November 4 & 5, 2015 Air Quality Committee

November 4 & 5, 2015 Air Quality Committee

November 4 & 5, 2015 Air Quality Committee & Environmental Management Commission Meetings Sushma Masemore, PE Department of Environmental Quality Standards of Performance for Existing Electric Utility Generating Units Under Clean Air Act (CAA) Section 111(d) 1. Recap of CAA Section 111(d) 2. Summary of U.S. Environmental Protection Agencys (EPA) Clean Power Plan Requirements (CPP) 3. DEQs 111(d) Plan Approach 4. Overview of Proposed 15A NCAC 02D .2700 Rules Department of Environmental Quality 2 Recap of CAA Section 111(d) State-based program for existing sources. There are 3 main steps: 1) EPA establishes guidelines that identify the best system of emission reduction (BSER) for the covered pollutant. The BSER must be adequately demonstrated, considering cost, energy needs, and secondary environmental impacts. 2) States design plans that establish a standard of performance and provides for implementation and enforcement. 3) State submits the plan to the EPA for approval. Department of Environmental Quality 3 Recap of CAA Section 111(d) What does the Statute Say? Section 111(d)(1) States submit a plan which:

Establishes standard of performance for existing sources Provides for implementation and enforcement of such standards Statute and regulations allow States to consider factors, such as: Remaining useful life of the existing source to which such standard applies EPA has the authority to prescribe a plan if the State fails to submit a satisfactory plan and to enforce the provisions of a plan in cases where the state fails to enforce them. Definition of standard of performance, CAA Section 111(a)(1) a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any non-air quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated. North Carolina 111(d) Principles document, January 2014, pgs. 10-11 Standard of performance applied on a unit specific basis; prohibits outside the fence approaches to establishing emission guidelines Department of Environmental Quality 4 Recap of CAA Section 111(d) How has EPA developed emission guidelines historically? CAA 111(d) and implementing regulations at 40 CFR Part 60, Subpart B 40 years of regulatory actions, 4 pollutants, 5 source categories General principles followed to determine BSER Degree of emission reduction achievable based on a demonstrated control technology Technical feasibility (considering age, size, type, class, facility design) Impact of demonstrated control technology on energy consumption, water pollution, waste disposal, and ambient air concentrations Cost of applying control technology Most importantly .

Each emission guideline established for emission points located within the facility, not any emission sources located outside of the facility. Department of Environmental Quality 5 EPAs Clean Power Plan Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units; Final Rule (80 CFR 64661-65120) Signed August 3, 2015 Published October 23, 2015 Effective December 22, 2015 Codified in 40 CFR Part 60, Subpart UUUU http://www2.epa.gov/cleanpowerplan/clean-power-plan-existing-power-plants Requires States to submit plans which reduce carbon dioxide (CO2) rates or mass emissions from affected electric generating units (EGUs) by 2030 relative to 2012 levels Contains EPAs guidelines for state plans based on the application of BSER Department of Environmental Quality 6 Affected EGUs in North Carolina Note: DEQ has determined that Elizabethtown and Lumberton Power should be excluded because they do not satisfy the applicability criteria under 40 CFR 60.5845 and 60.5850(a) (3), respectively.

Department of Environmental Quality 7 North Carolinas 2016 Plan Submittal: Overall Approach Develop a State Plan consistent with 111(d) and 40 CFR 60, Subpart B Determine BSER on a unit specific basis, within the fence line of the facility (BB1 type) CO2 reductions achieved through heat rate improvement (HRI) at each EGU BSER determined for 3 groups of affected EGUs Affected EGUs DEQs BSER Determination Explanation NGCC BSER is efficient operation and maintenance of combustion turbine and heat recovery steam generator using natural gas as fuel during normal operations. In the CPP, EPA found that the available emission reductions would likely be more expensive or too small to merit consideration as a material component of the BSER. Coal-fired units with announced retirement and/or conversion to natural gas BSER for Asheville Units 1 & 2 is no additional control based on remaining

useful life. NC Session Law 2015-110 requires Asheville Units 1 & 2 to retire by Jan. 31, 2020 and be replaced with new NGCC units. All other coal-fired units Source specific determination See next slides Department of Environmental Quality 8 North Carolinas 2016 Plan Submittal: Basis for Coal-Fired EGU BSER Determination Guiding Principles Decision Criteria 1 Adequately demonstrated What technology and/or work practices are currently available to improve heat rate in order to reduce CO2 emissions? 2 Ambient air concentrations Does the technology and/or work practices result in increases in non-GHG pollutants (e.g., SO2, NOx, and mercury)? 3

