### From: Wayland, Robertj [mailto:Wayland.Robertj@epa.gov]

Sent: Friday, April 18, 2014 5:35 PM

To: Higgins, Cortney

Cc: Culligan, Kevin; Tsirigotis, Peter; Srivastava, Ravi
Subject: RIA Briefing and Reg Text for 111(b) Rule

Cortney -

Attached to this email, please find the PowerPoint briefing for Monday's discussion of the RIA, and the regulatory text TSD for the 111(b) mods/recon package. If you have any questions, please free to give me a call on my cell (919-306-2290). Hope you have a nice Easter weekend - talk with you on Monday morning.

bob Robert J. Wayland, Ph.D. Leader, Energy Strategies Group U.S. Environmental Protection Agency Office of Air Quality Planning and Standards Sector Policies and Programs Division
Mail Code D243-01 Research Triangle Park, North Carolina 27709

Office: (919) 541-1045 Cell: (919) 306-2290 Fax: (919) 541-5450

Email: wayland.robertj@epa.gov

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DRAFT/Deliberative Document - FOIA EXEMPT

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<< EGU GHG RIA Briefing 04_18_14 OMB.pptx >> << Reg Text TSD to OMB 18 April 2014.docx >>Deliberative – Do Not Cite or QuoteGreenhouse GasElectric Generating Unit Existing/ Modified/Reconstructed Source ProposalRegulatory Impact Analysis (RIA)BriefingforInteragencyReviewGroupApril21,2014Deliberative – Do Not Cite or QuoteOutline►RIA overview►Control strategies, emission reductions, and costs►Control strategies►Emission reductions►Costs►Economic Impacts for the electricity sector and fuel sectors►Benefits►Net benefits►Upstream methane emissions►Economic impacts for sectors outside the electricity market (e.g.,industrial electricity customers)►Employment impacts►Statutory and Executive Order analyses►Modified and reconstructed source standards2Deliberative – Do Not Cite or QuoteRIA Overview►The RIA presents illustrative benefits, costs and economic impacts of actionsstates may take to comply with the greenhouse gas electric generating unit(GHG EGU) emission guidelines.►Base Case►Include relevant promulgated regulations (MATS, CAIR, etc.) and other actions takensuch as regional haze, but does not includeNAAQS or the replacement for the CrossState Rule.►Two regulatory alternatives are analyzed:►Option 1•Proposed option – more stringent•Compliance by 2030►Option 2•Regulatory alternative – less stringent•Compliance by 2025►Two compliance approaches are analyzed for each option•Regional compliance - assumes states collaborate•State compliance - assumes statescomply on a state specific basis►Three analysis years – 2020, 2025, and 2030. All estimates are shown in 2011$►Addresses relevant Executive Orders and statutory requirements such as EO12866, EO 13563, small business impacts, unfunded mandates, and others.►One RIA for existing source/modified & reconstructed source rulemakings3Deliberative – Do Not Cite or QuoteControl Strategies and Costs►Modeling is done using IPM and other tools, to estimateemission reductions and costs of the 111(d) guideline (andpotential alternatives)►Similar in scope to all past power sector air regulations, withadded complexities unique to 111(d)►Detailed power sector impacts from IPM are included in RIA(e.g., coal and gas markets, electricity prices, generation mix,retirements, etc.)4Deliberative – Do Not Cite or QuoteBuilding Block Technologies Translated to State GoalsTechnology/Building BlockOption 1 Option 21. Heat rate improvement (Avg.Reduction for Coal)6% 4%2. Dispatch to existing and underconstruction NGCCUtilization of NGCCup to 70% capacity factorUtilization of NGCCup to 65% capacityfactor3. Dispatch to new clean electricgenerationIncludes nuclear under construction and “at risk,”moderate deployment of new renewable generation4. Demand-side Energy Efficiency(% reduction in demand from BAU MWhsales)3.0% / 10.7%(2020 / 2030)2.4% / 5.2%(2020 / 2025)5Deliberative – Do Not Cite or Quote1,5001,7001,9002,1002,3002,5002,7002000 2005 2010 2015 2020 2025 2030BaseCaseOption1‐RegionalOption1‐StateOption2‐RegionalOption2‐StatePower Sector CO2Emissions(million metric tonnes)6Note: Historical data from EPA’s GHGinventory, projections from IPM.CO2Emissions (MM Tonnes)CO2Emissions Reductions:from 2005 (MM Tonnes)CO2Emissions Reductions:Percent Change from 20052020 2025 2030 2020 2025 2030 2020 2025 2030Base Case 2,161 2,231 2,256273 203 17811% 8% 7%Option 1 Regional 1,790 1,730 1,711644 704 72326% 29% 30%Option 1 State 1,777 1,724 1,701657 710 73327% 29% 30%Option 2 Regional 1,878 1,862 1,903556 572 53123% 23% 22%Option 2 State 1,866 1,855 1,882568 579 55223% 24% 23%Deliberative – Do Not Cite or Quote►Annual costs (billions of 2011$)►National average retail electricity prices►Option 1: Roughly 6-7% increase in 2020 and 2-3% in 2030►Option 2: Roughly 3-4% increase in 2020 and 1-2% in 2030►National average impact on electric bills►Option 1: Roughly 3% increase in 2020, but 9%lowerby 2030►Option 2: Roughly 1-2% increase in 2020, but 7%lowerby 2030Economic Impacts (vs. Base Case)72020 2030Option 1 – Regional 5.4 7.3Option 1 – State 7.4 8.8Option 2 – Regional 4.2 1.9Option 2 – State 5.4 3.1Deliberative – Do Not Cite or Quote►Retirements, by 2020►Option 1: 50 GW of additional coal retirements, up to 17 GW O/G steam►Option 2: 30 GW of coal, 12 GW of O/G steam►Coal Capacity (Net Summer: 310 GW existing in 2012, about 240 GW in 2030 Base Case)►Option 1: 191 GW to 198 GW remaining in service (2020-2030)►Option 2: 208 GW to 214 GW remaining in service (2020-2030)►Capacity Changes►Option 1: 20-22 GW additional NGCC by 2020,but 32-35 GW less than Base Case by2030, and 8 to 12 GW of new renewables►Option 2: 9 to 14 GW of additional NGCCby 2020, 26 to 31 GW less than Base Caseby 2030, and 6 to 9 GW of new renewables►Coal Production (national)►Option 1: 25% to 27% lower production and16% to 18% decrease in prices (2020-2030)►Option 2: 19% to 21% lower production androughly 14% decrease in prices (2020-2030)►Natural gas price (delivered, power)►Option 1: Roughly 9% to 12% increase in 2020 and negligible changes by 2030►Option 2: Roughly 7% to 8% increasein 2020, and negligible changes by 2030Other Impacts (vs. Base Case)8Deliberative – Do Not Cite or QuoteOverview of Benefits Analysis►Climate benefits of CO2reductions estimated using the mostrecent estimates of the global Social Cost of Carbon (SCC)►Health co-benefits estimated using regional benefit-per-tonestimates derived from EGU sector modeling published by Fannet al. (2012)►PM2.5and precursors (SO2, NOx, directly emitted PM2.5)•Same epidemiology studies and census data as 2012 PM NAAQS RIA►Ozone•Same epidemiology studies as 2010 Ozone NAAQS RIA•Assumes impacts from NOx alone because little VOC from EGUs►Qualitative benefits and co-benefits►Climate impacts of non-CO2pollutants►Health effects from direct exposure to NO2, SO2, and HAP►Visibility impairment►Ecosystem effectsDeliberative – Do Not Cite or QuoteMonetized Benefits for Options 1 and 2Option and ComplianceApproachNational Emission Reductions from Base CaseMonetized Benefits(billions of 2011$)2020 2025 2030 2020 2025 2030Option 1StateClimate Benefits* CO2: 383 MMT CO2: 506 MMT CO2: 555 MMT$18($4.9-$52)$25($7.6-$77)$31($9.5-$94)Health Cobenefits**SO2: 335,000 tonsNOX: 367,000 tonsSO2: 425,000 tonsNOX: 436,000 tonsSO2: 471,000 tonsNOX: 428,000 tons$15 to $36 $22 to $51 $25 to $58Option 1RegionalClimate Benefits* CO2: 371 MMT CO2: 501 MMT CO2: 545 MMT$17($4.7-$51)$25($7.5-$76)$30($9.3-$92)Health Cobenefits**SO2: 292,000 tonsNOX: 345,000 tonsSO2: 395,000 tonsNOX:421,000 tonsSO2: 424,000 tonsNOX: 407,000 tons$15 to $34 $21 to $50 $24 to $55Option 2StateClimate Benefits* CO2: 295 MMT CO2: 376 MMT CO2: 373 MMT$14($3.8 -$40)$19($5.6-$57)$21($6.4-$63)Health Cobenefits**SO2: 267,000 tonsNOX: 281,000 tonsSO2: 327,000 tonsNOX: 317,000 tonsSO2: 321,000 tonsNOX: 274,000 tons$12 to $29 $16 to $38 $17 to $39Option 2RegionalClimate Benefits* CO2: 283 MMT CO2: 368 MMT CO2: 353 MMT$13($3.6-$39)$18($5.5-$56)$20($6.0-$60)Health Cobenefits**SO2: 244,000 tonsNOX: 268,000 tonsSO2: 297,000 tonsNOX: 309,000 tonsSO2: 287,000 tonsNOX: 252,000 tons$12 to $28 $16 to $37 $16 to $37* Climate benefits are calculated with average SCC at a 3% discount rate, the value deemed central by the interagency workinggroup; climate benefits using additional SCC estimates (avg. SCC at 5% and 2.5%; 95thpercentile at 3%) are reported as a rangein parentheses; climate benefits reflect only changes in CO2emissions.