 100,000 megawatts of nuclear capacity with new combined cycle technology gas plants would cost more than $110 billion. To put that number in perspective, in 2011, American utilities invested slightly more than $30 billion in transmission and distribution facilities, less than 1/3 of the nuclear for combined cycle replacement cost. Moreover, this replacement cost estimate does not include any costs of expanding pipeline capacity to serve new gas-fired plants. The adequacy of pipeline capacity is a key consideration, as was recently demonstrated in New England.
Nuclear power is also a crucial contributor to maintaining America’s air quality.
Mr. BARTON. Let us be honest. You are not going to build a coal plant with those regulations, and you will build, probably, almost all natural gas. I am in the Barnett Shale, so I am not anti-natural gas, but I also have lignite coal plants and I support nuclear power and wind power. So I think it is a little bit disingenuous to say that they are fuel neutral. They are not. The gentleman from Entergy, you are a big proponent of nuclear power. Do you think it is possible in today’s market environment to build a base load nuclear power plant in America?
Mr. MOHL. It is very challenging in this environment to be able to build a new nuclear plant. Currently there is a handful of them being developed down South.
Mr. BARTON. Yes, where they still have the regulated markets and you can roll in the prices. But is the challenge for new nuclear, is it more still regulatory and licensing, or is it just the simple fact that because of the competition from coal and natural gas, and to some extent, wind power possibly, that it is just not cost effective right now? It is not economically possible?
Mr. MOHL. There are three challenges as it relates to merchant nuclear. Low gas prices obviously have depressed the markets. Regulation, we need fact-based scientific approach that is based on cost benefit, and we need fair and competitive wholesale markets. And so you are exactly right, that trying to build a new nuclear plant in a wholesale market is just not feasible. Mr. BARTON. I want the record to show that we had a witness say I was exactly right. If you all will make a note of that.
Mr. Benjamin Fowke, who is President and CEO, Xcel Energy
QUESTOIN: would you comment on the assistance stability impacts of wind and solar energy in your utilities?
Mr. FOWKE. Yes, the reliability issues increase, obviously, the more renewables you have on system. I mentioned in my testimony at one point earlier this year, we had 57 percent of our energy coming from wind. So when that happens, you have to quickly back down your generation, and typically you want that to be a gas-fired generation versus nuclear or coal, because they are designed better for those sorts of things. So you have to ramp up and ramp down, and you have to follow the load accordingly. And that does—as you get higher levels of penetration, increase the cost of having that much renewables on your system.
QUESTION: how does wind energy form a hedge against price spikes?
Mr. FOWKE. Wind, as we all know, is interruptible, so while it has a capacity factor for planning, we put a very small capacity factor on it. So it is fuel. So you can build it and you can determine how long it is going— what it is going to cost over a 20-year period. For us, that is about $40 a megawatt hour. Then you compare that to other fuel sources, natural gas specifically. Sometimes at $40 a megawatt hour it is in the money, as it was when natural gas was at 8 and $10. Sometimes it is a little bit out of the money, as it is today in a very low natural gas environment. But it is still a hedge.
QUESTION: You said in your testimony that only 3 percent of the dams, 80,000 dams across America produce electricity. Could you explain that a little bit? What is holding that up?
Mr. GERKEN. Well, one issue is it is very capital intense projects, and they take such a long time to develop. And a lot of these are not your big—dams or obviously run-of-the-river where we are at, so they have smaller capacity name plate. Our projects are, example, 105 megawatts, 82 megawatts, 72 megawatts, and 48 megawatts. But for the most part, it is that capital intense issue. I am not sure we would build these projects today, you know, in today’s natural gas markets it would have been tough to justify this, because quite frankly, our run-of-the-river hydro are very similar to the nuclear when it comes to cost. But we look at that component from we don’t have a fuel to buy and a waste stream on the other side——
MARK MCCULLOUGH ON BEHALF OF AMERICAN ELECTRIC POWER
Energy diversity plays an important role in reducing the potential exposure of our company and customers to major fluctuations in markets, costs, regulations, and electric demand by allowing for the use of the lowest cost resources possible while enabling rapid response to changes in demand that occur throughout the day. However, policies that could prevent the construction of new baseload generating units or force the retirement of existing coal-fired capacity could cause significant shifts to this balanced energy mix; reduce capacity diversity; and hinder our ability to provide reliable and affordable electricity to our communities and customers. For example, the proposed CO2 NSPS for new sources effectively prohibits the construction of any new coal-fired power plant because of the lack of a commercially available CO2 control technology. Due to these regulations, as well as numerous other challenges facing nuclear energy, our nation’s electric grid will become increasing reliant on natural gas for new generation capacity, likely eliminating both diversity and flexibility in new power plant builds. Federal policy should support fuel diversity, not preclude it.
