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Technical Support Document: Part 75 Monitoring and Reporting Considerations 

Draft 4/11/2014 

Table of Contents 

Background ................................................................................................................................................. 2

Monitoring of Electric Generation ............................................................................................................ 3

Equipment standards.................................................................................................................................4

Specification and frequency of quality assurance testing ......................................................................... 4

Proposed definition of net electric output................................................................................................. 4

Default apportionment of parasitic loads to multiple units....................................................................... 4

Monitoring of Non-electric Output at CHP units .................................................................................... 5

Reporting of Net Electric Generation and CHP Net Energy Output..................................................... 6

Reporting of Monitoring Plan Data and Quality Assurance Testing Data............................................ 7

Monitoring of Stack Gas Volumetric Flow Rate...................................................................................... 8

 
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Background 

This document provides additional information relating to the proposed Emission Guidelines for 

Greenhouse Gas Emissions from Existing Stationary Sources: Electric Utility Generating Units. 

It is intended to discuss topics regarding the monitoring and reporting of net output energy and 

stack gas volumetric flow rate at electric generating units (EGUs) for which the agency is 

seeking comments, as stated in the preamble of the proposal. 

As described in the preamble, the proposed emission guidelines would establish a rate-based 

emissions performance goal for each state on a net energy output basis. A state would have the 

option to translate the rate-based goal to a mass-based goal. Under either form of goal, CO2

emissions for affected EGUs would need to be reported to the EPA. In the case of plans with 

rate-based goals, net energy output would also need to be reported. State plans would need to 

require affected EGUs to monitor CO2 emissions, and net energy output if applicable, in 

accordance with 40 CFR Part 75. States would have the option of accomplishing the required 

reporting by requiring affected EGUs to report their hourly CO2 emissions, and hourly net 

energy output if applicable, directly to the EPA on a quarterly basis via the agency’s Emissions 

Collection and Monitoring Plan System (ECMPS). 

Currently, 40 CFR Part 75 requires monitoring and reporting of gross load (either electric or 

steam) for the main purposes of apportioning emissions to units that are monitored at a common 

stack and establishing load bins for data substitution procedures. As mentioned in the preamble, 

the EPA is proposing and taking comment on requiring states to use net energy output as the 

measure for any rate based emission standards. Options for addressing considerations associated 

with monitoring of net output are also discussed below. 

Part 75 does not currently include quality assurance requirements for monitoring and reporting of 

output (gross load or steam load) because it is presumed that the operator of an EGU would have 

the accurate monitoring of generation in its best interest and because the Acid Rain Program and 

other cap and trade programs require compliance on a mass basis and not a rate basis, so 

generation data is not necessary for compliance purposes. Under the proposed emission 

guidelines, reported energy output data would be used for compliance purposes. Therefore, 

quality assurance of output data is as important as quality assurance of emissions data. Options 

for quality assurance of these data are discussed below. 
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Additionally, the EPA is considering two approaches to improve the accuracy and consistency of 

stack gas volumetric flow measurements. Part 75 requires units that are not using Appendix D to 

report hourly stack gas volumetric flow data for the purpose of determining heat input and mass 

emissions. The associated quality assurance requirements include performance of Relative 

Accuracy Testing Audit (RATA) testing for stack gas flow meters, generally using standard 

Reference Method 2. Part 75 also provides alternative reference methods that are designed to 

reduce or remove over-reporting of gas flow by accounting for cyclonic flow and wall effects in 

stacks for units for which these conditions are present. The alternative methods are currently 

optional, but as noted in the preamble, the agency is considering whether they should be 

required. 

Monitoring of Electric Generation 

Electricity is used at power plants for a variety of purposes and this usage is commonly described 

as auxiliary or parasitic load. The EPA understands that electric generation and parasitic loads 

are universally measured at EGUs. The parasitic loads can include any of the following: electric 

motors used for pumps, fans, air compressors, coal handing equipment (such as conveyor belts 

and pulverizers), gas turbine starters, air pollution control equipment (such as electrostatic 

precipitators), and building use (such as lighting, air conditioning, computer systems, etc.). Gross 

generation is measured at the generator terminals (via current and potential transformers) enroute 

to the unit high voltage step up transformer, plant HV switchyard, and transmission into the 

electric grid. A unit auxiliary transformer typically steps down generator voltage to provide 

separately measured medium voltage electricity to in plant auxiliary/parasitic loads. Station 

service transformers typically provide separately measured electricity from the grid to plant 

auxiliary loads when the EGU is not in operation or is starting up. The EPA understands that 

steam boiler based plants typically have station service transformers, while combustion turbine 

based plants commonly do not have separate station service transformers and back-feed through 

unit and unit auxiliary transformers to measured auxiliary loads when the EGU is not operating 

or is starting up. Given that these measurements commonly occur at EGUs, the EPA understands 

that the equipment needed to convert gross generation to net generation on an hourly basis exists 

at all EGUs. 
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Equipment standards 