Technical feasibility Based on age, size, type, class, and design, can the technology and/or work practices be implemented at the EGU? 4 Non-air quality health and environmental impact and energy consumption Does the technology and/or work practices reduce water usage, solid waste production, etc.? Is there an adverse impact on energy consumption associated with the implementation? 5 Application of DAQ engineering judgement and sound science Recognize that: HRI will degrade with time due to normal wear and tear; HRI can vary greatly at part load operations; HRI for a combination of measures will be less than the sum of individual measures 6 Cost Is the average annual cost factor across project life 23 $/ton CO2 as determined by EPA to be reasonable? 7

Emission reduction What is the average expected heat rate improvement and CO2 reductions across project life considering forecasted operating capacity factor and degradation factor? Department of Environmental Quality 9 Potential BSER Measures 10 Potential Measure Abbreviation Controllable Loss Reduction (Maintain Unit Efficiency) CLR Intelligent Sootblowers ISB Air Heater Leakage Reductio n ALR Combustion Optimizatio n - CCM / Excess Air / Neural Network Online Condenser Cleaning CO OCC Induced and/or Booster DraftFan Variable Frequency Drive Air Heater Exit Gas Temperature Reductio n

IBD AHE Boiler Feed Pump Motor Driven Variable Frequency Drive BFP Induced DraftFan Replacement IDF Forced DraftFan Variable Frequency Drive FDF Condenser Rebundle, Retubes, and Rebuilds CRR Turbine Upgrades (HI, IP, LP) Helper Cooling Tower Sliding Pressure Operatio n Lower FGD Efficiency (as SO 2 permit limits allow) Flue Gas Desulfurization (FGD) Auxiliary Load Reduction through Variable Frequency Drives Electrostatic Precipitator (ESP) (Power management, T/R set upgrades) TUR HCT SPO LFGD FGDA ESP GenericMedium Diagram ofImage Coal-Fired Electric

Generating Unit ISB CO ALR 11 IDF FDF CRR Description of Proposed BSER Measures for Certain NC Coal-Fired EGUs 1) Air heater leakage reduction (ALR) Air heaters increase the temperature of pre-combustion air to improve combustion efficiency Typically designed as a rotating plate heat exchanger using hot exhaust gas complex high temp system Measure Replaces old seals with high performance seals to reduce leakage between combustion air/exhaust gas and improve heat transfer 2) Combustion optimization with neural network (CO) Refers to adjusting combustion process to maximize combustion efficiency and minimize emissions of air pollutants as boiler operating conditions change Measure employs an automated control system to adjust parameters based on a mathematical model called a neural network that utilizes both real-time and historical unit operating data Allows predictive control of process to improve combustion efficiency 3) Condenser rebundle, retube, rebuild (CRR) Condensers cool steam back into a liquid so it can be recycled to the boiler and improve thermal efficiency Measure repairs/replaces components to improve heat transfer and fluid flow in the condenser

Department of Environmental Quality 12 Description of BSER Measures 4) Controllable loss reduction (CLR) Measure consists of implementing a site-specific plan to collect data, evaluate performance, and take any required actions to improve boiler performance and heat rate Focuses on equipment/parameters not being tracked by existing data collection system Requires informing staff on the value and practice of collecting/reporting information on equipment performance and taking action 5) Forced/Induced draft fan variable frequency drive (FDF and IDF) Forced draft and Induced draft fans move combustion air and exhaust gas, respectively, through the boiler system Measure replaces fixed speed fans with variable frequency drive fans which can increase/decrease the fan speed in response to varying boiler operating conditions Allows for reduced fan power consumption when EGU is operated at less than full load 6) Intelligent soot blowing (ISB) Soot blowers use high pressure steam to remove slag deposits from heat transfer surfaces in boiler. Large boilers have ~200 soot blowers Measure employs an automated control system to monitor temperatures, evaluate heat transfer, and activate specific soot blowers as required, rather than at predetermined times Reduces the annual energy consumed for soot blowing and improve boiler efficiency Department of Environmental Quality 13 Example: Roxboro Unit 2 BSER Determination DEQ Assessment based on following unit specific information provided by EGU owner/ operator Baseline (2012) Operational Data Net Heat Rate (Btu/kWh) CO2 Emissions (tons/yr) Net Generation (MWh) Heat Input (million Btu/yr) Annual Capacity Factor

10,158 3,939,610 4,151,161 42,167,493 66.7% 10,078* 3,913,047* 3,583,308* 36,112,579* 57.0% Potential Measures CLR, SPO, LFGD, ISB, ALR, CO, OCC, IBD, AHE, FGDA, BFP, IDFR, FDF, CRR, ESP, TUR, HCT Capital and O&M costs per measure 2015 costs reported as confidential business information Adjusted to 2019 $s* Fuel Cost $3.84/million Btu reported by Duke Energy for 2014 Adjusted to 2019 fuel cost at $3.92/million Btu* Measure life and HRI degradation factor Confidential business information *Calculated by DEQ (see Supporting Basis document) 14