** Health co-benefits are shown at a 3% discount rate and calculated using regional benefit-per-ton estimates; co-benefits at a7%discount rate are approximately 9% lower; co-benefits from reductions in directly emitted particles are not yet available; health cobenefits reflect reduced exposure to ambient PM2.5from emission reductions of SO2and NOx and reduced exposure to ambientozone from emission reductions of ozone-season NOx; range reflects different epidemiology studies; monetized co-benefits do notinclude additional co-benefit categories, including direct exposure to SO2, NO2, or HAP; ecosystem effects; or visibility impairment.10Deliberative – Do Not Cite or QuotePreliminary Net BenefitsOptionandComplianceApproachNetBenefits(billionsof2011$,3%discount rate)*2020 2025 2030Option1State $26to$46 $41to$70 $47to$80Option1Regional $26to$46 $42to$70 $47to$78Option2State $20to$37 $30to$52 $34to$57Option2Regional $21to$37 $30to$51 $33to$5511* Includes central climate benefits and health co-benefits at a 3% discount rate; benefits estimated usingadditional discount rates would show abroader range; benefits shown here arerounded to two significant digits,so net benefits may not sum from previous slides•Net benefits are positive for all combinations of costs and total monetized benefits(climate plus health)•Climate benefits alone often exceed costs•Climate benefits alone exceed costs using a 3% discount rate for bothcompliance approaches for both options in all analysis years•Climate benefits alone exceed costs using any discount rate for bothcompliance approaches for both options in 2025 and 2030•Option 1 net benefits exceed Option 2 inall years analyzed. Net benefits areroughly equivalent between state and regional approaches within the optionsDeliberative – Do Not Cite or QuoteChanges in Upstream Methane Emissions►RIA presents supplementary analysis of potential implications for coal and natural gassector methane emissions in appendix to Cost, Economic, and EnergyImpacts chapter.►IPM results indicate decreases in coal production and smaller increases or decreases innatural gas production (dependingon year) as a result of the compliance scenarios.►IPM coal and natural gas production resultsinput into emissions projection modelsdeveloped for EPA submission to the US Climate Action Report to estimate changes inupstream methane emissions and CO2emissions from natural gas flaring.►Upstream defined in this analysis as being from the mine or well to the power plant.►Overall results:►Net reduction in upstream methane emissions and CO2emissions from gas flaring►Magnitude is small relative to the emissions changes at power plants12ChangeinupstreammethaneemissionsandCO2emissionsfromnaturalgasflaring (MM TonnesCO2‐eq.)2020 2025 2030Option 1‐Regional‐9.9‐16.0‐19.8Option1‐State‐10.6‐16.4‐20.5Option 2‐Regional‐7.4‐11.4‐13.8Option2‐State‐7.7‐11.8‐14.4Deliberative – Do Not Cite or QuoteImpacts Outside the EGU Sector►Addresses the ripple effect of energy price changes (electricity,natural gas, coal) through the economy for sectors other thanthe EGU sector►The best way to analyze impacts on the economy is by using adynamic computable general equilibrium (CGE) model, but theadvice from the Science Advisory Board (SAB) panel formedspecifically to address the subject of economy-wide modelingwill not be available in time for this proposal►This RIA only discusses these impacts qualitatively andemphasizes the flexibility states will have to mitigate impacts, ifnecessary13Deliberative – Do Not Cite or QuoteGHG Existing Source Employment ImpactsAnalysis Overview►The RIA will primarily discuss the employment impacts for theseguidelines based on the four building blocks.►Qualitative•Peer reviewed literature– “Economic theory predicts that the totaleffect of an environmental regulationon labor demand in regulated sectors isnot necessarily positive or negative.– Peer-reviewed econometric studies suggest whether positive or negative,impacts have been small and have not affected employment in the regulatedsectors in a significant way.”– There is evidence suggesting environmental regulation may improve laborsupply and productivity.•Historical trends in employment inthe power, coal and natural gas sectors•Recent historical trends in clean energy employment►Quantitative•Partial potential impacts of supply side and demand-side employment estimates– Job estimates in the EGU, coal and natural gas sectors based onengineering-cost information for a subsetof possible employment impacts isprovided (similar to MATS analysis)– Demand-side energy efficiency employment estimates based partly onBureau of Labor Statistics and the AnnualSurvey of Manufacturers data.14Deliberative – Do Not Cite or QuoteEmployment Impacts - Regional Compliance Approach15CategoryOption 1 Option 22020 2025 2030 2020 2025 2030Supply Side – Quantified ImpactsHeat Rate Improvement32,900 0 0 33,900 0 0Boilermakers and General Construction 22,800 0 0 23,600 0 0Engineering and Management 6,000 0 0 6,200 0 0Equipment-related 2,900 0 0 3,000 0 0Material-related 1,100 0 0 1,100 0 0New Capacity Construction24,200 -33,300 -37,000 10,600 -23,100 -29,600Renewables 17,500 -4,700 -2,100 9,500 -3,100 -4,000Natural Gas 6,700 -28,600 -34,900 1,100 -20,000 -25,000Operation and Maintenance-22,900 -23,800 -23,700 -15,300 -15,500 -16,600Changes in Gas 2,300 -600 -3,400 1,000 -1,000 -3,900Retired Coal -22,600 -20,800 -18,200 -14,600 -13,100 -11,500Retired Oil and Gas -2,600 -2,400 -2,100 -1,700 -1,400 -1,200Fuel Extraction-8,800 -14,900 -19,200 -6,600 -10,600 -13,300Coal -13,700 -17,000 -16,60010,900 -12,900 -10,300Natural Gas 4,900 2,100 -2,600 4,300 2,300 -3,000Supply Side Employment Impacts –Total (job-years)25,400 -72,000 -79,000 22,600 -49,200 -58,600Demand Side – Quantified Impacts*Energy Efficiency EmploymentImpacts –Total (jobs)*78,800 112,000 111,800 57,000 76,200 77,200Unquantified - Other Employment Impacts• Other additional direct and indirectlyrelated jobs in the manufacturing andmaterials sectors.• Additional upstream and downstream effectsof EE investments (e.g., changes indemand for steel, increased spendingin non-energy categories).*Estimatesmaychangependingadditionalanalysis.Estimatesmaynotsumduetorounding.Deliberative – Do Not Cite or QuoteEmployment Impacts - State Compliance Approach16CategoryOption 1 Option 22020 2025 2030 2020 2025 2030Supply Side – Quantified ImpactsHeat Rate Improvement32,200 0 0 30,800 0 0Boilermakers and General Construction 22,400 0 0 21,400 0 0Engineering and Management 5,900 0 0 5,700 0 0Equipment-related 2,900 0 0 2,800 0 0Material-related 1,000 0 0 1000 0 0New Capacity Construction21,900 -38,000 -36,100 15,800 -29,500 -25,300Renewables 12,200 -8,900 -2,200 8,000 -6,300 -2,400Natural Gas 9,700 -29,100 -34,000 7,800 -23,200 -22,000Operation and Maintenance-24,100 -25,300 -24,900 -16,800 -17,100 -16,800Changes in Gas 2,500 -500 -3,200 1,500 -800 -2,600Retired Coal -24,000 -22,500 -19,700 -16,400 -14,800 -12,900Retired Oil and Gas -2,600 -2,300 -2,000 -1,900 -1,500 -1,300Fuel Extraction-8,300 -14,600 -19,400 -6,500 -10,300 -13,400Coal -14,300 -17,800 -18,000 -11,500 -13,500 -11,600Natural Gas 6,000 3,200 -1,400 5,000 3,200 -1,800Supply Side Employment Impacts –Total (job-years)21,700 -77,900 -80,400 23,300 -56,900 -55,500Demand Side – Quantified Impacts*Energy Efficiency EmploymentImpacts –Total (jobs)*78,800 112,000 111,800 57,000 76,200 77,200Unquantified - Other Employment Impacts• Other additional direct and indirectlyrelated jobs in the manufacturing andmaterials sectors.• Additional upstream and downstream effectsof EE investments (e.g., changes indemand for steel, increased spendingin non-energy categories).*Estimatesmaychangependingadditionalanalysis.Estimatesmaynotsumduetorounding.Deliberative – Do Not Cite or QuoteStatutory and Executive Orders►Substantial outreach was undertaken with small entities, local, state andtribal governments, the business community and the public►Proposed guidelines do not impose requirements on small entities and willnot impose a significant economic impact on a substantial number of smallentities, because states establishstandards on existing sources afterguidelines are promulgated►Proposed guidelines do not have federalismimplications (substantial directcompliance costs on state or local governments) and do not contain afederal mandate for state, local or tribal governments or the private sector(UMRA), because the guidelines do notimpose any direct compliancerequirements on regulated entities►Action is a “significant energy action”►Proposed guidelines will reduce CO2, SO2, NOx, PM2.5, HCl and Hgemissions. Generally considered tobe beneficial to all communities, butstates will make the ultimate compliance decisions►Paperwork Reduction Act analysis to estimate monitoring, reporting andrecordkeeping costs is still in progress17Deliberative – Do Not Cite or QuoteModified and Reconstructed Source Standards►Based on historical information, theEPA anticipates few, if any, coveredunits will trigger the reconstruction or modification provisions. As aresult, we expect there would be minimal emission reductions, costs, orbenefits associated with the proposed standards.►Because there have been a few unitsthat have notified the EPA ofmodifications in the past, the RIA presents an illustrative analysis of thecosts and benefits for a hypothetical unit if it were to trigger themodification provision.►We estimate that a 500 MW coal unit could achieve a 6% efficiencyimprovement for an annualized cost of $8.3 million.►These efficiency improvements would result in an annual fuel savings of$5.6 million.►These efficiency improvements would result in reductions in CO2, SO2, NOX,and PM2.5emissions.•For a 6% efficiency improvement, EPA estimates the combined climate benefitsfrom reductions in CO2and health co-benefits from reductions in SO2, NOx, andPM2.5total $27 to $49 million (2011$) at a 3percent discount rate for emissionreductions in 2025.18Page **1** of **45**

