World Energy Situation and 21st Century Coal Power

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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

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  • 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

    1. 1. World Energy Situation and 21st Century Coal Technology Dr. Jeffrey N. Phillips Senior Program Manager 11th AECE Technical Forum February 25, 2014
    2. 2. Average Cost of Fossil Fuels Delivered to US Power Plants ($/MMBtu, no inflation adjustments) Coal Petroleum Liquids Pet Coke 25 20 15 10 5 0 © 2014 Electric Power Research Institute, Inc. All rights reserved. 2 Natural Gas
    3. 3. US Power Demand is Flat – No Need for New Coal 4,500,000 4,000,000 Total 3,500,000 Coal 8 years, no load growth GW-hr 3,000,000 Natural Gas 2,500,000 Nuclear 2,000,000 Conventional Hydro 1,500,000 Wind 1,000,000 Other Renewables 500,000 © 2014 Electric Power Research Institute, Inc. All rights reserved. 3 2013 2011 2009 2007 2005 2003 2001 1999 1997 1995 1993 1991 1989 1987 1985 1983 1981 1979 1977 1975 1973 0
    4. 4. US Power Generation Predictions – EIA Annual Energy Outlook 2014 Get info from AEO 2014 Millions of MWhr per year Billions of MWhr per year © 2014 Electric Power Research Institute, Inc. All rights reserved. 4
    5. 5. Most new US capacity additions predicted to be natural gas and renewables (gigawatts) Source: EIA, Annual Energy Outlook 2013 © 2014 Electric Power Research Institute, Inc. All rights reserved. 5
    6. 6. Key Question: What is the future of IGCC for coal power? © 2014 Electric Power Research Institute, Inc. All rights reserved. 6
    7. 7. “It was the best of times, it was the worst of times” – Charles Dickens Buggenum, The Netherlands Tianjin, China Shell coal gasifier for IGCC – permanently stopped in 2013 Two Shell coal gasifiers for chemicals production – still operating © 2014 Electric Power Research Institute, Inc. All rights reserved. 7
    8. 8. IGCCs face strong headwinds in Europe • Vattenfall permanently closes its 250 MW IGCC located in Buggenum, The Netherlands – Cites decrease in power demand in EU and high fixed costs of the comparatively small coal power plant • The Elcogas IGCC in Spain has seen a similar lack of demand for power – Did not operate for 5 months in 2013 © 2014 Electric Power Research Institute, Inc. All rights reserved. 8
    9. 9. Capital Cost Increases Hit US IGCCs • Duke Energy’s Edwardsport IGCC: $3.5 billion or $5663/kW “total project cost” – Estimated cost at beginning of project (Oct. 2006) was $1.9 billion – actual was 184% of this estimate • Mississippi Power’s Kemper County IGCC has reached $4.0 billion or $7670/kW “total project cost” – Estimated cost at beginning of project (April 2010) was $2.4 billion – current cost is 167% of that estimate © 2014 Electric Power Research Institute, Inc. All rights reserved. 9
    10. 10. Mississippi Power’s Kemper County IGCC Summer 2013 Photo courtesy of Southern Company © 2014 Electric Power Research Institute, Inc. All rights reserved. 10
    11. 11. The Cost of First-of-a-Kind? • Both the US Dept of Energy and EPRI have predicted costs for “nth-of-a-kind” IGCCs which are much lower than Edwardsport or Kemper • DOE/NETL-2011/1498 report cites an IGCC with 60% CO2 capture having a “total overnight cost” of $3024/kW – This report is cited in EPA’s Greenhouse Gas New Source Performance Standard proposal – Sept 2013 • Adjusting Kemper’s costs to “total overnight” results in a current estimate of $7190/kW – 238% higher than DOE’s How do you get to the “nth” project when the 1st is so costly? © 2014 Electric Power Research Institute, Inc. All rights reserved. 11
    12. 12. Asia IGCC Projects (1400 + MW) • China China - GreenGen - 250 MW – TPRI 5 other IGCCs in planning 300 more gasifiers by 2020 Korea KOWEPCO IGCC - 300 MW – Shell/ GE Start up – 2015 POSCO Coal to SNG – E-GasTM Japan Osaki CoolGen - 170 MW IGCC with EAGLE Gasifier, TEPCO&MHI - 2 x 500 MW © 2014 Electric Power Research Institute, Inc. All rights reserved. 12