Future (2019) Example: Roxboro Unit 2 BSER Determination (Contd) Guiding Principles Small Chart DEQs Assessment 1 Adequately demonstrated 17 measures identified 1 measure removed - increased electric grid reliability risk due to boiler tube or drum damage and possible unstable operation 2 Ambient air concentrations 2 measures removed adversely impacts post combustion environmental controls 3 Technical feasibility 5 measures removed technically infeasible or negligible HRI opportunity 3 measures removed implemented prior to 2012 2 measures removed implemented between 2012 and July 31, 2015

4 Non-air quality health, environmental and energy impact None identified 4 measures remain (CLR, FDF, IBD and ISB) 15 Example: Roxboro Unit 2 BSER Determination (Contd) 5 6 7 Guiding Principles Small Chart Application of engineering judgment and sound science Performance of CLR can be reduced by half when used in conjunction with other measures Cost CLR FDF IBD

ISB Average annual cost factor 23 $/ton CO2 if implemented individually? If implemented with other measures? Yes No No Yes Yes Yes Yes Yes Cost effective BSER measures* Average annual cost effectiveness factor FDF, IBD and ISB $ 4/ton CO2 Total heat rate improvement (Btu/kWh) 80 CO2 emissions reductions (tons/yr) Percent reduction from 2012 baseline emissions 26,563 0.7% DEQ Conclusions *Also offers significant reductions in CO2 emissions.

16 DEQs Assessment BSER for Roxboro Unit 2 is FDF, IBD and ISB. Proposed BSER Measures for Coal-Fired EGUs Utility Company - Facility Unit ID BSER Measure Duke Energy - Asheville 1 none Duke Energy - Asheville 2 none Duke Energy - Belews Creek 1 CLR and FDF Duke Energy - Belews Creek 2 CLR and FDF

Duke Energy - Cliffside 5 none Duke Energy - Cliffside 6 ALR, CO, FDF and ISB Duke Energy - G G Allen 1 none Duke Energy - G G Allen 2 none Duke Energy - G G Allen 3 none Duke Energy - G G Allen 4 none

Duke Energy - G G Allen 5 none Duke Energy - Marshall 1 ISB Duke Energy - Marshall 2 ISB Duke Energy - Marshall 3 ALR, CO, FDF and ISB Duke Energy - Marshall 4 ALR, CO, FDF and ISB 1A & 1B none Duke Energy - Roxboro 1

none Duke Energy - Roxboro 2 FDF, IBD and ISB Duke Energy - Roxboro 3A & 3B ISB Example Duke Energy - Roxboro 4A & 4B ISB Edgecombe Genco - Battleboro 1 none Edgecombe Genco - Battleboro 2 none Westmoreland Partners - Roanoke Valley Energy Facility I 1

none Westmoreland Partners - Roanoke Valley Energy Facility II 1 none Duke Energy - Mayo 17 Rule Fiscal Impact Summary 23 Measures 18 Range in HRI Cumulative Reduction in HRI 26 80 Btu/kWh 0.4% (relative to 2012 baseline) Cumulative Reduction in CO2 Emissions 191,826 tons/yr 0.4% (relative to 2012 baseline) Cumulative Initial Capital Cost 2019 Capital Recovery Cost $ 51,818,929 $ 3,302,450 / yr 2019 O&M Cost $ 3,007,109 / yr

2019 Fuel Saving $ - 7,316,705 / yr 2019 Net Annual Cost $ - 1,007,146 / yr Net Fiscal Impact $ -5,888,000 Overview of Proposed 15A NCAC 02D .2700 Rules 15A NCAC 02D .2701 Purpose And Applicability Affected and excluded EGUs same as CPP Invalidates affected state rules if - all or any portion of 40 CFR 60 Subpart UUUU is (1) determined by court to be invalid or unconstitutional or stayed or (2) withdrawn, repealed, revoked or rendered of no force by the EPA, Congress or Presidential Executive Order. 15A NCAC 02D .2702 Definitions Affected EGUs BSER measures Performance parameters 19 Overview of Proposed 15A NCAC 02D .2700 Rules (Contd) 15A NCAC 02D .2703 Standards of Performance Requirements for Carbon Dioxide Unit specific BSER measures Coal Units - measures requiring technology implementation Follow manufacturers installation procedures and performance acceptance test procedures Follow on-going manufacturers maintenance requirements Coal Units - measures requiring work practices

