Renewable Power to Minimize Risk and Reduce Utility Costs

Transcription

1 Renewable Power to Minimize Risk and Reduce Utility Costs

2 Introduction of the Speaker Tom Parker, PE Vice President, Carter & Burgess, Energy & Power Solutions

3 Background Wood products manufacturer consisting: Building products manufacturing facility Lumber mill Utilities required Steam (process and comfort heating) Electricity Gas (direct fired drying kilns)

4 Background Current Operations: Steam Provided by three stoker type boilers 120,000 lb/hr at 600 psig Further subdivided as follows» 30,000 lb/hr of 600 psig» 90,000 lb/hr of 300 psig 110,000 lb/hr at 200 psig Equipment age various (5-30 years)

5 Background Current Operations: Gas Purchased from local provider Approximate demand 93 MMBTU/hr Used in the kilns as part of the product drying process Electricity Purchased from local provider Approximate peak demand MW Provided base load of MW Deregulated power price base on market clearance price (MCP)

6 Purpose of Analysis Due to sharp increase in purchased electricity cost, study was undertaken to investigate self-generation of electricity to offset the increased cost of purchased electricity and to allow for continued profitable operation of the facility.

7 Study Parameters Investigate self power generation Exclusively power generation Generation with additional steam generated to satisfy process loads Generation with waste heat used to supply the dryer kilns 18% Internal Rate of Return Investigate incentives associated with renewable fuels

8 Study Parameters Cost of fuels Wood waste (wet) first 370,000 tons (generated on-site) - $0.00 Purchased wood waste (wet) next 220,000 tons - $10 / ton Purchased wood waste (wet) remaining tonnage - $21 / ton Purchased wood waste (dry) - $25 / ton Natural Gas - $10.00 / MMBTU (HHV) Electricity - $75.00 / MWH Included sensitivity analysis for both gas and electricity pricing variation

9 Options Analyzed Install Reclaimed Renewable Power Generation Facility Install New Renewable Cogeneration Facility Install Natural Gas Fired Combustion Turbine

10 Option A: Reclaimed Power Generation Facility 22 MW coal fired power generating facility Stoker type boiler Unit to be dismantled at present location, shipped to new location and reassembled Unit to retrofitted to fire dry wood waste HHV = 8,600 BTU/lbm Utilize condensing steam turbine to generate electricity New output to be 17MW DN wood baseload Continue use of existing boilers for process steam

11 Option A: Reclaimed Power Generation Facility Pros Reduced capital cost Ability to utilize renewable fuel Good fit with respect to electrical load (i.e. does not require selling back to the grid) Shortest lead time with respect to implementation

12 Option A: Reclaimed Power Generation Facility Pros Reduced capital cost Ability to utilize renewable fuel Good fit with respect to electrical load (i.e. does not require selling back to the grid) Shortest lead time with respect to implementation

13 Option A: Reclaimed Power Generation Facility Cons Increased maintenance associated with older equipment Reduced efficiency associated with older equipment Existing boilers to remain to handle process steam load Natural gas still required for use in Kilns

14 OPTION A: Reclaimed Power Generation Facility

15 Option B New Cogeneration Facility Single Circulating Fluidized Bed (CFB) boiler Fuel source would be wood waste (wet or hogged ) Dual-extraction condensing steam turbine to provide both power and process steam CFB boiler would replace the existing process steam boilers

16 Option B New Cogeneration Facility Pros Ability to utilize renewable fuel Greater fuel flexibility of CFB technology Good fit with respect to electrical load Allowed for decommissioning of existing process boilers Cons Highest capital cost Natural gas still required for use in Kilns Long lead time for implementation

17 OPTION B: New Cogeneration Facility

18 Option C Natural Gas Fired Combustion Turbine Basis of design GE LM2500PE MW combustion turbine Waste heat sufficient to offset the 93MMBTU/H currently required in the drying kilns. No steam produced as part of the cycle.

19 Option C Natural Gas Fired Combustion Turbine Pros Reduced capital cost Simpler installation Good fit with respect to electrical load Sufficient waste heat to offset the 93MMBTU/H required in the kilns Cons No ability to utilize renewable fuel Existing boilers need to remain to satisfy process steam load Less familiar technology to existing plant

20 OPTION C: GAS TURBINE USING WASTE HEAT IN DRYER KILNS

21 Incentives Various Incentive programs were investigated for applicability to the analyzed options Grants Biomass Research and Development Initiative Energy Efficiency, Research, Development, Demonstration, Deployment, and Rebuild America Projects Tax Incentives Renewable Electricity Production Credit Rebates Advanced Power System Technology Program

22 Incentives - Results Grants Rebates Not applicable due to the lack of new technology being used This program is still being developed and funding still needed to be appropriated by Congress.

23 Incentives - Results Tax Incentives The tax incentive for producing electricity through the use of bio-based fuels seemed to hold some promise. Current tax credit for open-loop biomass providers is 0.9 cents per kilowatt-hour Applicable for first 10 years of operation Biggest issue This tax incentive can only be applied to taxpayers that produce the electricity and sell it to an unrelated person / entity. Resulted in investigating third party participation Life cycle analysis were performed with and without the benefit of the tax incentives

24 Results A life cycle analysis was performed and compared to baseline operations (no changes): 20 year period Capital costs Energy costs (7.5 /kwh and $10/MMBTU)- conservative Operations & Maintenance costs Marginal discount rate (18 percent) Escalations for both energy costs and O&M costs were also included Life cycle analysis was performed both with and without incentives Sensitivity analysis performed Electricity varied from 6 /kwh to 11 /kwh Gas varied from $8/MMBTU to $12/MMBTU

25 Results LCC w /o incentives

26 Results LCC w /o incentives $160 M $140 M $120 M $100 M $80 M $60 M $40 M $20 M BASELINE OPTION A OPTION B OPTION C $0 M Discount rate of 18% built-in

27 Results LCC w / incentives

28 Results LCC w / incentives $140 M $120 M $100 M $80 M $60 M $40 M $20 M BASELINE OPTION A OPTION B OPTION C $0 M Discount rate of 18% built-in

29 Conclusions Within the financial constraints of the study, option A meets all the requirements when tax incentives are included. Without tax incentives, Option A begins to overcome the baseline option just past year 20 of the study. We are currently exploring a deal with a third party to build, own and operate the Option A plant and guarantee electrical rates to facilitate profitable operations for the future

30 Questions