    13. 13. Reliance Jamnagar Polygen, India Project Highlights E-Gas technology Gasifiers 8+4 = 12 x 2,900 tpd petcoke, SRU/ TGTU Oxygen 4+2 = 6 x 5,250 tpd, 99% (Linde) AGR SFU CO2 Acid gas 272,000 Nm³/h syngas per gasifier Sulfur Linde Rectisol PSA Schedule Kickoff meeting May 2012 1,300 t/dH2 Start up Q2 2015 - (3 Years) Syngas ASU O2 LTGC AGR Gasification Shift & GC Methanation CO Recovery 3,500 Gcal/hr SNG CO to Chemicals Petcoke and/or coal SWS CCP OSBL Offsites Source: Thomas Matthew, CoalAsia New Delhi, 2013 © 2014 Electric Power Research Institute, Inc. All rights reserved. 13 1,510 MW
    14. 14. Key Question: Can the Asian IGCC and Polygen projects avoid the large cost overruns of the US IGCC projects? © 2014 Electric Power Research Institute, Inc. All rights reserved. 14
    15. 15. Conclusions on Gasification • The commercial application of gasification technology is very robust in Asia • At the same time it has lost its appeal in North America and Europe • If demand for energy picks up in Europe, interest in gasification may return • In North America, unless natural gas prices return to >$810/MMBtu, demand will be limited to niche applications • The future of IGCC technology will be determined by the current projects under construction in Asia © 2014 Electric Power Research Institute, Inc. All rights reserved. 15
    16. 16. Key Question: Can US Shale Gas Continue to Keep US Natural Gas Prices Low? © 2014 Electric Power Research Institute, Inc. All rights reserved. 16
    17. 17. Impact of Natural Gas Prices on Drilling in North America (July 2004 to November 2013) 1,800 Number of Active Drilling Rigs 1,600 1,400 1,200 1,000 800 Oil 600 Natural Gas 400 200 0 70% Decrease in Natural Gas Drilling Since 2008 © 2014 Electric Power Research Institute, Inc. All rights reserved. 17
    18. 18. Spot Prices for LNG - Worldwide Prices are not the same around the world! © 2014 Electric Power Research Institute, Inc. All rights reserved. 18
    19. 19. US LNG Export Facilities • Approved for Construction – Five LNG export facilities – Total capacity 6.7 billion cubic feet per day – Total capacity 50 million tons per year – Approximately 10% of total US natural gas production • Construction Permits Under Review – Approximately 20 additional LNG export projects have filed with the US government for approval – Total LNG capacity could be as high as 20 billion cubic feet per day or 150 million tons per year © 2014 Electric Power Research Institute, Inc. All rights reserved. 19
    20. 20. US Government Predictions for US Fuel Prices, $/MMBtu Source: www.eia.doe.gov 2014 Annual Energy Outlook 9 8 7 6 5 Coal Natural Gas 4 3 2 1 0 2012 © 2014 Electric Power Research Institute, Inc. All rights reserved. 2025 2040 20
    21. 21. Key Question: How will the new US CO2 emission standard for new power plants impact coal power? © 2014 Electric Power Research Institute, Inc. All rights reserved. 21
    22. 22. Proposed US rules for CO2 emissions from new power plants Separate limits are set for coal and gas: – Coal: 500 kg CO2/MWh, gross, rolling 12 month average – Gas turbines ≥ 250MW: 455 kg CO2/MWh, gross, 12 month average – Gas turbines 73-250MW: 500 kg CO2/MWh, gross, 12 month average • Will require new coal plants to include ~50% CO2 capture – More efficient plants will need less CO2 capture © 2014 Electric Power Research Institute, Inc. All rights reserved. 22
    23. 23. Impact of CO2 Emission Standards for New US USC Coal Power Plant 100.00 Nat. Gas Price, $/MMBtu 90.00 $9 Levelized Cost of Electricity, $/MWh Fuel & O&M COE Capital COE CO2 T&S COE 80.00 70.00 $6 60.00 50.00 $3 40.00 30.00 NGCC LCOE 20.00 10.00 0.00 No CCS © 2014 Electric Power Research Institute, Inc. All rights reserved. MEA MEA + $0 23 Best + $0
    24. 24. Legend for chart in previous slide Case Description No CCS No CO2 capture MEA 37% CO2 capture using MEA solvent MEA + $0 Same as “MEA” case but assumes MEA system adds zero capital cost Best + $0 CCS system consumes 3.6% of the net power of “No CCS” case and is available at no capital cost – the best one could hope for! • All plants are based on 600°C supercritical steam cycle, burn Powder River Basin coal sub-bituminous coal, and pay $10/ton CO2 for transport & storage © 2014 Electric Power Research Institute, Inc. All rights reserved. 24
