An overview of the current power market in the US and the impact it may have on other parts of the world. This was first presented at a workshop held at the University of Tokyo in Japan on Feb 25, 2014
This first chart snow the prices, in US dollars per million BTU, that have been paid by US power plants for fuel each month since January 2001.Coal prices are shown in black.Pet Coke or Petroleum Coke prices are shown in blue.Natural Gas prices are shown in yellow, and petroleum liquids such as distillate fuel are shown in brown.I have highlighted two points on the chart. First look at the green circle. This was at the end of 2008 when the impact of the global financial crisis was first being felt and the price of both natural gas and petroleum had crashed from all-time highs. Notice that before this time natural gas prices roughly tracked petroleum prices, but after this point in time natural gas prices detached from petroleum prices. This was caused by the large increase in production of natural gas in the US from shale formations. This new production, coupled with a downturn in demand due to the economic recession, created a surplus of natural gas which has cut the link between the price of petroleum and natural gas. As more natural gas became available in the US, the only option for increasing consumption was to use it for power generation. The more the price fell, the more attractive it became to use natural gas for power generation. This trend continued until the period highlighted by the blue circle at the first half of 2012. At that time natural gas prices approached the price of coal in the US. This set the floor for natural gas prices, and since then gas prices have slowly risen as the US economy has slowing started growing again, and non-power use of natural gas has started to increase. In fact, in January 2014 natural gas prices had risen to the $5/MMBTU mark.
Here is my second chart that tells you all you need to know to understand what is happening in the US power generation market.This chart shows the amount of power that has been generated by US power plants each year since 1973. It shows both the total amount of power generated, in gigawatt-hours, and the contributions from specific types of power generation including coal, natural gas, nuclear, hydro and wind.First, look at the red line, the total amount of power generated. Notice that from 1973 to 2008 the amount of power produced increase almost every year. In fact, if this chart was extended back to the beginning of the US power industry you would see that until 2009, there had never been two consecutive years in which the demand for electricity had dropped. Yes, there had been single years in which that happened such as 1983 and 2001, but never two years back-to-back. That ended with the arrival of the global financial crisis in 2008. Power demand in 2008 was less than it was in 2007, and in 2009 it was less than 2008. There was a significant increase in 2010, but that was followed by three more years of slight reductions in demand. Overall there has been no growth in power demand over the past 8 years. When you couple this lack of increase in demand with the price decrease of natural gas and government mandates to increase the amount of power from renewable sources, you can see that this has pushed some coal power out of the market. From 2007 to 2012, the amount of power generated by coal in the US dropped by about 25%. There was a small recovery of market share in 2013 as natural gas prices rebounded, but is that the start of a trend or a one-time event?
This chart represents the US Department of Energy’s official prediction of what the future will bring for US power generation. It was issued as part of the Department’s 2013 Annual Energy Outlook report.You will see that they are predicting that the amount of power that is generated by coal will remain flat over the entire period of the projection. The amount of nuclear power is also expected to be flat. However, the government is predicting that demand for electric power will once again start rising in 2014 and will climb steadily through 2040. They predict this increase in demand will be met mostly by new natural gas power plants with some contribution from renewable power sources.If you only look at the predictions for contributions from coal and natural gas power plants, you will see that the US government expects that sometime after 2030, natural gas will be the largest source of power.
This chart also comes from the government’s Annual Energy Outlook 2013. It shows their predictions of what types of power plants will be built in the US out to the year 2040. They are predicting significant amounts of new natural gas fired capacity, and after the current small wave of coal power plants that are under construction are built, they predict essentially no new ones until the 2036-40 and then only a miniscule amount compared to the contributions of natural gas and renewables. Interestingly they show more nuclear power being built after 2015 than coal.Predictions such as this make it very difficult to invest money in coal power R&D in the US. This is true whether you are the US government or a US power generation technology supplier. If there is no future market, why bother making a better product?
Since the US has been a leader in Integrated Gasification Combined Cycle (IGCC) technology in the past, one question based on what I have just shown you is what will happen to IGCC technology in the future?
When it comes to coal gasification technology, the famous opening line from the English author Charles Dickens’ book “A Tale of Two Cities” accurately describes what is happening around the world: It is the best of times, it is the worst of times.These two photo show examples of the striking contrast of fortunes for coal gasification. I will explain more in the following slides.
Last year Vattenfall, the owner of a 250 MW IGCC in the Netherlands decided to permanently close that facility. Europe, like the US, has seen falling demand for power, and the Dutch IGCC was relatively small and therefore had high costs for operations and maintenance compared to Vattenfall’slarger coal power plants. I visited that IGCC in June of last year as part of a meeting of EPRI’s Gasification Users Association. I was amazed that a facility which appeared to be excellent condition was about to be knocked to the ground. This seemed especially ironic given the need that many developing nations have for environmentally sound coal power. Another IGCC in Europe, Elcogas located in Spain, has also been impacted by a lack of demand for power. It sat idle for 5 months in 2013.