The EPA understands that there are several equipment standards including those that require 0.2 

accuracy meters and 0.5 accuracy meters. The American National Standards Institute (ANSI) has 

published an American National Standard for Electricity Meters – 0.2 and 0.5 Accuracy Classes 

(ANSI C12.20-2010) as well as a Code for Electricity Metering: ANSI C12.1-2008. The EPA is 

considering a specification of 0.2 accuracy class meters to determine net electric output (or gross 

electric output). Specification of certain equipment standards would ensure a level playing field 

regarding the minimum acceptable accuracy of equipment used to measure net electric 

generation while minimizing any additional burden of upgrading equipment used to measure net 

electric generation. ANSI C12.20 is one equipment standard the agency is considering. 

Specification and frequency of quality assurance testing 

The EPA understands that, on a regular basis, EGUs typically perform checks on their electricity 

meters to ensure that the equipment is operating as designed. The EPA is considering the 

specification of such checks and the frequency at which they are typically performed in order to 

ensure adequate net electricity measurement accuracy while minimizing additional burden of 

quality assurance testing procedures. 

Proposed definition of net electric output 

Under EPA’s proposed definition of net electric generation, the EPA is considering to treat grid 

supplied electricity (or other externally provided electricity) in a certain way that may be 

different from other definitions of net electricity. Specifically, the EPA is considering that grid 

supplied electricity (or other externally provided electricity) that is used at the station when the 

EGU has no gross generation (such as when the EGU is not operating or when the EGU is 

beginning to start up) would not be subtracted from the zero gross generation, which would 

prevent net generation from being negative at any given hour. This would effectively only 

subtract electricity that is used by the plant and that is derived from unit from gross generation. 

Default apportionment of parasitic loads to multiple units 

For plants that have more than one unit, apportionment of parasitic loads that share common 

auxiliary transformers would be necessary. As mentioned in the preamble, the EPA is proposing 

a default system of apportioning parasitic loads among multiple EGUs. The proposed default 

apportionment would be to apportion net generation to each unit at a facility that shares common 
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auxiliary transformers or a common bus to the grid by the gross generation of each of the 

generators. For combined cycle units, the gross generation of the steam turbine would be 

apportioned to each combustion turbine by the gross load of each combustion turbine, as 

currently described in the Part 75 Emissions Monitoring Policy Manual, question 17.2. There 

may be unique transformer and parasitic load configurations at a plant with multiple units where 

alternatives to the default apportionment procedure may be appropriate. For example, if two 

units share a common steam header and a common generator, there are not two gross generation 

values to apportion the net electric generation. Also, for example, if two units that share an 

auxiliary transformer have materially different equipment configurations, so that one unit has 

greater parasitic load than the other unit as a proportion of its gross generation, then the default 

apportionment of electricity usage based on gross generation to each of the units might not be 

appropriate. Therefore, as stated in the preamble to the proposal, the EPA intends to allow 

owners and operators of affected EGUs to propose alternative apportionment procedures for EPA 

approval given unique plant configurations. 

Monitoring of Non-electric Output at CHP units 

For affected EGUs that are combined heat and power (CHP) units (also known as cogeneration 

units), the combustion of fuel is used to provide both electric generation and other useful energy. 

Commonly, waste heat is captured and useful thermal output is provided for on-site use or sale. 

Thermal energy from CHP units can be used in direct process applications or indirectly to 

produce steam, hot water, hot air for drying, or chilled water for process cooling. Under the 

proposed rule, a CHP unit subject to a rate based standard would demonstrate compliance on a 

net energy output basis: net electric output and useful thermal output (converted into MWh 

equivalent) would be combined into net energy output. Therefore, for CHP units to demonstrate 

compliance with a rate based standard, the measurement of both net electric output and useful 

thermal output would be required. 

Mechanical energy from turbines can be used to drive rotating equipment, such as compressors, 

pumps and fans, and the exhaust of which may be routed through a heat recovery steam 

generator to generate electricity. Combustion turbines used for mechanical drive applications are 

typically used in the oil and gas industry. There may be a few such systems that meet the 

applicability requirements of the rule that would need to measure mechanical energy produced 
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for net energy output. The EPA is considering specification of equipment and equipment 

standards used to measure and record mechanical output on an hourly basis for reporting 

purposes. 