    25. 25. Impact of Proposed CO2 Standard on Coal Power in the US • To be competitive, new coal power plants will need: – A significant improvement in CO2 capture technology, and – A significant improvement on coal power plant technology, or – An increase in natural gas prices to approximately $9/MMBtu © 2014 Electric Power Research Institute, Inc. All rights reserved. 25
    26. 26. Key Question: Is CCS Ready for Use on Commercial Coal Power Plants? © 2014 Electric Power Research Institute, Inc. All rights reserved. 26
    27. 27. Largest CO2 Capture System Ever Operated on a Coal Power Plant • 400,000 ton/yr CO2 from 100 MW Lubbock Power & Light power plant • Operational 1983-1984 for EOR Floods • Dow Amine Technology Photo courtesy Gas Processing Solutions LLC © 2014 Electric Power Research Institute, Inc. All rights reserved. 27
    28. 28. CO2 Capture System on a Natural Gas Combined Cycle Plant – Bellingham, Mass. Photo from Google Maps Tanks for storing liquid CO2 Fin-fan coolers for capture system CO2 absorber vent Exhaust duct going to capture system Combined exhaust stack for two W501D gas turbines Captured ~100,000 tons/year for carbonated beverages – no longer in operation © 2014 Electric Power Research Institute, Inc. All rights reserved. 28
    29. 29. AEP-Alstom CCS Demo Project Overview • Alstom’s chilled ammonia CO2 post-combustion capture – ~20-MWe demonstration at AEP’s Mountaineer Plant in WV Alstom’s Chilled Ammonia Process at AEP’s Mountaineer – Designed for ~100,000 Property of Alstom Power and/or AEP tons-CO2/year – Injection occurred in saline reservoir using two on-site wells – Capture started in September 2009 and storage in October 2009; ~57,000 tons were captured and ~42,000 tons stored – Capture project was completed in May 2011 – Location of the injected CO2 continues to be monitored per AEP’s injection permit Power consumption was 22% less than generic amine technology © 2014 Electric Power Research Institute, Inc. All rights reserved. 29
    30. 30. Southern-MHI CCS Demo Project Overview • MHI KM-CDR advanced amine CO2 combustion capture post- – ~25-MWe demonstration at Alabama Power’s Plant Barry in AL MHI’s KM-CDR Process at Plant Barry – ~550 tons-CO2/day Property of MHI and/or Southern – Capture started on June 3, 2011; over 100,000 tons captured so far – Injection is occurring in the Citronelle dome ~10 miles away and started on August 20, 2012; goal of 100,000 tons reached in 2013 • EPRI’s role: – Manage collaborative, select and manage test contractors, develop test plan to perform capture testing, and document results – Leading the storage effort for DOE with ARI and Denbury © 2014 Electric Power Research Institute, Inc. All rights reserved. 30
    31. 31. Large CO2 “Capture-to-Storage” Projects in Operation Map courtesy Global CCS Institute (with additions by EPRI) ~10 projects worldwide – None at a power plant © 2014 Electric Power Research Institute, Inc. All rights reserved. 31
    32. 32. Large-scale CCS projects operating in North America 1. Weyburn EOR – CO2 from coal gasifier in ND, 2.8 million ton/yr Map & data from Global CCS Institute 2. Shute Creek EOR – CO2 from natural gas processing, 7 million ton/yr 1 3. Enid EOR – CO2 from fertilizer production, 0.7 million ton/yr 2 3 4. Val Verde EOR – CO2 from nat. gas processing, 1 million ton/yr 4 5 6 5. Century Plant EOR – CO2 from nat. gas processing, 8 million ton/yr All the current large-scale CCS projects use CO2 for Enhanced Oil Recovery (EOR) © 2014 Electric Power Research Institute, Inc. All rights reserved. 32 6. Port Arthur EOR – CO2 from steam methane reformer (US DOE project), 1 million ton/yr