MEMORANDUM

From: Office of Air Quality Planning and Standards U.S. Environmental Protection Agency

To: EGU NSPS Docket (EPA-HQ-OAR-2013-0603)

Date: June, 2014

Subject: Amended Regulatory Text

Amended Regulatory Text

On January 8, 2014, the EPA proposed amendments (79 FR 1430) to the regulatory text of subparts Da and KKKK to include greenhouse gas (GHG) standards for new electric generatingunits (EGUs). As an alternative to amending proposed subparts Da and KKKK, the EPA coproposed creating a new subpart TTTT to include the proposed GHG standards. Since those amendments have not been finalized we would have to reprint the January 8, 2014, amendments in this rulemaking and add the amendments in this proposal to the previous amendments. However, that could complicate the ability of the public to identify the proposed amendments included in this proposal. Therefore, to facilitate understanding the amendments being proposed in this proposal, the following document uses track changes to demonstrate the GHG standards for the proposed standards for modified and reconstructed EGUs on top of the existing proposed amendments from January 8, 2014.

In addition, in docket item EPA-HQ-OAR-2013-0495-0062 of the January 8, 2014, proposal, the EPA elaborated upon the request for comment included in the preamble on whether the general applicability of the proposed standards should be broadened and based on design characteristics instead of design characteristics and operating parameters. Under this approach, a GHG emission standard would apply during periods when certa in conditions are met and no numerical GHG emission standard would apply during periods when one or more of those conditions are not met. In other words, although there would be no numerical emission limit, the facility would remain subject to the standard of performance. The trac k changes of the proposed amendments in this proposal include this expanded applicability approach.

We intend to finalize the proposed amendments for modified and reconstructed EGUs following the approach finalized in the new source proposal published on January 8, 2013. For example, if the new source requirements are included in subp arts Da and KKKK and use the applicability described in detail in docket item EPA-HQ-OAR-2013-0495-0062, the proposed requirements in this proposal would be added to those amendments.Page **2** of **45**

Subpart Da-— Standards of Performance for Electric Utility Steam Generating Units

2. Section 60.46Da is added to read as follows:

§60.46Da Standards for carbon dioxide (CO 2 ).

(a) Your affected facility is subject to this section if construction commenced after January 8, 2014 or if modification or reconstruc tion commenced after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER] , and the affected facility meets the conditions specified in paragraphs (a)(1) and (a)(2) of this section, except as specified in paragraph (b) of

this section.

(1) The affected facility combusts fossil fuel for more than 10.0 percent of the heat input during any 3 consecutive calendar years.

(2) The affected facility net-electric sales consist ofsupplies more than one-third of its potential electric output and more than 219,000 MWh net-electric output to a utility power distribution system for sale on an annual basis.

(b) The following EGUs are not subject to this section:

(1) The proposed Wolverine EGU project described in Permit to Install No. 317-07 issued by the Michigan Department of Environm ental Quality, Air Quality Division, effective June 29, 2011 (as revised July 12, 2011).

(2) The proposed Washington County EGU project described in Air Quality Permit No. 4911-303-0051-P-01-0 issued by the Georgia Department of Natural Resources, Environmental Protection Division, Air Protection Branch, eff ective April 8, 2010, provided that construction had not commenced for NSPS purposes as of January 8, 2014.

(3) The proposed Holcomb EGU project described in Air Emission Source Construction Permit 0550023 issued by the Kansas Department of Health and Environment, Division of Environment, effective December 16, 2010, provided that construction had not commenced for NSPS purposes as of January 8, 2014.

