U.S. Department of Energy National Energy Technology Laboratory July 2011

1. Cost and Performance Baseline for Fossil Energy Plants – Volume 2Coal to Synthetic Natural Gas and Ammonia U.S. Department of Energy National Energy Technology Laboratory July 2011

2. Disclaimer This presentation was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference therein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed therein do not necessarily state or reflect those of the United States Government or any agency thereof.

3. Objective • Determine cost and performance estimates of near-term commercial offerings for the production of synthetic natural gas (SNG) and ammonia both with and without CO2 sequestration. • Consistent design requirements • Up-to-date performance and capital cost estimates • Technologies built now and deployed in the near term • Provides baseline costs and performance • Comparison of study natural gas and ammonia prices with current market prices

4. Study Matrix 1 There is CO2 capture in every case, but CO2 is sequestered only in the even numbered cases PRB– Powder River Basin WTA – Fluidized bed dryer with integrated waste heat recovery (German)

5. Design Basis: Coal Type

6. Economic Assumptions for First Year Cost of Production First Year of Capital Expenditure 2007 Economic Analysis Period 35 years Dollars 2007 Coal ($/MM Btu) Illinois No. 6 1.64 PRB 0.89 Lignite 0.83 Capacity Factor (%) 90

7. Technical Approach Systems Analyses Categorization STUDY CATEGORY • Order of Magnitude Estimate (+/- >50% Accuracy) • Very little project-specific definition • Rough scaling of previous related but dissimilar analyses • “Back-of-the-envelope” analyses • Concept Screening (+/- 50% Accuracy) • Preliminary mass and energy balances • Modeling and simulation of major unit operations • Factored estimate based on previous similar analyses • Budget Estimate (+30% / -15% Accuracy) • Thorough mass and energy balances • Detailed process and economic modeling • Estimate based on vendor quotes, third-party EPC firms

8. Technical Approach • 1. Extensive Process Simulation (ASPEN) • All major chemical processes and equipment are simulated • Detailed mass and energy balances • Performance calculations (auxiliary power, SNG/ammonia production, gross/net power output) • 2. Cost Estimation • Inputs from process simulation (Flow Rates/Gas Composition/Pressure/Temp.) • Sources for cost estimation WorleyParsons Vendor sources where available • Follow DOE Analysis Guidelines

9. Study Assumptions • Capacity Factor assumed to equal Availability at 90% • The addition of CO2 capture, compression, and sequestration and an ammonia co-production facility was assumed not to impact the availability factor • Methanation system was modeled using Haldor Topsoe’s high temperature TREMP™ process • Ammonia reaction was modeled at 2,030 psia based on the Haldor Topsoe S-300 Ammonia Synthesis Loop • In CO2 sequestration cases, CO2 was compressed to 2,200 psig, transported 50 miles, sequestered in a saline formation at a depth of 4,065 feet and monitored for 80 years • CO2 transport, storage and monitoring (TS&M) costs were included in the first year cost of production (COP) for sequestration cases

10. SNG and SNG/Ammonia Plants

11. Siemens Gasifier • SNG production is based on nominal thermal input of 500 megawatt-thermal (MWth) to the gasifier. • Actual gasifier thermal input varies according to the type of coal feed and ranges from 506 to 550 MWth. • Heat Recovery includes a partial quench followed by a syngas cooler (This configuration is not currently a commercial offering by Siemens, but is planned for future coal-to-SNG projects) Source: Siemens

12. SNG Plant with CO2Capture (Sequestration in Cases 2,6, and 8*) • Emission Controls: • SOx: Selexol AGR removal of sulfur to < 6 ppmv H2S in syngas • Claus plant with tail gas recycle for ~99.8% overall S recovery • Hg: Activated carbon beds for ~95% removal • Steam Turbine:302 - 311 MW (Steam is produced primarily from syngas cooler and methanation process, but is not shown in BFD) • Steam Conditions:1800 psig/1050°F/1000°F *Note: Cases 5thru 8 do not have a COS hydrolysis reactor in the bypass stream