    33. 33. Starting up in 2014 • Boundary Dam: 90% CO2 capture retrofitted to 150 MW coal power plant, ~1 million tons CO2 per year for EOR Map from Global CCS Institute Boundary Dam • Kemper County: new 582 MW IGCC with ~65% CO2 capture, ~3 million tons CO2 per year for EOR Kemper Both receiving large government subsidies. Will give power industry “real life” experience in operating large-scale CCS © 2014 Electric Power Research Institute, Inc. All rights reserved. 33
    34. 34. Summary of Issues Impacting Coal Power Around the World • Several countries now proposing CO2 emission limits for power plants that (nearly) match those of a natural gas fired combined cycle • Many Asian countries are strongly committed to continued use of coal for power and more inclined to try coal gasification • Several important coal-using nations have not found suitable storage sites for large amounts of CO2 • Public distrust of nuclear power may create demand for more coal power in some countries • Global economic slump has decreased electric power growth in developed countries – This limits opportunities to demonstrate new coal power technology including CCS © 2014 Electric Power Research Institute, Inc. All rights reserved. 34
    35. 35. Final Conclusion • In order to develop coal power technologies for the 21st Century, more collaboration is needed among the OECD nations and between OECD nations and the rapidly growing economies of the developing world – The developing economies need new coal power plants but are unwilling to pay extra for advanced technologies – Developed countries are willing to pay extra, but do not need new coal power plants – We all need to find secure places to store captured CO2 © 2014 Electric Power Research Institute, Inc. All rights reserved. 35
    36. 36. Together…Shaping the Future of Electricity © 2014 Electric Power Research Institute, Inc. All rights reserved. 36
    37. 37. Background Information
    38. 38. The View from China • 733 GW of installed coal power generation at end of 2011 • 890 GW planned by 2015 • 1500 GW anticipated by 2030 – This would be ~5 times current US coal power capacity • 222 coal gasifiers now installed in China – Almost all for non-power applications – 250 MW GreenGen IGCC is first gasification facility for power only – See polygen as way to meet variable demand for power • Higher efficiency is their CO2 “solution” for today – Goal of building 700ºC USC demo plant has been announced – Looking for “developed” countries to provide funding for CCS demos in China © 2014 Electric Power Research Institute, Inc. All rights reserved. 38
    39. 39. The View from Korea • World’s 2nd largest importer of coal for power (2010 data) • Increasing interest in coal gasification due to very high cost of LNG – Korea Western building a 300 MW IGCC (no CO2 capture) – IGCCs get 25% credit in renewable portfolio standard – POSCO building an SNG plant that will use sub-bituminous coal • Concerned about rising cost of internationally traded bituminous coal – Have significantly increased imports of sub-bituminous coal to try to offset cost increases – Interested in upgrading technologies for low rank coal (drying, briquetting, cleaning) • Official plan calls for coal power generation capacity to level out at 28 GW (~25 GW now) – However, “huge” public resistance to building more nuclear power plants, so more coal may to be added • Only suitable CO2 storage capacity appears to be offshore © 2014 Electric Power Research Institute, Inc. All rights reserved. 39
    40. 40. The View from Taiwan • With few domestic fuel options, Taiwan is dependent on energy imports including coal • Awarded contract for three new 800 MW SCPC units to replace two older (built in 1968) 300 MW coal units • Have roadmap to implement a CCS demo project – Currently characterizing site for storage – 10,000 ton pilot injection in 2014-15 – 100,000 ton demonstration in 2018-2020 – Goal to be ready for commercial scale CCS by 2025 © 2014 Electric Power Research Institute, Inc. All rights reserved. 40