Meanwhile in the US it is also the “worst of times” for coal gasification. In addition to the competition from low cost natural gas, two new IGCCs being built this decade have experienced large cost increases.Duke Energy’s Edwardsport IGCC was originally predicted to cost $1.9 billion but ended up costing 184% of that amount.The second project, Mississippi Power’s Kemper County IGCC, will be the first coal power plant in the US that captures more than 1 million tons of CO2 per year. Kemper County is still under construction, but its costs have risen to over $4 billion. That excludes the cost of the lignite mine being built next to the power plant and also excludes the cost of the CO2 pipeline. When all costs are included, the project is over $5 billion.Why have these two projects exceeded their initial cost estimates by such large amounts?
One cause of the cost overruns according to Mississippi Power is they under-estimated the amount of labor it would take to construct the plant, and also the wages they would have to pay to attract workers to the remote construction site.This aerial photo shows the Kemper County construction site. At the time this photo was taken, more than 5000 construction workers were at the site each day. You can see the many automobiles that are parked in the lower part of the photo.
Both EPRI and the US Dept of Energy have published reports with cost estimates for new IGCCs, but those estimates are for what we call “nth of a kind” IGCCs. They represent the costs after multiple copies of the same design have been built. It is expected that the 2nd of a kind will cost less than the first of a kind because less money will be spent on engineering for the second plant. For the 3rd, 4th and 5th plants, we would expect the cost of construction to come down as construction companies learn the best way to put the facilities together. As even more plants of the same design are built, the equipment costs will also come down.The problem is that the first-of-a-kind costs of an IGCC in the US are very high. While the US Dept of Energy predicted a cost of $3024/kW for an IGCC with 60% CO2 capture, the “total overnight” cost of Kemper County IGCC with 60% CO2 capture now is over $7000/kW. (Total overnight costs means all financing charges and other owner’s costs are excluded.) Therefore, the 1st of a kind cost for the Kemper County IGCC is 238% higher than the US Dept of Energy’s “nth of a kind cost” expectation. With that big of a difference one has to wonder if the nth of a kind costs will really be that low. An even bigger concern is that I do not see any US company that would be willing to build the 2nd of a kind IGCC when the cost of the first was so high. If there is no 2nd of a kind, there will never be an nth of a kind!
In Asia is it is the “best of times” for coal gasification.China is of course the biggest user of coal gasification technology with many coal-to-liquids and coal-to-chemicals plants and at least one IGCCGreenGen the 250 MW IGCC in Tianjin is shown in the photo. The two Shell coal gasification plants I showed earlier are located right across the street from GreenGen. The map on the right is from World Resources Institute and shows several other IGCCs in various stages of development.In KoreaKOWEPCO is building a 300 MW IGCC based on the Shell Coal Gasification process and the same GE gas turbine used in the Duke Edwardsport IGCC. The KOWEPCO IGCC should start up in 2015. Also, POSCO is building a coal-to-SNG (substitute natural gas) plant in Korea. In Japan of course you know about the IGCC already operating at Nakoso based on Mitsubishi technology and the Osaki CoolGen IGCC which is now under construction based on the EAGLE gasifier. Last year the exciting announcement was made that two more IGCCs, each twice the output of Nakoso will be built.
The largest IGCC project in the world is now under construction in India. It is located at Reliance’s oil refinery in Jamnagar. It will use the E-Gas technology which is now owned by CB&I. Reliance is doing the project in two phases. The first phase is under way and will use 8 gasifiers that will each consume 2900 tons per day of pet coke. The second phase will add four more gasifiers.The goal of the project is to use all of the pet coke that is produced in the refinery to make a variety of products that are currently supplied by using LNG. The products include: Hydrogen to upgrade crude oil, SNG for fired heaters located throughout the refinery, a small amount of CO which is used to make chemicals, and 1500 MW of electricity which will be generated in combined cycle power plants. Start-up of the first gasifiers is scheduled for the 2nd quarter of 2015 – 3 years after the start of the construction project.
A key question, which I cannot answer, is “can the Asian IGCC and Polygeneration projects I just mentioned avoid the large cost overruns that were encountered by the US IGCC projects?” If they can, that will open the door to more IGCC projects not only in Asia but elsewhere. If they cannot, it could doom the technology.
My conclusions about the status of coal gasification are shown here. It is the “best of times” in Asia, but gasification has lost its appeal in North America and Europe.If the demand for energy picks up in Europe, interest in gasification may return because it may be competitive with natural gas in that region.In North America, interest in coal gasification will only return if natural gas prices return to the levels we saw in the middle of the last decade.Because of this situation, it is clear that the future of IGCC technology will be determined by the current projects which are under construction in Asia.