(c) As owner or operator of an affected facility subject to this section, you shall not cause to be discharged into the atmosphere from the affected facility any gases that contain CO 2 in

excess of the emissions limit ation specified in either this paragraph s (c)(1) or (c)(2) of this

section

. (1) As owner or operator of an affected facility for which construction commenced after January 8, 2014, you shall not cause to be discharged into the atmosphere from the affected facility any gases that contain CO 2 in excess of the emissions limit specified in paragraph (c)(1)(i) or (c)(1)(ii) of this section.

(i) 500 kilograms (kg) of CO 2 per megawatt-hour (MWh) of gross energy output (1,100

lb CO 2 /MWh) on a 12-operating month rolling average basis; or

( ii2 ) 480 kg of CO 2 per MWh of gross energy output (1,050 lb CO 2 /MWh) on an 84- operating month rolling average basis.

(2) As owner or operator of an affected facility for which reconstruction commenced after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER], you shall not Comment [FC1]: Changing terminology to “netelectric sales” so “net-electric output” can be used in the definition of “net energy output” when determining the emission rate.

Comment [FC2]: Use consistent terminology –

either “limit” or “standard”

Comment [FC3]: For references purposes, in Table 4 of the January 8, 2014, proposal (79 FR 1430) the approximate net output based standard that corresponds to an 1,100 lb CO2/MWh-gross standard is 1,400 lb CO2/MWh-netPage **3** of **45**

cause to be discharged into the atmosphere from the affected facility any gases that contain CO 2 in excess of the emissions limit specified in para graph (c)(2)(i) or (c)(2)(ii) of this section.

(i) If the design rated capacity of your affected facility is 590 MW (2,000 MMBtu/h) or less, 950 kg CO 2 /MWh of net energy output (2,100 lb CO 2 /MWh) on a 12-operating month rolling average basis; or

(ii) If the design rated capacity of your affected facility is greater than 590 MW (2,000 MMBtu/h), then 820 kg CO 2 /MWh of net energy output (1,900 lb CO 2 /MWh) on a 12-operating month rolling average basis.

(3) As owner or operator of an affected f acility for which modification commenced after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER], you shall not cause to be discharged into the atmosphere from th e affected facility any gases that contain CO 2 in excess of the emissions limit specified in paragraph (c)(3)(i) or (c)(3)(ii) of this section.

(i) If the facility is not subject to an approved CAA section 111(d) plan (state or federal),

a CO 2 emissions limit specified in paragraph (c)(3)(i )(A), (c)(3)(i)(B), or (c)(3)(i)(C) of this

section.

(A) a site-specific12-operating month rolling average CO 2 emission limit calculated as 2 percent lower than (i.e., 98 percent) the best demonstrated annual historical operating performance for the affected facility using historical CO 2 emissions data for the calendar years 2002 through the most recent full calendar year the affected facility was operating prior to the modification using either recorded net output em ission rate data or gross electrical output and

CO 2 emissions data as reported under part 75 of this chapter. If incomplete or no data has been submitted under part 75 of this chapter, the Ad ministrator or delegated authority shall approve the use of alternate data sources. The equivalent net output-based standard shall be calculated from gross output-based data assuming a 7.5 percent auxiliary (i.e., parasitic) load (i.e., the best annual value is divided by 0.925);

(B) If the design rated capacity of your affected facility is 590 MW (2,000 MMBtu/h) or less, 950 kg CO 2 /MWh of net energy output (2,100 lb CO 2 /MWh) on a 12-operating month rolling average basis; or

(C) If the design rated capacity of your affected facility is greater than 590 MW (2,000 MMBtu/h), 820 kg CO 2 /MWh of net energy output (1,900 lb CO 2 /MWh) on a 12-operating month rolling average basis.

(ii) If the facility is subject to an approved CAA section 111(d) plan (state or federal), a site-specific 12-operating month rolling average CO 2 emission limit determined by the CAA section 111(d) implementing authority based on the affected facility performing an energy assessment by an energy professional or engineer that have expertise in evaluating energy systems to identify appli cable energy efficiency projects that you will implement at the affected facility to improve the affected facility’s operating performance. You must maintain a copy of the most recent energy assessment report. The energy assessment must include at a minimum the elements in paragraphs (c)(3)(ii)(A) through (c)(3)(ii)(C) of this section.

(A) A visual inspection of the facility to iden tify steam leaks or other sources of reduced efficiency, Comment [FC4]: Since facility is not subject to 111(d) there is no CAA section 111(d) authority.Page **4** of **45**

(B) A review of available engineering pl ans and facility operation and maintenance procedures and logs, and

(C) A comprehensive report detailing the ways to improve efficiency, the cost of specific improvements, benefits, and the time frame for recouping those investments.

(d) You must make compliance determinations at the end of each operating month, as provided in paragraphs (d)(1) and (d)(2) of this section. For the purpose of this section, operating month means a calendar month during which any fossil fuel is combusted in the affected facility.

(1) If you elect toare comply ing with the a 12-operating month CO 2 emissions limit ation in paragraph (c)(1) of this section , you must determine compliance monthly by calculating the average CO 2 emissions rate for the affected facility at the end of each 12-operating month period that includes, as the last month, the month for which you are determining compliance.

(2) If you elect toare comply ing with thean 84-operating month CO 2 emissions limit ation in paragraph (c)(2) of this section , you must determine compliance monthly by calculating the average CO 2 emissions rate for the affected facility at the end of each 84-operating month period that includes, as the last month, the month for which you are determining compliance.

(e) You must conduct an initial compliance determination with the CO 2 emissions

limit ation for your affected facility within 30 da ys after accumulating the required number of operating months for the compliance period with which you have elected to comply (i.e., 12- operating months or 84-operating months). The firs t operating month included in this compliance period is the month in which emissions reporting is required to begin under § 75.64(a) of this chapter.

(f) You must monitor and collect data to demonstrate compliance with the CO 2 emissions

limit ation according to the requirements in paragrap hs (f)(1) through (4) of this section.

(1) You must prepare a monitoring plan in accordance with the applicable provisions in § 75.53(g) and (h) of this chapter.

(2) You must measure the hourly CO 2 mass emissions from each affected facility using the procedures in paragraphs (f)(2)(i) through (vii) of this section, except as provided in paragraph (f)(3) of this section.

(i) You must install, certify, oper ate, maintain, and calibrate a CO 2 continuous emission monitoring system (CEMS) to directly measure and record CO 2 concentrations in your affected facility’s exhaust gases that are emitted to the atmosphere and an exhaust gas flow rate monitoring system according to §75.10(a)(3)(i) of this chapter. If you measure CO 2 concentration on a dry basis, you must also inst all, certify, operate, maintain, and calibrate a continuous moisture monitoring system, according to §75.11(b) of this chapter.

(ii) For each monitoring system used to determine the CO 2 mass emissions, you must meet the applicable certification and quality assurance procedures in §75.20 of this chapter and Appendices B and D to part 75 of this chapter.

(iii) You must use a laser device to measure the dimensions of each exhaust gas stack or

duct at the flow monitor and the reference met hod sampling locations prior to the initial setup (characterization) of the flow monitor. For circular stacks, you must make measurements of the diameter at three or more distinct locations and average the results. For rectangular stacks or ducts, you must make measurements of each dimens ion (i.e., depth and width) at three or morePage **5** of **45**

distinct locations and average the results. If the flow rate monitor or reference method sampling site is relocated, you must repeat these measurements at the new location.

(iv) You can only use unadjusted exhaust ga s volumetric flow rates to determine the hourly CO 2 mass emissions from the affected facility; you must not apply the bias adjustment factors described in section 7.6.5 of Appendix A to part 75 of this chapter to the exhaust gas flow

rate data.

(v) If you choose to use Method 2 in Appendix A-1 to this part to perform the required relative accuracy test audits (RATAs) of the part 75 flow rate monitoring system, you must use a calibrated Type-S pitot tube or pitot tube asse mbly. You must not use th e default Type-S pitot

tube coefficient.