The measurement of useful thermal output in the form of steam involves the monitoring of steam 

pressure and steam flow (and in the case of superheated steam, steam temperature). However, 

there are several potential methods depending on whether the heat content of condensate or 

steam return is measured and other considerations. Please refer to “Developing and Updating 

Output-Based NOx Allowance Allocations: Guidance for States Joining the NOx Budget Trading 

Program under the NOx SIP Call”1

 for more details, specifically section VI, Monitoring 

locations: Where could facilities monitor electric and thermal output and subsection D, How 

could sources monitor electric and thermal output at a cogeneration facility. The EPA presumes 

that a CHP unit that sells useful thermal output would already be using equipment to measure the 

saleable product. The operation and calibration of equipment that measures pressure, temperature 

and steam flow leaving the unit and that measures the temperature and flow of returning 

condensate, or the pressure, temperature and steam flow of returning steam would be needed. 

The EPA is considering specification of best practices for the measurement and recording of 

useful thermal output and best practices regarding quality assurance protocols for such 

equipment to ensure consistent and accuracy reporting of useful thermal output while minimizing 

additional burden. 

Reporting of Net Electric Generation and CHP Net Energy Output 

In order to facilitate compliance with a rate based standard, the EPA is proposing that an affected 

EGU could report hourly net electric generation under 40 CFR Part 75 via ECMPS, which would 

be included in emissions reports submitted quarterly. A CHP unit would additionally report net 

energy output as calculated from net electric generation, useful thermal output and any other 

useful mechanical output. If a rate-based standard is based on gross energy output (rather than 

net), then an affected EGU would need to report gross electric output, and if a CHP unit, would 

need to also report energy output that includes useful thermal output. 

                                                            

1 http://www.epa.gov/airmarkets/progsregs/nox/docs/finaloutputguidanc.pdf
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Reporting of Monitoring Plan Data and Quality Assurance Testing Data 

The EPA is considering including the reporting of equipment used to measure net electric output 

(and net energy output for CHP units) in an EGU’s monitoring plan under 40 CFR Part 75. The 

current system for reporting monitoring plan data under 40 CFR Part 75 is ECMPS. The EPA is 

also considering including the reporting of the performance of tests on equipment used to 

measure net electric generation and net energy output for the purpose of determining whether the 

equipment is accurate or is operating as designed. If a rate-based standard is based on gross 

electric output (rather than net), then monitoring plan and quality assurance information 

pertaining to the measurement of gross generation would be considered. 

Monitoring of Stack Gas Volumetric Flow Rate 

Currently, under the Acid Rain Program, 40 CFR Part 75 requires units that are not using 

Appendix D to report hourly stack gas volumetric flow data for the purpose of determining heat 

input and mass emissions. During Relative Accuracy Testing Audits (RATA) testing for stack 

gas flow meters, Part 75 allows units to use either the standard Reference Method 2 or an 

optional method in order to increase the accuracy of and to minimize over reporting of CEMS 

stack gas volumetric flow data. EPA Reference Method 2 specifies the normal procedure for 

measuring stack gas volumetric flow rate during a flow RATA. Methods 2F, 2G, 2H and CTM041 are approved alternatives. Methods 2F and 2G correct measured flow rates for angular (nonaxial) flow, Method 2H (for circular stacks) and conditional test method CTM-041 (method J, for 

rectangular stacks and ducts) are used to correct measured flow rates for velocity decay near the 

stack wall, using a “wall effects adjustment factor”. 40 CFR Part 75 specifies that these 

alternative methodologies are optional. Therefore, there may be inconsistencies between 

emissions or heat input values when a unit changes the reference method used during flow 

RATAs, which could impact comparisons between emissions and heat input between time 

periods under which different reference methods are used. 

Because of these flexibilities regarding use of optional reference methods used in flow RATAs, 

the EPA is considering two approaches to ensure consistent and accurate accounting of stack gas 

volumetric flow measurements. The first approach the EPA is considering is the development of 

adjustment factors for normalizing data when the reference methods change. For example, if a 

unit transitions from Method 2 to Method 2H when performing flow RATAs, a percentage 
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reduction of baseline data could be applied. The second approach that the EPA is considering is 

requiring the use of the most accurate reference method taking into account the specific 

configuration of the stack.