The importance of fuel diversity cannot be overstated given its implications for assuring economic and energy security. Too great a reliance upon any one energy source (particularly those with a history of price volatility) creates a significant risk of exposure to electricity price spikes and supply disruptions. This can lead to severe impacts on the supply stability and price of electricity for residential, commercial, and industrial customers. Consider the Tsunami catastrophe in Japan, where a natural disaster resulted in all 54 nuclear reactors being abruptly removed from service. Nearly two years later only two units are back in service. Hurricane Katrina in 2005 disabled nine oil refineries and rendered 30 oil platforms damaged or destroyed. Coal and nuclear plants buffer against fuel supply disruptions because they can inventory months of fuel on site, a fundamental value to any energy security solution with national security benefits.
Over the past twelve years AEP has added more than 5,000MW of natural gas fuel diversity, which has enabled our company to switch between fuel sources based on price fluctuations of fuels over time. This diversity has served our customers and communities well and has allowed us to keep our electricity rates low. For example, AEP responded to the spikes in natural gas pricing during the mid2000’s by increasing its use of cheaper coal to serve our customers, while at the same time decreasing emissions. Similarly, recently depressed natural gas pricing have allowed us to keep our electricity prices low by using additional natural gas where more cost effective than coal. However, AEP is concerned that a prolonged“dash” to gas will lead to over reliance on one fuel and have adverse consequences for the balance and diversity of the power sector and the economy.
With the current low cost of natural gas, now is the ideal time to look to the future and adjust the focus of technology development to truly innovative, revolutionary paradigms for energy conversion and use. We support commercialization of Small Modular Reactor (SMR) technology for the next generation of nuclear power. For fossil fuels, the United States must invest in technologies that show promise of meaningfully moving the needle regarding cost, fuel efficiency, and environmental performance. With success, chemical looping and other new revolutionary technologies will enable our next generation of power plants to use coal with extremely high efficiency and ultra-low emissions, while producing a pure stream of CO2 with no added energy penalty. Not only will these new paradigms revolutionize the power generation industry, they can open the vast, yet untapped, oil reserves in this country to Enhanced Oil Recovery (EOR) production by making enormous quantities of low cost CO2 available for EOR purposes. These technology innovations are essential to a diverse energy future, but they require attention now and focused funding to enable industry to overcome the high cost of commercialization. Encouragingly, as stated in the CURC-EPRI Technology Roadmap, the necessary funding to develop and commercialize these concepts is not beyond the levels invested in recent years with DOE’s Fossil Energy clean coal programs; this funding just needs to be focused on the proper technologies.
To ensure our current investments in coal-fired generation can be retained in the future to maintain diversity, we have also invested heavily in the advancement of carbon capture and storage technology. The Mountaineer CCS Project treated a 20-MW portion of flue gas from our 1300-MW Mountaineer Plant, removed the carbon dioxide (CO2), and compressed and injected the CO2 into two deep underground formations more than 7,000 feet below the surface of the plant property. The project successfully operated from 2009 to 2011, and permanently stored nearly 40,000 tons of CO2 in deep saline reservoirs, with continuing post-closure monitoring. A second phase of that project, which would have advanced the technology to a 235-MW commercial scale, was deferred due to the failure to raise funding.