(vi) If two or more affected facilities share a common exhaust gas stack and are subject to

the same CO 2 emissions limit ation in paragraph (c) of this sec tion, you may monitor the hourly

CO 2 mass emissions at the common exhaust gas stack rather than monitoring each affected facility separately.

(vii) If the exhaust gases from the affected facilities are emitted to the atmosphere through multiple stacks (or if the exhaust gases are routed to a common stack through multiple ducts and you choose to monitor in the ducts), you must monitor the hourly CO 2 mass emissions and the “stack operating time” (as defined in § 72.2 of this chapter) at each stack or duct separately.

(3) As an alternative to complying with paragraph (f)(2) of this section, for affected facilities that do not combust any solid fuel, you may determine the hourly CO 2 mass emissions by using Equation G-4 in Appendix G to part 75 of this chapter according to the requirements specified in paragraphs (f)(3)(i) and (f)(3)(ii) of this section.

(i) You must implement the applicable procedures in Appendix D to part 75 of this chapter to determine hourly unit heat input rates (MMBtu/h), based on hourly measurements of fuel flow rate and periodic determinations of the gross calorific value (GCV) of each fuel

combusted.

(ii) You may determine site-specific carbon-based F-factors (F

c ) using Equation F-7b in section 3.3.6 of Appendix F to part 75 of this chapter, and you may use these F

c values in the emissions calculations instead of using the default F

c values in the Equation G-4 nomenclature.

(4) You must install, calibrate, maintain, and operate a sufficient nu mber of watt meters to continuously measure and record the gross or net electric output from the affected facility

,. Measurements must be performed using 0.2 cl ass electricity metering instrumentation and calibration procedures as specified under ANSI Standards No. C12.20.and yY ou must also meet the requirements specified in paragraphs (f)(4)(i) and (ii) of this section, as applicable.

(i) If your affected facility is a combined heat and power unit as defined in § 60.42Da, you must also install, calibrate, maintain, a nd operate meters to continuously determine and record the total useful recovered thermal energy. For process steam applications, you must install, calibrate, maintain, and operate meters to continuously determine and record steam flow rate, temperature, and pressure. If your affected f acility has a direct mechanical drive application, you must submit a plan to the Administrator or delegated authority for approval of how gross orPage **6** of **45**

net energy output will be determined. Your plan sha ll ensure that you insta ll, calibrate, maintain, and operate meters to continuously determine and record each component of the determination.

(ii) If two or more affected facilities have steam generating units that serve a common electric generator, you must apportion the combined hourly gross or net electric output to each individual affected facility using a plan approved by the Administrator (e.g., using steam load or heat input to each affected facility). Your plan shall ensure that you install, calibrate, maintain, and operate meters to continuously determine and record each component of the determination.

(g) You must demonstrate compliance with the CO 2 emissions limit ation using the procedures specified in paragraphs (g)(1) and (2) of this section.

(1) You must calculate the CO 2 mass emissions rate for your affected facility using the calculation procedures in paragraphs (g)(1)(i) through (v) of this section with the hourly CO 2 mass emissions and gross or net energy output data determined and recorded according to the procedures in paragraph (f) of this section for each operating hour in the applicable compliance period (i.e., 12-operating months or 84-operating months).

(i) You must only use operating hours in the compliance period for which you have valid data for all the para meters you use to determine the hourly CO 2 mass emissions and gross or net output data. You must not use operating hours which use the substitute data provisions of part 75 of this chapter for any of the parameters in the calculation. For the compliance determination calculation, you must obtain valid hourly values for a minimum of 95 percent of the operating hours in the applicable compliance period.

(ii) You must calculate the total CO 2 mass emissions by summing all of the valid hourly

CO 2 mass emissions values for the applicable compliance period. If exhaust gases from the affected facility are emitted to the atmosphere through multiple stacks or ducts, you must

calculate the total CO 2 mass emissions for the affected facility by summing the total CO 2 mass emissions from each of the individual stacks or ducts.

(iii) For each operating hour of the compliance period used in paragraph (g)(1)(ii) of this

section to calculate the total CO 2 mass emissions, you must determine the affected facility’s corresponding hourly gross or net energy output using the appropriate definitions in § 60.42Da and paragraph (k) of this section and using the procedure specified in paragraphs (g)(3)(iii)(A) through (D) of this section.

(A) Calculate P gross /net for your affected facility using the following equation:

ܲ

௚௥௢௦௦ /௡௘௧ = ሺ ܲ݁ ሻ ௌ் ൅ ሺ ܲ݁ ሻ ஼் ൅ ሺ ܲ݁ ሻ ூா െ ሺܲ݁ሻ ிௐ
T ൅ 	0.75 ൈ ሾ ሺ ܲݐ ሻ ௉ௌ ൅ ሺ ܲݐ ሻ ுோ ൅ ሺ ܲݐ ሻ ூா ሿ

Where: a

P gross /net = Gross or net energy output of your affected facility in megawatt-hours in ( MWh )

. (Pe) ST = Electric energy output plus mechanic al energy output (if any) of steam

turbines in MWh.

(Pe) CT = Electric energy output plus mechanical energy output (if any) of stationary combustion turbine(s) in MWh. Comment [FC5]: Technical corrections included throughoutPage **7** of **45**

(Pe) IE = Electric energy output plus mechanic al energy output (if any) of your affected facility’s integrated equipment that provides electricity or mechanical energy to the affected facility or auxiliary equipment in MWh.

(Pe) FW = Electric energy used to power boiler feedwater pumps at steam generating

units in MWh. This term is no t applicable to IGCC facilities or facilities complying with a net output based standard

. (Pt) PS = Useful thermal energy output of steam ( measured relative to ISO SATP

conditions , as applicable) that is used for applications that do not generate additional electricity, pro duce mechanical energy output, or enhance the performance of the affected facility. This term is calculated using the equation specified in paragraph (g)(3)(iii)(B) of this section in MWh.

(Pt) HR = Hourly useful thermal energy output ( measured relative to ISO SATP

conditions , as applicable) from heat recovery that is used for applications other than steam generation or performance enhancement of the affected facility in MWh.

(Pt) IE = Useful thermal energy output ( relative to ISO SATP conditions , as applicable) from any integrated equipment that provides thermal energy to the affected facility or auxiliary equipment in MWh.

T = Electric Transmission and Distribution Factor.

T = 0.95 for a combined heat and power affected facility where at least on an annual basis 20.0 percent of the total gross or net energy output consists

of electric or direct mech anical output and 20.0 percent of the total gross

or net energy output consists of useful thermal energy output on a rolling 3 year basis.

T = 1.0 for all other affected facilities.

(B) If applicable to your affected facility, calculate (Pt) PS using the following equation:

ሺܲݐሻ ௉ௌ ൌ ܳ
௠ ൈ 	ܪ

3.6	 ൈ	 10 ଽ

Where:

Q

m = Measured steam flow in kilograms (kg) (or pounds (lb)) for the operating

hour.

H = Enthalpy of the steam at ( measured temperature and pressure relative to

ISO SATP conditions , as applicable) in Joules per kilogram (J/kg) (or Btu/lb).

3.6 x 10 9 = Conversion factor (J/MWh) (or 3.413 x 10 6 Btu/MWh).

(C) For an operating hour in which there is no gross or net electric load, but there is mechanical or useful thermal output, you must still determine the gross or net energy output forPage **8** of **45**

that hour. In addition, for an operating hour in which there is no useful output, you must still determine the hourly gross CO 2 emissions for that hour. For hours or partial hours where there is no gross generation, net electric output shall be zero.

(D) If hourly CO 2 mass emissions are determined for a common stack, you must determine the hourly gross or net energy output (electric, thermal, and/or mechanical, as applicable) by summing the hourly loads for the individual affected facility and you must express the operating time as “stack operating hours” (as defined in § 72.2 of this chapter).