I said interest in coal gasification in North America will only return if natural gas prices exceed $8 to $10 per million BTU (MMBTU). Let’s spend a few minutes looking at the US natural gas market to understand whether that might happen any time in the near future.
The first slide I showed you revealed that natural gas prices in the US detached from oil prices when the global financial crisis hit in late 2008. I have also shown the impact that low natural gas prices had on US power generation. This chart shows you the impact that low natural prices have had on drilling for natural gas and oil. You can see that in the three years before the global financial crisis hit, there were at least 1400 rigs drilling for natural gas every day in North America. That was when the shale gas formations were first being developed and natural gas prices were well above the expected cost of production from a shale gas resource. Typical costs I have seen are $5-6/MMBtu. In other words, a shale gas producer would need to get at least $5 to $6/MMBtu for natural gas to recover their costs. When natural prices fell to as low as $3/MMBtu, the incentive to drill for more shale gas went away. The producers lost money on the wells they drilled. There are now only 400 natural gas drilling rigs in operation in North America. That is a 70% decrease since the peak in 2008. While US natural gas production has continued to slowly climb since 2008, I think it will be difficult to continue that trend if drilling activity remains this low. If production begins to fall off, that will cause prices to rise, which would then provide an incentive to start drilling for more natural gas. Consequently, one should expect that US natural gas prices should rise to at least the level that will cover the cost of production: $5-6/MMBtu.
Another reason one can expect US natural gas prices to rise is shown in this chart which was produced by the US government’s Federal Energy Regulatory Commission – that agency monitors the US energy market.The chart shows spot prices paid for delivery of LNG at various ports around the world. The prices generally reflect the market price of natural gas in the different regions. Prices in the US are very, very low compared to the rest of the world and especially compared to Asia and South America.This large price discrepancy has created a desire by US natural gas producers to find a way to reach the higher price markets. One way to do that is to build LNG export facilities in the US. If that happens, one would expect the prices on this chart will come closer together with US prices going up and Asian prices dropping. Where will they equilibrate? I don’t know. It will depend partly on how much LNG the US is willing to export.
Many companies in the US that have indicated a desire to build LNG export facilities. Five projects have already been approved by the US government for construction. If all five are built, they would consume 10% of current US natural gas production. There are also another 20 projects which have applied to the US government for approval. If all were approved and built, the US would have the capacity to export 30% of its current production of natural gas. I believe that would be enough to have a meaningful impact on natural gas markets both in the US and Asia.
Despite the looming impact such a large amount of exports could have, the US government’s most recent “Annual Energy Outlook” is predicting natural gas prices will be about $5/MMBtu in 2025 before climbing to $7.50/MMBtu by 2040.If this prediction is correct, then there will be little interest in coal gasification in the US before 2040.
It is against this background that I will consider another key question: “How will the new US CO2 emission standard for new power plants impact coal power?”
This slide summarizes the new regulation which is set to go into effect this year in the US.It only applies to new power plants. New coal power plants would have to meet a standard of emitting no more than 500 kg of CO2 per gross MW-hour of output averaged over any 12-month period. This would require a coal plant to capture, on average, about 50% of the CO2 it produces. If the plant had a high efficiency design, such as higher steam temperatures, it would need to capture less than 50%, but some amount of CO2 capture would still be required.Natural gas fired gas turbines and combined cycles, however, would have to meet a standard of 455 kg CO2 per gross MW-hr if the plant produced more than 250 MW, or 500 kg CO2/MWhr if it produced 73 to 250 MW of power. Units smaller than 73 MW would be exempt.Because of the lower carbon content of natural gas, it should be possible to meet the proposed standards for gas turbines without adding any CO2 capture.
On this chart I will try to summarize the impact the new CO2 emission standards will have on the competitiveness of coal power in the US. The chart shows EPRI’s estimates for the cost of electricity, levelized over 30 years, for new power plants. The first column shows our estimate for an new coal power plant that does not have any CCS. This plant would not be able to comply with the new rule, but I include it here as a reference. It would produce electricity at a cost of $70/MW-hour.The next column shows our estimate for a new coal plant that would meet the 500 kg/MWhr standard by using a post-combustion capture system with Mono-ethanol-amine (MEA) – the most proven post-combustion technology available today. That plant would produce electricity at a cost of $92/MW-hour.Now let’s look at how that compares with building a natural gas combined cycle (NGCC). I’ve shown three lines corresponding to three different prices for natural gas: $3/MMBtu, $6/MMBtu and $9/MMBtu. Remember that the US government is predicting that natural gas prices will only reach $7.50/MMBtu by 2040, and this chart shows that even if they are wrong and it reaches $9/MMBtu, today’s CCS technology would still be a more expensive option. Also notice that even the coal plant without CCS is not competitive with natural gas at $6/MMBtu.It is clear that technology must improve if coal is to be competitive under these new regulations. But it is not just the CO2 capture technology that must improve, the entire system of power generation and CCS most improve. I show why with the next two columns. The one labeled “MEA+$0” assumes that we could develop a CO2 capture technology which has the same energy consumption as MEA but has zero capital cost. Obviously that is not going to happen, but it helps define a lower limit. The cost of electricity from that plant is still above $80/MWhr. The final column is based on a CO2 capture technology that uses the theoretical minimum amount of energy to capture and compress CO2 and has no capital cost. Again, such a system will never be developed, but it shows that even if it could it would not be able to compete with $6/MMBtu natural gas. Consequently, coal will not become competitive with natural gas in the US if we focus only on improving CCS technology. We must look at the entire power plant.