13. SNG/Ammonia Plant with CO2Capture (Sequestration in Case 4)

14. Performance Results 1 Assumes capacity factor of 90% 2 Conversion efficiency is HHVSNG/HHVcoal for SNG only cases and (HHVSNG + HHVNH3)/HHVcoal for co-production cases

15. Economic Results 1 Total Overnight Cost (Includes Total Plant Cost plus preproduction costs, inventory capital, financing costs, and other owner’s costs) 2 90% capacity factor and 24.49% first year capital charge factor

16. Environmental Performance Comparison

17. Criteria Pollutant Emissions for All Cases

18. Mercury Emissions for All Cases

19. CO2 Emissions for All Cases

20. Raw Water Withdrawal and Consumption Comparison

21. Raw Water Withdrawal and Consumption

22. Economic Results for All Cases

23. CO2 Avoided Costs

24. Plant Cost Comparison

25. Cost of Production Comparison

26. Highlights

27. NETL Viewpoint • Most up-to-date performance and costs currently available in public literature • Establishes baseline performance and cost estimates for current state of technology • Reduced costs are required to improve competitiveness of coal-to-SNG processes • In today’s market and regulatory environment • Also in a carbon constrained scenario • Ammonia co-production provides the most attractive SNG prices

28. Result Highlights: Efficiency & Capital Cost • HHV Conversion Efficiencies • Illinois No. 6: 61.3% to 61.5% • Powder River Basin: 63.1%* • North Dakota Lignite: 61.5% • Total Overnight Cost without Sequestration (MM$): • Illinois No. 6 SNG: $3,235 • Illinois No. 6 SNG/NH3: $3,742 • Powder River Basin SNG: $3,354 • North Dakota Lignite SNG: $3,504 • Total Overnight Cost with Sequestration (MM$): • Illinois No. 6 SNG: $3,313 • Illinois No. 6 SNG/NH3: $3,830 • Powder River Basin SNG: $3,442 • North Dakota Lignite SNG: $3,595 *PRB has the highest conversion efficiency of 63.1% primarily due to the low nitrogen and high oxygen content in the design fuel, which enables the SNG product to have a relatively lower concentration of inerts.

29. Results Highlights: FY COP • FY COP ($/MMBtu) without Capture: • Illinois No. 6 SNG: 19.27 • Illinois No. 6 SNG and NH3: 15.82 (NH3 = $799/ton) • Powder River Basin SNG: 19.15 • North Dakota Lignite SNG: 21.27 • FY COP ($/MMBtu) with Capture: • Illinois No. 6 SNG: 20.95 • Illinois No. 6 SNG and NH3: 17.85 (NH3 = $828/ton) • Powder River Basin SNG: 21.01 • North Dakota Lignite SNG: 23.24

30. Summary Table for All Cases

31. Summary Table

32. Fuel Quality

33. SNG Fuel Quality • The SNG produced in this study is at the low end of the acceptable quality range. • HHVs - 965-975 Btu/scf • Wobbe Indices -1,265-1,275 • Inert concentrations - 3-4.5 % • The primary reason for the lower quality product is the absence of higher hydrocarbons. • The quality of the SNG produced in this study could be enhanced with minor impact on overall cost by the following… • Increase the oxygen purity from 99% to 99.5%. • Upgrade the PSA by increasing the bed depth or adding beds in series. • Blend other gases into the pipeline to achieve a desired Wobbe Index value. • Purity requirements will be dictated by location and fuel end use.

34. Sensitivity to Financing Scenario

35. Sensitivity to ROE

36. Favorable Financial Structure Economic Pathway • Modify financing structure • Increase percentage of debt from 50% to 70% and decrease interest on debt from 9.5% to 4.5% • Increase loan repayment term from 15 years to 30 years • Decrease capital expenditure period from 5 years to 4 years • Reduce capital cost escalation during the capital expenditure period from 3.6% to 0% • Reduce owner’s cost from 23% to 18% • Reduce taxes and insurance in fixed O&M costs from 2% to 0.4% • Assume CO2 revenue value for enhanced oil recovery of $10/tonne

37. Technology Maturity Economic Pathway • Modify financing • Decrease interest on debt from 9.5% to 4.5% • Decrease required internal rate of return on equity from 20% to 12% • Reduce capital cost by 22% to reflect FOAK to NOAK improvements