(iv) You must calculate the total gross or net energy output by summing the hourly gross

or net energy output values for the affected facility determined from paragraph (g)(1)(iii) of this section for all of the operating hours in the applicable compliance period.

(v) You must calculate the CO 2 mass emissions rate for the applicable compliance period interval by dividing the total CO 2 mass emissions value from paragraph (g)(1)(ii) of this section by the total gross or net energy output value from paragraph (g)(1)(iv) of this section.

(2) You must determine compliance with the CO 2 emissions limit ation in paragraph (c) of this section is determined as specified in paragr aphs (g)(2)(i) and (ii) of this section using the

CO 2 mass emissions rate for your affected facility that you determined in paragraph (g)(1) of this

section.

(i) If the CO 2 mass emissions rate for your affected facility is less than or equal to the

CO 2 emissions limit ation applicable to your affected facility, then your affected facility is in compliance with the CO 2 emissions limit ation . If you attain compliance with the CO 2 emissions

limit ation at a common stack for two or more affected facilities subject to the same CO 2 emissions limit ation , each affected facility sharing the stack is in compliance with the CO 2 emissions limit ation

. (ii) If the CO 2 mass emissions rate for the affect ed facility is greater than the CO 2 emissions limit ation in paragraph (c) of this section appli cable to the affected facility, then the affected facility has excess CO 2 emissions.

(h) You must prepare and submit notifications and reports according to paragraphs (h)(1) through (4) of this section.

(1) You must prepare and submit the notifications in §§ 60.7(a)(1) and (a)(3) and 60.19, as applicable to your affected facility.

(2) You must prepare and submit notifications in § 75.61 of this chapter, as applicable to your affected facility.

(3) You must submit electronic quarterly reports according to the requirements specified in paragraphs (h)(3)(i) through (iii) of this section.

(i) Initially, after you have accumulated the required number of operating months for the

CO 2 emission limit ation compliance period that you have chosen to comply with (i.e., 12- operating months or 84-operating months), you must submit a report for the calendar quarter that includes the final (12th- or 84th) operating month no later than 30 days after the end of that quarter. Thereafter, you must submit a report for each subsequent calendar quarter no later than 30 days after the end of the quarter. Comment [FC6]: During periods of startup/shutdown where the facility is not generating power and “purchasing” power to run the facility net electricity is negative. There periods will be counted as zero and not negative.Page **9** of **45**

(ii) In each quarterly report you must include the information in paragraphs (h)(3)(ii)(A) through (E) of this section.

(A) The CO 2 emission limit ation compliance period with which you have chosen to comply.

(B) Any months in the calendar quarter that you are not counting as operating months.

(C) For each operating month in the calendar quarter, the corresponding average CO 2 mass emissions rate for the applicable compliance period interval that you determined according to paragraph (g) of this section.

(D) The percentage of valid CO 2 mass emission rates in each compliance period (i.e., the

total number of valid CO 2 mass emission rates in that period divided by the total number of operating hours in that period , multiplied by 100 percent).

(E) Any operating months in the calendar quarter with excess CO 2 emissions.

(iii) In the final quarterly report of each calendar year you must include the following:

(A) Net electric output sold to an el ectric grid over the calendar year; and

(B) The potential electric output of the facility.

(iv) You must submit each electronic re port using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool pr ovided by the Clean Air Markets Division in the EPA Office of Atmospheric Programs.

(4) You must meet all applicable reporting re quirements and submit reports as required under subpart G of part 75 of this chapter.

(5) If your affected unit uses geologic sequ estration to meet the applicable emissions limit, you must report in accordance with the requirements of 40 CFR part 98, subpart PP and

either:

(i) if injection occurs onsite, report in accordance with the requirements of 40 CFR part 98, subpart RR, or

(ii) if injection occurs offsite, transfer the captured CO 2 to a facility or facilities that reports in accordance with the requirements of 40 CFR part 98, subpart RR.

(i) For each affected electric utility stream generating unit, you must maintain records according to paragraphs (i)(1) through (i)(8) of this section.

(1) You must comply with the applicable recordkeeping requirements and maintain records as required under subpart F of part 75 of this chapter.

(2) You must maintain records of the calcula tions you performed to determine the total

CO 2 mass emissions for each operating month, and the averages for each compliance period interval (i.e., 12-operating months or 84-operating months, as applicable to the CO 2 emissions

limit ation s).

(3) You must maintain records of the applicable data recorded and calculations performed that you used to determine the gross or net energy output for each operating month.

(4) You must maintain records of the calculations you performed to determine the percentage of valid CO 2 mass emission rates in each compliance period.Page **10** of **45**

(5) You must maintain records of the calculations you performed to assess compliance with each applicable CO 2 emissions limit ation in paragraph (c) of this section.

(6) Your records must be in a form suitable and readily available for expeditious review.

(7) You must maintain each record for 5 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record except those records required to demonstrate compliance with an 84-operating month compliance period. You must maintain records required to demonstrate compliance with an 84-operating month compliance period for at least 10 years following the date of each occurrence, measurement, maintenance, corrective action, report, or record.

(8) You must maintain each record on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to § 60.7. You may maintain the records off site and electronically for the remaining year(s) as required by this subpart.

(j) PSD and Title V Thresholds for Gree nhouse Gases. (1) For purposes of 40 CFR 51.166(b)(49)(ii), with respect to GHG em issions from new affected facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 51.166(b)(48) and in any SIP approved by the EPA that is interpreted to incorporate, or specifically incorporates, 40 CFR 51.166(b)(48).

(2) For purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG emissions from new affected facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 52.21(b)(49).

(3) For purposes of 40 CFR 70.2, with respect to greenhouse gas emissions from new affected facilities, the “pollutant that is subject to any standard promulga ted under section 111 of the Act” shall be considered to be the pollutant that otherwise is "subject to regulation" as

defined in 40 CFR 70.2.

(4) For purposes of 40 CFR 71.2, with respect to greenhouse gas emissions from new affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is "subject to regulation" as defined in 40 CFR 71.2.

(k) For purposes of this section, the following definitions apply:

Gross energy output means:

(i) Except as provided under paragraph (ii) of this definition, for electric utility steam generating units, the gross electric or mechanical output from the affected facility (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expanders) minus any electricity used to power the feedwater pumps plus 75 percent of the useful thermal output

measured relative to ISO conditions that is not used to genera te additional electri c or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application) ;

(ii) For electric utility steam generating unit combined heat and power facilities where at least 20.0 percent of the total gross energy output consists of electric or direct mechanical output Comment [FC7]: Redundant with definition of useful thermal outputPage **11** of **45**

and at least 20.0 percent of the total gross energy output consists of thermal output on a rolling 3 year basis, the gross electric or mechanical out put from the affected facility (including, but not limited to, output from steam turbine(s), combus tion turbine(s), and gas expanders) minus any electricity used to power the feedwater pumps, th at difference divided by 0.95, plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application) ;

(iii) Except as provided under paragraph (i vi ) of this definition, for a IGCC electric utility generating unit, the gross electric or mechanical output from the affected facility (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expanders) plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application) ; or

(iv) For IGCC electric utility generating unit co mbined heat and power facilities where at least 20.0 percent of the total gross energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross energy output consists of thermal output on a rolling 3 year basis, the gross electric or mechanical out put from the affected facility (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expanders) divided by 0.95, plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industri al process for a heating application).;

IGCC facility is an integrated gasification combined cycle electric utility steam generating unit, which means an electric utility combined cycle facility that is designed to burn fuels containing 50 percent (by heat input) or more solid-derived fuel not meeting the definition of natural gas plus any integrated equipment that provides electricity or useful thermal output to either the affected facility or auxiliary equi pment. The Administrator may waive the 50 percent solid-derived fuel requirement during periods of the gasification system construction, startup and commissioning, shutdown, or repair. No solid fuel is directly burned in the facility during operation.