This slides provides more detail on the previous chart
My conclusions on the impact of the proposed US standard on CO2 emissions are that coal power will need a significant improvement in both CO2 capture technology and power plant technology, or an increase in natural gas prices to approximately $9/MMBtu before it will be competitive.If neither of those happen, then we will not see any new coal power plants built in the US.
Let’s assume for a moment that natural gas prices to do rise significantly in the US to the point that a coal power plant might be competitive, or that in regions where natural gas already costs more than $9/MMBtu there will be regulations requiring CCS on coal plants. Is CCS technology ready for use in a commercial coal power plant?I will use the next slides to review the current status of CCS technology.
Based on our research, we believe the largest CO2 capture system ever operated on a coal power plant is the one shown in this old photo. It is a system which captured 400,000 ton CO2 per year at power plant in Texas. The CO2 was used for enhanced oil recovery in 1983 but shortly after the project began, the price of oil collapsed and it soon became uneconomic to run the facility. It was shutdown in 1984.
We believe this photo shows the largest CO2 capture system ever installed on a natural gas fired power plant. This system captured 100,000 tons of CO2 per year from a portion of the exhaust from a combined cycle power plant. The CO2 was used in carbonated beverages like Coca-Cola.The system operated from 1991 until approximately 2005 when it was shutdown.
The only CCS projects in operation today that capture and store at least 0.5 million tons of CO2 per year are shown on this map. I’ve crossed out the project in Algeria because it stopped injecting CO2 last year due to concerns about a crack forming in the rock above the saline formation. The two other projects outside of North America are associated with off-shore oil and gas production.
This map zooms in on the six large-scale CCS projects currently in operation in North America. I am not going to go into detail since none of them are attached to a power plant, but I do want to point out that all six are selling the captured CO2 for enhanced oil recovery.
Later this year, two new projects are scheduled to begin capturing CO2 from coal power plants. The first will be the Boundary Dam project in Saskatchewan where 1 million tons of CO2 will be captured from an upgraded 150 MW (gross) coal power plant.The second will be the Kemper County IGCC which I mentioned earlier. Boundary Dam will be capable of capturing 1 million tons of CO2 per year, Kemper is designed to capture 3 million tons per year. Both projects will sell CO2 for enhanced oil recovery or EOR.These two projects will give the power industry its first “real life” experience with operating large-scale CCS systems.
My slides have focused mainly on the United States since that is the region I know best.I do not have sufficient time to cover the other regions of the world in detail, so I have added some slides as background to this presentation which review important policies and projects related to coal in various countries around the world.A summary of those slides is provided here:There are several other countries which are now proposing or have implemented limits on CO2 emissions that would require at least partial capture of CO2 from coal power plants.Many Asian countries are strongly committed to continued use of coal for powerSeveral important coal-using nations have not found suitable storage sites for large amounts of CO2 – South Africa and Korea are two examplesPublic distrust of nuclear power may create demand for more coal power in some countriesAnd finally, as it has in the US, the global economic slump has slowed or stopped the growth in the demand for electric power in developed countries. This limits the opportunities to demonstrate new coal power technology since few new coal power plants are needed.
Given this situation, the development and demonstration of new coal power technologies will require more collaboration among the nations in the Organization for Economic Cooperation and Development and between the OECD nations and the rapidly developing economies in the developing world.The developing economies need new coal power plants but are unwilling to pay extra for advanced technologies.Developed nations may be willing to pay extra for improved environmental performance, but they do not need new coal plants due to flat or declining demand for power. (Japan may be the one exception.)Could these two groups of countries get together to jointly demonstrate advanced coal power technology in the nations with a growing need for power?Finally, whether in developed countries or developing ones, we all need to find secure places to store captured CO2. We should find ways to work together to make that happen.Thank You.
World Energy Situation and 21st Century Coal Power
World Energy Situation and 21st
Century Coal Technology
Dr. Jeffrey N. Phillips
Senior Program Manager
11th AECE Technical Forum
February 25, 2014