Personnel responsible for operation of each measure follow manufacturers operating guidelines NGCC Units Operate and maintain combustion turbine with heat recovery steam generator using natural gas during normal operation according to manufacturer's recommended procedures Alternative BSER Affected EGU demonstrates to the Director application of alternative measures that would achieve an equivalent or greater HRI Requires Director approval Compliance Schedule implement BSER measure or alternative BSER by September 1, 2019 20 Overview of Proposed 15A NCAC 02D .2700 Rules (Contd) 15A NCAC 02D .2704 Permitting Permit application required to incorporate requirements into a Title V permit 15A NCAC 02D .2705 Monitoring, Recordkeeping and Reporting Coal Units - measures requiring technology implementation Maintain onsite installation procedures and performance acceptance test results for review by DAQ Maintain onsite records of completed maintenance activities for review by DAQ Coal Units - measures requiring work practices Maintain onsite records of operational procedures and documentation of forced or operational outages of the BSER measure NGCC Units Maintain onsite record of maintenance and operational procedures for review by DAQ Annual Compliance Report Operational data (heat input, net generation, heat rate) Performance data (carbon dioxide rate and mass emissions) 21

111(d) Plan Schedule 9/9/15 EMC briefing 11/4/15 Draft rules 111(d) Plan to AQC & 30-day waiver request 11/5/15 Request to EMC to proceed to public hearing & 30-day waiver request 11/16/15 Public comment period begins Dec. 2015/Jan. 2016 Public hearings 1/15/16 End of comment period 2/2016 Hearing Officers report to EMC for consideration By 2/22/16 File with RRC 3/17/16 RRC action 4/1/16

Effective date (if < 10 objections) ~mid-May through June 9/6/16 22 - potential Legislative review Deadline to submit plan to EPA Thank you. Questions? 23 Additional Reference Material Department of Environmental Quality 24 EPAs BSER Determination System = integrated network of electrical grids that connect power generating sources with transmission and distribution sources Enables BSER to be applied outside the existing electric generating units that actually produce the CO2 emissions BSER applied to 3 interconnections BSER based on 3 building blocks BB1: Heat Rate Improvement inside the fence line BB2: Shift generation from coal to 75% natural gas combined cycle (NGCC) capacity level BB3: Shift generation from coal and NGCC to renewable resources Emissions Standards in State Plans must be satisfied through one of the following:

1 Uniform emission performance rate for: 2 3 Fossil Steam (Coal + Oil) units NGCC units State rate goal State mass goal Department of Environmental Quality 25 North Carolinas Interim and Final Targets In EPAs Clean Power Plan 1 Uniform Emission Performance Rate (lb/MWh) NCs 2012 Baseline Rate 2 2,054 1,534 1,305 NGCC 853 832

771 North Carolina Rate Goal (lb/MWh) NC Aggregate Interim Rate Goal: 2022-2029 1,778 1,311 Final Rate Goal: 2030 1,136 North Carolina Mass Goal (annual tons) NCs 2012 Baseline Emissions NC Aggregate 58,353,477 Department of Environmental Quality 26 Final Performance Rate: 2030 Fossil Steam

NCs 2012 Baseline Rate 3 Interim Performance Rate: 2022-2029 Interim Mass Goal: 2022-2029 56,986,025 Final Mass Goal: 2030 51,266,234 Key Compliance Dates In EPAs Clean Power Plan Sept. 6, 2016 Final Plan or Initial Submittal (with request for extension) Sept. 6, 2017 Initial Submittal update due if extension granted Sept. 6, 2018 Final Plan due if extension granted July 1, 2021 Milestone status report due 2022-2029: Interim goal to be achieved July 1, 2025: meet Interim Step 1 Goal for 2022-2024 July 1, 2028: meet Interim Step 2 Goal for 2025-2027 July 1, 2030: meet Interim Step 3 Goal for 2028-2029 2030: Final goal to be achieved July 1, 2032 and every 2 years beyond Department of Environmental Quality 27 State Plan Options In EPAs Clean Power Plan Must define whether the state will achieve: Federal emission performance rates or State rate-based goal or State mass-based goal

Choose between 2 types of Plans Emissions Standards Plan Performance Rate State Rate-Based State Measures Plan Mass-Based Regulates only the owners/operators of covered EGUs EGUs must meet their required performance rate or state-specific ratebased goal Similar to other Clean Air Act programs Consists of federally enforceable or combination of federally enforceable and state only enforceable requirements Must result in EGUs meeting the EPAs or states mass-based goal

Must be quantifiable, verifiable, enforceable, non-duplicative and permanent States can impose requirements on non-EGUs through state law (e.g., renewable energy, energy efficiency) If state measures dont perform as planned, federally enforceable backstop (e.g., final model rule) kicks in Department of Environmental Quality 28

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