Net-electric salesoutput means:

(i) Except as provided under paragraph (ii) of this definition, the gross electric sales to the utility power distribution sy stem minus purchased power on a calendar year basis , or

(ii) For combined heat and power facilities wh ere at least 20.0 percen t of the total gross

or net energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross or net energy output consists of thermal output, the gross electric sales to the utility power distribution system minus purchased power of the thermal host facility or facilities on a calendar year basis; and.

(iii) Electricity supplied to other facilities that produce electricity to offset auxiliary loads are included when calculating net-electric sales.

Net-electric output means: the amount of gross generation the generator(s) produces (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)), as measured at the generator terminals, less the electricity used to operate the plant (i.e., auxiliary loads); such uses include fuel handling equipment, pumps, fans, pollution control Comment [FC8]: Use “net-electric sales” so we don’t have to use “for applicability purposes” and “for compliance purposes” for net electric output.

Comment [FC9]: Not necessary since time frame specific directly in text.

Comment [FC10]: Net electric output does not account for supplying electric power to other EGUs.For example, a simple cycle combustion turbine colocated with a coal-fired EGU would not be able to say it was supplying power to coal-fired EGU to offset auxiliary power requirements of the coal-fired

EGU.Page **12** of **45**

equipment, other electricity needs, and transformer losses as measured at the transmission side of the step up transformer (e.g., the point of sale).

Net energy output means:

(i) Except as provided under paragraph (ii) of this definition, the net electric or mechanical output from the affected facility plus 75 percent of the useful thermal output; or

(ii) For combined heat and power facilities wh ere at least 20.0 percen t of the total gross or net energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross or net energy output consists of thermal output on a rolling 3 year basis, the net electric or mechanical output from the affected f acility divided by 0.95, plus 75 percent of the useful thermal output.

Potential electric output means:

(i) Either 33 percent or the design net elect ric output efficiency, at the election of the owner/operator of the affected facility,

(ii) Multiplied by the maximum design heat in put capacity of the steam generating unit,

(iii) Divided by 3,413 Btu/KWh,

(iv) Divided by 1,000 kWh/MWh, and

(v) Multiplied by 8,760 h/yr.

(vi) For example, a 35 percent efficient steam generating unit with a 100 MW (341 MMBtu/h) fossil-fuel heat input capacity would have a 310,000 MWh 12 month potential electric output capacity.

Standard ambient temperature and pressure (SATP) conditions means 298.15 Kelvin (25 o C, 77 o F)) and 100.0 kilopascals (14.504 psi, 0.987 atm) pressure. The enthalpy of water at SATP conditions is 45 Btu/lb.

Steam generating unit means any furnace, boiler, or other device used for combusting fuel for the purpose of producing steam (nuclear steam generators are not included) plus any integrated equipment that provides electricity or useful thermal output

to either the boiler or auxiliary equipment.

Useful thermal output means the thermal energy made available for use in any heating application (e.g., steam delivered to an industrial process for a heating application, including thermal cooling applications) that is not used fo r electric generation, mechanical output at the affected facility, or to directly enhance the performance of the affected facility (e.g., economizer output is not useful thermal output, but thermal ener gy used to reduce fuel moisture is considered useful thermal output). Useful thermal output for affected facilities with no condensate return (or other thermal energy input to the affected facility) or where measuring the energy in the condensate (or other thermal energy input to the affected facility) would not meaningfully impact the emission rate calculation is measured agai nst the energy in the thermal output at SATP conditions. Affected facilities with meaningful en ergy in the condensate return (or other thermal energy input to the affected facility) must measur e the energy in the condensate and subtract that energy relative to SATP conditions from the measured thermal output. Comment [FC11]: Soliciting comment on 100%

thermal credit

Comment [FC12]: Thermal energy used for coal drying is considered useful thermal output – could be done offsite by a separate thermal source and would

not be included in the calculation.

Comment [FC13]: Changing form ISO conditions since SATP is closer to makeup water conditions (45 Btu/lb instead of 27 Btu/lb).Page **13** of **45**

Subpart KKKK -— Standards of Performance for Stationary Combustion Turbines

3. Section 60.4305 is amended by adding paragraph (c) to read as follows:

§ 60.4305 Does this subpart apply to my stationary combustion turbine?

* * * * *

(c) For purposes of regulation of greenhouse gases, the applicable provisions of this subpart affect your stationary combustion turbine if it serves a generator capable of selling greater

than 25 MW to a utility power distribution system and commenced construction after January 8,

2014 or it commenced reconstruction or modi fication after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER].

4. Section 60.4315 is revised to read as follows:

§ 60.4315 What pollutants are regulated by this subpart?

(a) The pollutants regulated by this subpart are nitrogen oxides (NO X ), sulfur dioxide (SO 2 ), and greenhouse gases.

(b)(1) The greenhouse gases regulated by this subpart consist of carbon dioxide (CO 2 ).

(2) PSD and Title V Thresholds for Green house Gases. (i) For purposes of 40 CFR 51.166(b)(49)(ii), with respect to GH G emissions from affected stationary combustion turbine, the “pollu tant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 51.166(b)(48) and in any SIP approved by the EPA that is interpreted to incorporat e, or specifically incorporates, 40 CFR 51.166(b)(48).

(ii) For purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG emissions from affected stationary combustion turbines, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 52.21(b)(49).

(iii) For purposes of 40 CFR 70.2, with respect to greenhouse gas emissions from affected stationary combustion turbines, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is "subject to regulation" as defined in 40 CFR 70.2.

(iv) For purposes of 40 CFR 71.2, with respect to greenhouse gas emissions from affected stationary combustion turbines, th e “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is "subject to regulation" as defined in 40 CFR 71.2.

5. Section 60.4326 is added to read as follows:

§ 60.4326 What CO 2 emissions standard must I meet?

You must not discharge from your affected stationary combustion turbine into the atmosphere any gases that contain CO 2 in excess of the applicable CO 2 emissions standard specified in Table 2 of this subpart.

6. Section 60.4333 is amended by adding paragraph (c) to read as follows: Comment [FC14]: Added to avoid covering large industrial units not connected to a generator being subject to “no emision standard”Page **14** of **45**

§ 60.4333 What are my general requirements for complying with this subpart?

* * * * *

(c) If you own or operate an affected stationary combustion turbine subject to a CO 2 emissions standard in §60.4326, you must make compliance determinations on a 12-operating month rolling average basis, and you must de termine compliance monthly by calculating the average CO 2 emissions rate for the affected stationary combustion turbine at the end of each 12- operating month period.

7. Section 60.4373 is added under undesignated center heading “Monitoring” to read as

follows:

§ 60.4373 How do I monitor and collect data to demonstrate compliance with my CO 2 emissions standard using a CO 2 CEMS?

(a) You must prepare a monitoring plan in accordance with the applicable provisions in § 75.53(g) and (h) of this chapter.

(b) You must measure the hourly CO 2 mass emissions from each affected stationary combustion turbine using the procedures in paragraphs (b)(1) through (5) of this section, except as provided in paragraph (c) of this section.

(1) You must install, certify, ope rate, maintain, and calibrate a CO 2 continuous emission monitoring system (CEMS) to directly measure and record CO 2 concentrations in the stationary combustion turbine exhaust gase s emitted to the atmosphere an d an exhaust gas flow rate monitoring system according to § 75.10(a)(3)(i) of this chapter. If you measure CO 2 concentration on a dry basis, you must also inst all, certify, operate, maintain, and calibrate a continuous moisture monitoring system, according to § 75.11(b) of this chapter.

(2) For each monitoring system that you use to determine the CO 2 mass emissions, you must meet the applicable certification and quality assurance procedures in § 75.20 of this chapter and Appendices B and D to part 75 of this chapter.