THE ROLE OF DIVERSITY
Diversity plays an important role in reducing the potential exposure of our company and customers to fluctuations in markets, costs, regulations, and electric demand. Diversity within the electric power sector can refer to a variety of practices that reduce these exposures. Perhaps the most important measure of diversity for the electric power sector is the practice of fuel diversity. The U.S. has an abundance of energy resources that can be used to generate electricity, including coal, natural gas, uranium, wind, solar, water, biomass and geothermal. These fuel sources each have a unique cost profile based on both supply and demand of the fuel as well as the unique generating technology required to turn chemical, solar or kinetic energy into useful electrical energy. However, each fuel type and technology present different risk characteristics in terms of availability, reliability, cost, and performance. As such, fuel diversity among these energy resources will lower the overall risk of the generation portfolio and provide for a more reliable and cost effective electric supply. Generating technologies are specific to the fuel or energy resource used to produce electricity to our electric grid. Developing capacity diversity within our generating system is important because it allows for the use of the lowest cost resources when possible while enabling rapid response to changes in demand that occur throughout the day. Capacity diversity is achieved by constructing baseload, intermediate and peaking facilities in addition to intermittent facilities (e.g. wind and solar), which may or may not be available to generate electricity at any given time. When properly deployed, each type of resource can synergistically operate during the various fluctuations in supply and demand to reliably support customer needs and requirements. Generally speaking, baseload facilities (coal, nuclear, hydro, and more recently gas) are designed to run around the clock with low fuel costs and provide the bulk of electricity to the grid. Intermediate and peaking facilities are designed to run primarily during periods of higher electric demand. However, policies that could prevent the construction of new baseload facilities or force their retirement could cause significant shifts to this mix; reduce capacity diversity; and increase risk of availability, reliability, and cost of electricity.
IMPORTANCE OF FUEL DIVERSITY
The importance of fuel diversity cannot be overstated given its implications for assuring economic and energy security. Too great a reliance upon any one energy source (particularly those with a history of price volatility [NATURAL GAS]) creates a significant risk exposure to electricity price escalation and supply disruptions. As has been proven repeatedly across the globe, such exposure can lead to severe impacts on the supply and price of electricity for residential, commercial, and industrial customers. For example, the recent catastrophe in Japan serves as a sobering reminder of what can happen if a single energy source is abruptly removed from use. In 2011, an earthquake and tsunami devastated shoreline communities and seriously damaged the Fukushima Daiichi nuclear power plant. Resultant radiation leaks and a greatly eroded public faith in safety of nuclear power lead to the shutting down of all of Japan’s 54 nuclear reactors for mandatory maintenance and safety checks. To date, only two units are back in service. Heavily populated areas of the country have faced the realities of rolling blackouts, while manufacturing facilities are reducing output, with some making moves to relocate abroad. Meanwhile, natural gas prices in Japan nearly tripled as power producers scrambled to fill the massive void left in their energy infrastructure. Domestic energy disruptions and their consequences are clearly evident by such disasters as Hurricane Katrina in 2005, where nine oil refineries were shut down for an extended period of time and 30 oil platforms were either damaged or completely destroyed, dramatically hampering oil and gas production. United States natural gas prices spiked following the disaster and for months afterward remained more than double the price over the previous year.
There is another unique feature to coal that must be considered from an energy security perspective. Coal is a solid and physically stable energy resource that can be safely stockpiled at the power plant site. A typical power plant takes advantage of this feature by keeping an inventory of 30 to 60 days of supply of coal at the plant site. This is an incredibly valuable characteristic when considering the risks associated with supply interruptions of other fuels, such as natural gas. If storms, natural disasters, or other forces interrupt major gas pipeline infrastructure, gas-fired power plants immediately cease to produce electricity and cannot resume production until infrastructure repairs are made. Coal plants, on the other hand, can continue to operate if the major fuel supply is compromised.
Similarly, nuclear power enjoys the benefit of large reserves of fuel capacity on the plant site. This is a factor of fundamental value to any energy security solution and has national security benefits as well– particularly given the abundant reserves of coal in the United States.
While we value natural gas as a critical component of our generation energy mix, AEP is concerned that the United States has reached an important crossroads in terms of fuel diversity planning. EPA’s regulations have led to the premature shut down of some of our existing coal fired facilities, while not allowing the construction of new coal-fired facilities, as discussed later. This effectively precludes further use of a low-cost, abundant and domestic resource, coal, within the U.S. generating mix and will force AEP and others to increasingly rely on natural gas for generating electricity– which has a long history of price volatility. AEP is concerned that a prolonged “dash” to gas will lead to over reliance on one fuel and have adverse consequences for the balance and diversity of the power sector and the economy.