    41. 41. The View from Australia • “Love-Hate” Relationship with coal – CO2 emissions price of A$23 per tonne began in 2012 for large emitters, but new prime minister wants to scrap the CO2 tax • Lack of growth in power demand means no one is building new power plants, so little opportunity for demonstrating CCS in near term • “Flagship” CCS projects have mostly stalled. No large scale coal CCS project under construction (though Gorgon LNG is a large CCS project) • Desire by coal-rich states to find new markets for their coal – Victoria intends to issue new allocations for brown coal mines, with no new power plants being built this means CTX or upgrading to briquettes © 2014 Electric Power Research Institute, Inc. All rights reserved. 41
    42. 42. The View from India • Ambitious plans for more generation capacity – Just under 200 GW now, want 600 GW additional by 2032 – Much of that will be coal • An extreme shortage of coal supply – Demand for coal growing at 10%/yr, domestic production growing at 5%/yr – Many power plants have only 1 day coal supply on site • Government has announced goal to build an 800 MW USC with 700ºC steam conditions – Will start testing components in existing PC soon • No plans for CCS demonstration © 2014 Electric Power Research Institute, Inc. All rights reserved. 42
    43. 43. The View from South Africa • Power generation shortfall remains very tight – Three mothballed power stations have been brought back into service – First unit of Medupi 6 x 700 MW SCPCs is expected to be commissioned in 2013 – Work on second 6 x 700 MW SCPCs has started • Government has announced aggressive goal for reducing CO2 emissions – 34% emission reduction below business as usual by 2020 and 42% by 2025.* – Published CO2 storage “atlas” in 2010. Small potential for storage inland. Majority offshore. All unproven. – No announced plans for a CCS demonstration. The South African Centre for Carbon Capture and Storage is considering a storage demonstration but nothing officially announced. • Work on underground coal gasification continues. – First gasifier has been successfully shutdown. Second gasifier started in 2012 and co-fires the gas into Majuba power station. *Note that these commitments were conditional on a fair, ambitious and effective outcome in the international climate negotiations in Copenhagen and on financial and technical support from the international community. © 2014 Electric Power Research Institute, Inc. All rights reserved. 43
    44. 44. The View from Germany • In July 2011 ~10 GW of new coal-fired power plants were under construction • “It is illegal to have a CCS project in Germany” – Lars Stromberg, former VP of R&D for Vattenfall – You cannot legally inject CO2 under German soil • No Nukes! • Strong subsidies for wind & solar – only provide 10% of generated power but represent ~50% of price of the “full basket” of electricity © 2014 Electric Power Research Institute, Inc. All rights reserved. 44
    45. 45. The View from UK • On-again, off-again large CCS demonstration program is “on again” – Last of the original candidates, Longannet, dropped out citing high cost of offshore transport & storage – Drax’s White Rose oxy-combustion project and a Shell/SSE natural gas combined cycle are the currently “preferred” projects – One billion pounds may be available for one of the projects • Any CO2 storage will occur offshore – At least one project looking at feasibility of EOR offshore • Proposed limit of 450 kg CO2/MWhr for new power plants © 2014 Electric Power Research Institute, Inc. All rights reserved. 45
    46. 46. The View from Canada • CO2 emission limit for new coal plants: • 420 kg/MWhr net • SaskPower’s Boundary Dam CCS project will be world’s only commercial coal power plant with 90% CO2 capture • Alberta’s ambitious CCS demo program has encountered difficulties – TransAlta’s Pioneer Project was canceled, $800 million subsidy & $15/ton CO2 emission “tax” not sufficient, Shell Quest oil sands upgrader a “go” • Ontario moving forward with phasing out coal power © 2014 Electric Power Research Institute, Inc. All rights reserved. 46

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