For example, the increased use of natural gas to generate electricity puts stress on a natural gas supply system designed to meeting peak winter heating needs by requiring increasingly larger supply and flow rate to power plants, which currently represent a minority share of U.S. natural gas demand. As an example, ISO New England just told the Federal Energy Regulatory Commission on February 7 that it was concerned about “increasing reliance on natural gas-fueled generators at times when there is an increasingly tight availability of pipeline capacity to deliver natural gas from the south and west to New England.” This increased reliance has contributed to rapid price spikes in the cost of natural gas in that area, which translates into much higher wholesale electric prices. There are additional concerns surrounding the synchronization of electricity and natural gas markets as supplies of power and natural gas are secured on a different time basis. This disconnect may prevent facilities committed to provide electric power from securing the gas supplies they need to operate. This picture is further complicated by the interdependent nature of the natural gas supply and electric generation industries. As more of the power generation comes from gas, the impact of simultaneous peak electricity demand and peak consumer heating demands converge, creating a scenario where gas deliverability capability can become a bottleneck.
This is particularly true in the winter when shorter days and colder temperatures increase demands for heating and lighting. While adequate supply of gas may exist, delivering at the rate needed during peaks could be constrained.
The dash to gas and the potential problems created in its wake has come at the same time that other countries around the world are increasingly turning to coal to fuel their economies. China is currently far and away the largest consumer of coal, and in fact is consuming almost as much coal as the rest of the world combined. Additionally, Europe is increasingly returning to coal to fuel its electric sector, with much of the imported coal coming from the United States. Consequently, any policy, direct or indirect, to restrict coal use within the U.S. is unlikely to have a significant impact on reducing global coal consumption. The more significant impacts will be felt however by the U.S. economy, particularly in regions of the country which rely on coal production for economic stability and low-cost electric generation.
REGULATORY BARRIERS TO FUEL DIVERSITY
There are numerous barriers to fuel diversity within the electric generation fleet; however our most pressing concerns are the new federal environmental regulations and the lack of an energy policy promoting diversity and therefore energy security.
As an example, the proposed CO2 NSPS for new sources effectively prohibits the construction of new coal-fired facilities for the reasons discussed in the next section. These proposed CO2 performance standards come in the wake of other new environmental regulations, most notably the Mercury and Air Toxics Standards. Due to these new EPA rules and other factors, electric utilities have already publicly announced their plans to shut down 335 coal-fired generating units, totaling about 47,000 MW. Additional coal plant shutdowns are expected as companies finalize their air toxics compliance plans. Once these additional plant retirements are combined with already announced retirements, it is likely that over 20 percent of the U.S. coal fleet will be shut down within the next few years. 1 See http://www.eia.gov/todayinenergy/detail.cfm?id=9751 .2 See http://www.economist.com/news/briefing/21569039-europes-energy-policy-delivers-worst-all-possible-worldsunwelcome-renaissance. 3 See
Due to these regulations, our nation’s electric grid will become increasing reliant on natural gas for new generation capacity, likely eliminating both diversity and flexibility in new power plant builds.
CCS is not currently commercially available or economically viable at this time. EPA supports its fuel discriminatory standard by stating that the rule would not impose any additional costs on the economy because under current economic conditions, no new coal-fueled units will be built. While AEP agrees that current market conditions generally do not support development of new coal-fueled units, this result is driven primarily by current low prices of a very volatile commodity, natural gas. Natural gas prices have fluctuated over the past decade between $2 and $13 per MMBtu on a monthly average basis. Average prices over most of the last decade have been above $6 per MMBtu. Most 10-year projections show gas prices in the range of $4 to $6 per MMBtu. By contrast, most coal prices in the US are less than $3 per MMBtu. In light of the significant historical fluctuation of natural gas prices, it is reasonable to plan for some continued variation in natural gas prices over the long-term even though shale gas reserves appear to be plentiful at this time. If, for example, natural gas prices were to increase modestly to levels seen only a few years ago, electric generating companies could opt to build new coal units based on economics, absent the proposed CO2 NSPS requirements. However, with EPA’s proposal to adopt a CO2 emissions standard based on the performance of natural gas combined cycle units, electric generating companies are unable to build coal-fueled units without assuming unreasonable risks, and therefore generally have no choice but to build gas units instead.
Nuclear energy also faces daunting challenges. According to an MIT study “The Future of Nuclear Power”, nuclear energy faces four unresolved problems: high relative cost; perceived adverse safety, environmental, and health effects; potential security risks stemming from proliferation; and unresolved challenges in long-term management of nuclear wastes. From a new plant construction perspective, risks associated with cost escalation, scheduling, and sheer project size suggest that very few new nuclear plants will be built. Compounding this with the fact that existing nuclear power plants are facing expiration of their operating licenses over the coming years or decades, there is a real threat that nuclear energy will not be a viable participant in a long term diverse energy portfolio.
AEP believes that technological solutions are critical to reducing emissions as well as improving the reliability, efficiency, and availability of electricity production. More than a century of technology innovation qualifies AEP as an industry leader and expert in these topics. Nonetheless, as a consequence of our first-hand experience and intimate understanding of CCS technologies, AEP is convinced that CCS is many years from providing a commercially viable solution to capturing and permanently storing CO2 emissions due to the numerous technical, financial, legal, and regulatory challenges that must first be addressed. However, these solutions will need to be developed to ensure fuel diversity can be maintained with the possibility of a carbon-constrained world. Additionally, there are a number of other new and innovative technologies that convert coal to electric power and other products while producing a pure stream of CO2, not requiring the added processes to capture and purify CO2 emissions. While still in the developmental phase, these emerging technologies are showing tremendous promise at the laboratory and pilot-plant level. In many cases, these new technologies, such as chemical looping applications, are revolutionary as opposed to evolutionary in nature and could usher in a new generation of technology solutions that are lower in cost, perform at higher energy efficiencies, and provide more flexibility in fuel selection.
“Commercially available” technologies are those that can be purchased from a vendor, have been proven at commercial scale on a representative application, and are offered with robust guarantees on performance and reliability. Vendors cannot provide meaningful guarantees without extensive testing at representative scale. Based on this point of reference, no commercially available technologies for the capture of CO2 from coal-based power plants exist today.
The Department of Energy’s Major CCS Demonstration program currently includes twelve projects that propose to demonstrate CO2 capture along with some form of storage and/or utilization of the captured CO2. If this were a list of 12 successfully completed projects, then it could certainly be argued that the technologies are ready for commercial deployment. However, not one of the projects has been completed, and in fact, none have even commenced operation. Most are no more developed than the work on paper required for conception of the project. Some that had previously been included on DOE’s list have been cancelled or delayed indefinitely.
The technologies to capture and sequester CO2 are not commercially available, domestically or otherwise. While several promising CO2 capture technologies are under development, none are ready for commercial deployment. They must be advanced in a systematic and step-wise manner to ensure their technological and economic feasibility.
AEP had begun the process of moving the CCS technology to commercial scale with the Mountaineer CCS Demonstration Project, but the lack of an adequate funding mechanism resulted in the company placing the project on hold. Even if AEP’s project had remained on schedule, the CCS technology, like other first-of-a-kind projects, would have been installed without any commercial guarantees from vendors and would have run the risk of not continuously or reliably achieving high CO2capture levels. AEP’s expectation was that a commercial-scale CCS demonstration project was essential now, so that in 2020 or later, a reliable commercial-scale CO2 capture system might be commercially available and ready for deployment.
With the suspension of the AEP project and as similar DOE projects are delayed or discontinued, the date for commercial readiness of CCS technology continues to move further out on the horizon. A reasonable estimate for commercial availability, based on the current state of technology development, is at least ten years away, and this is assuming that current financial and regulatory barriers to demonstration projects are expeditiously removed. Without a clear path forward, we will remain, perhaps indefinitely, ten years or more from commercialization of CO2 capture technology. Numerous studies and projects by public and private organizations also have concluded that the availability of commercially available CCS is at least a decade away, even if a much more ambitious research, development, and demonstration program were implemented. Even then, CCS equipment is large, expensive to install, and highly energy intensive. There is a real risk that project economics could discourage wide deployment of CCS.
Furthermore, the path to CCS commercialization is filled with significant regulatory and legal barriers. These include issues related to the ownership of, acquisition of, and/or access to geologic pore space, as well as issues surrounding long-term liability and stewardship of geologically stored CO2. The removal of these barriers in many cases will most likely be through the development of state legislation and regulatory programs. Efforts at the state and federal level are underway and in various stages of development, but significant challenges remain before these and other legal and regulatory issues will be sufficiently resolved to support the commercialization of CCS on coal-based generation.
Finally, EPA has proposed an alternative compliance option that will not help coal-fueled EGUs achieve the CO2 performance standard. EPA’s averaging approach will not work without much greater certainty pertaining to CCS cost and technology. In fact, this alternative compliance option does nothing to ensure the demonstration and deployment of CCS technologies. As just discussed, CCS is not yet commercially demonstrated for large-scale commercial applications and the high cost of the CCS technology effectively precludes its commercial deployment, even if the technology was ready. As a result, there are many technical, economic, and legal risks with CCS technology that must be addressed before an EGU developer would consider investing in a new multi-billion dollar plant. These risks will not be taken if the new plant might have to cease operation after ten years if CCS cannot achieve a regulatory standard developed without any real-world data. Without much greater certainty on the timing and success of CCS commercialization efforts, such risk simply will not be acceptable and will effectively preclude the development of any new generation technology that must rely on CCS to operate. It is unlikely that the developer could ever obtain the necessary funding for building the plant until these matters are satisfactorily addressed. Lending institutions and state regulatory commissions will not risk several billion dollars unless they obtain adequate assurances that a CCS technology is capable of achieving the CO2 performance standard and can be installed at the new coal-fueled plant within the initial ten-year period of operation. Simply put, a utility operator will never select an electric generating technology or unit design that requires a control equipment retrofit of unknown technology to be installed ten years after initial operation.
Work done to date on CCS technology has yielded incremental improvements in cost and process efficiency. Substantial “game changing” innovations for CCS cost and performance will require the integration of new CCS technologies with advanced next generation coal-based systems, such as advanced IGCC, oxycombustion, and chemical looping combustion or gasification. As a result, EPA’s proposed rule is likely to delay for many years the development of CCS technology because new coal-fueled generation will not be built and, without the development of such new coal-based units in the future, the incentive to invest in and advance CCS technology will be greatly diminished.
As stated above, the current regulatory climate and market are such that no new coal-fired power plants are likely to be built so long as gas prices remain low.
Currently, most power generation-related technology development is focused on modifications and retrofit applications to the existing power plant fleet. Yet, most of the existing fleet in the US is over 30 years of age and already carrying expensive and complex retrofit systems, many of which were installed at costs rivaling the original power plant. Any further modification or retrofit will add complexity and most likely reduce the energy efficiency of the power plant.
QUESTION: let us talk about this shift in natural gas. I am all for it, but I think you alluded to—just like an electricity grid and a transmission grid, we may have some pipeline constraints. Can you talk about that?
Mr. MCCLURE. Well, there is a recent example, a very real example in New England that I think many of you have become familiar with where high demand for electricity and a very cold snap, high demand for gas for heating created a real spike in prices for both natural gas and electricity. There are other parts of the country where we simply don’t have the gas pipeline infrastructure. We could not convert our two coal plants to gas because there is no— not an adequate gas line infrastructure there.
Mr. SHIMKUS. And Mr. Gramlich, that is some of the challenges on wind power on the reverse side, just with the transmission grid, is it not?
Mr. GRAMLICH. Transmission is very helpful——
Mr. SHIMKUS. Just trying to wield that power to places that it might be used. So those are—I think those are especially issues in a bipartisan manner that we can talk about is expanding our natural gas pipeline, expanding the transmission grid.
Mr. MCCULLOUGH. We will be converting just a few plants to natural gas, but that will be for capacity reserve reasons, not for, you know, overall energy economics. You lose some efficiency, as these units are designed to burn coal and gas can’t get steam temperatures to the same efficiency levels that it was designed for, so it is not going to be a very efficient use of natural gas, as you try to meet the energy needs of your jurisdiction.
Mrs. CHRISTENSEN. We are looking at wind energy. We are doing some solar, but haven’t really moved towards wind yet. For a place that doesn’t have a grid that supplies energy from diverse areas, like the Virgin Islands, do you think that we could reach that same reliability from wind or would we need additional reserve capacity? I am thinking that we couldn’t rely on it.
Mr. FOWKE. You know without specifics, the smaller the grid and the larger the one single source of wind would be, I think the more problems you would have making sure that it is integrated efficiently and reliably.
Mr. OLSON. We all know more people means more homes, more commerce, more industry, more need for electricity generation. ERCOT is the agency in our State of Texas that regulates most of the electricity in the State, about 90 percent of it, and they did a recent study that says we may have a power crisis by 2014 unless we have new power generation brought up online. We will be short 2,500 megawatts is their estimate. If we have a heat wave like the August before last, we were over 100 degrees in every part of the State for over a month. If that happens again, we will have brownouts or blackouts. We need more capacity.