(3) You must use a laser device to measure the dimensions of each exhaust gas stack or

duct at the flow monitor and the reference met hod sampling locations prior to the initial setup (characterization) of the flow monitor. For circular stacks, you must make measure of the diameter at three or more distinct locations and average the results. For rectangular stacks or ducts, you must measure each dimension (i.e., de pth and width) at three or more distinct locations and average the results. If the flow rate monitor or reference method sampling site is relocated, you must repeat these measurements at the new location.

(4) You must use unadjusted exhaust gas volumetric flow rates only to determine the hourly CO 2 mass emissions from the affected stationary combustion turbine; you must not apply the bias adjustment factors described in section 7. 6.5 of Appendix A to part 75 of this chapter to the exhaust gas flow rate data.

(5) If you chose to use Method 2 in Appendix A-1 to this part to perform the required relative accuracy test audits (RATAs) of the part 75 flow rate monitoring system, you must use a calibrated Type-S pitot tube or pitot tube asse mbly. You must not use th e default Type-S pitot

tube coefficient.

(c) As an alternative to comp lying with paragraph (b) of th is section, you may determinePage **15** of **45**

the hourly CO 2 mass emissions by using Equation G-4 in Appendix G to part 75 of this chapter according to the requirements specified in paragraphs (c)(1) and (2) of this section.

(1) You must implement the applicable procedures in appendix D to part 75 of this chapter to determine hourly unit heat input rates (MMBtu/h), based on hourly measurements of fuel flow rate and periodic determinations of the gross calorific value (GCV) of each fuel

combusted.

(2) You may determine site-specific carbon-based F-factors (F

c ) using Equation F-7b in section 3.3.6 of Appendix F to part 75 of this chapter, and you may use these F

c values in the emissions calculations instead of using the default F

c values in the Equation G-4 nomenclature.

(d) You must install, calibrate, maintain, and operate a sufficient nu mber of watt meters to continuously measure and record the gross electric output from the affected stationary

combustion turbine. Measurements must be performed using 0.2 class electricity metering instrumentation and calibration procedures as specified under ANSI Standards No. C12.20. If the affected stationary combustion turbine is a CHP stationary combustion turbine, you must also install, calibrate, maintain, and operate meters to continuously determin e and record the total useful recovered thermal energy. For process st eam applications, you will need to install, calibrate, maintain, and operate meters to continuously determine and record steam flow rate, temperature, and pressure. If the affected stati onary combustion turbine has a direct mechanical drive application, you must submit a plan to the Administrator or delegated authority for approval of how gross energy output will be determ ined. Your plan shall ensure that you install, calibrate, maintain, and operate meters to continuously determine and record each component of

the determination.

(e) If two or more affected stationary combustion turbines serve a common electric generator, you must apportion the combined hourly gross output to the individual stationary combustion turbines using a plan approved by th e Administrator (e.g., using steam load or heat input to each affected stationary combustion turbine). Your plan shall ensure that you install, calibrate, maintain, and operate meters to continuously determine and record each component of

the determination.

(f) In accordance with § 60.13(g), if two or more stationary combustion turbines that implement the continuous emission monitoring provi sions in paragraph (b) of this section share a common exhaust gas stack and are subject to the same emissions standard under § 60.4326, you may monitor the hourly CO 2 mass emissions at the common stack in lieu of monitoring each stationary combustion turbine se parately. If you choose this option, the hourly gross load (electric, thermal, and/or mechanical, as applicable) must be the sum of the hourly loads for the individual stationary combustion turbines and you must express the operating time as “stack operating hours” (as defined in § 72.2 of this chapter). If you attain compliance with the applicable emissions standard in § 60.4326 at the common stack, each stationary combustion turbine sharing the stack is in compliance.

(g) In accordance with § 60.13(g), if the exhaust gases from a stationary combustion turbine that implements the continuous emission monitoring provisions in paragraph (b) of this section are emitted to the atmosphere through mul tiple stacks (or if the exhaust gases are routed to a common stack through multiple ducts and you chose to monitor in the ducts), you must monitor the hourly CO 2 mass emissions and the “stack operating time” (as defined in § 72.2 of this chapter) at each stack or duct separately. In this case, you determine compliance with thePage **16** of **45**

applicable emissions standard in § 60.4326 by summing the CO 2 mass emissions measured at the individual stacks or ducts and dividing by the total gross output for the unit.

8. Section 60.4374 is added under undesignated center heading “Monitoring” to read as

follows:

§ 60.4374 How do I demonstrate compliance with my CO 2 emissions standard and

determine excess emissions?

(a) You must calculate the CO 2 mass emissions rate for your affected stationary combustion turbine by using the hourly CO 2 mass emissions and total gross output data determined and recorded according to the procedures in § 60.4373 for the compliance period for

the CO 2 emissions standard applicable to the affected stationary combustion turbine, and the calculation procedures in paragraphs (a)(1) through (a)(5) of this section.

(1) You must only use operating hours in the compliance period for the compliance determination calculation for which you obtained valid data for all parameters you used to determine the hourly CO 2 mass emissions and gross output data, are used for the compliance

determination calculation. You must not include operating hours in which you used the substitute data provisions of part 75 of this chapter for any of the parameters in the calculation. For the compliance determination calculation, you must obtain valid hourly CO 2 mass emission values for a minimum of 95 percent of the operating hours in the compliance period.

(2) You must calculate the total CO 2 mass emissions by summing the hourly CO 2 mass emissions values for the affected stationary combustion turbine determined to be valid according to the conditions specified in paragraph (a)(1) of this section for all of the operating hours in the applicable compliance period.

(3) For each operating hour of the compliance period used in paragraph (a)(2) of this

section to calculate the total CO 2 mass emissions, you must determine the affected stationary combustion turbine’s corresponding hourly gross output (P gross ) by applying the appropriate definitions in §§ 60.4420 and 60.4421 of this subpart and according to the procedures specified in paragraphs (a)(3)(i) and (iv) of this section .

(i) Calculate P gross for your affected stationary combustion turbine using the following equation:

ܲ ௚௥௢௦௦ = ሺܲ݁ሻ ஼் ൅ 	 ሺܲ݁ሻ ௌ் ൅ 	 ሺܲ݁ሻ ூா
T ൅ 	0.75 ൈ ሾ ሺ ܲݐ ሻ ௉ௌ ൅ ሺ ܲݐ ሻ ுோ ൅ ሺ ܲݐ ሻ ூா ሿ

Where:

P gross = Gross energy output of your affected stationary combustion turbine in megawatt-hours in ( MWh )

. (Pe) CT = Electric energy output plus mechanical energy output (if any) of stationary

combustion turbines in MWh.

(Pe) ST = Electric energy output plus mechanic al energy output (if any) of steam

turbines in MWh.

(Pe) IE = Electric energy output plus mechanic al energy output (if any) of your affected stationary combustion turbine’s integrated equipment that provides electricity to the affected facility or auxiliary equipment in MWh.Page **17** of **45**

(Pt) PS = Useful thermal energy output of steam ( relative to ISOSATP conditions

, as applicable) that is used for applications that do not generate additional electricity, produce mechanical energy output, enhance the performance of the affected facility. This is Cc alculated using the equation specified in paragraph (a)(3)(ii) of this section in MWh.

(Pt) HR = Useful thermal energy output ( relative to ISO SATP conditions , as applicable) from heat recovery that is used for applications other than steam generation or performance enhancement of the affected facility in

MWh.

(Pt) IE = Useful thermal energy output ( relative to ISO SATP conditions , as applicable) from any integrated equipment that provides input to the affected facility or auxiliary equipment in MWh.

T = Electric Transmission and Distribution Factor.

T = 0.95 for a CHP stationary combustion turbine where at least on an annual basis 20.0 percent of the total gross energy output consists of electric or direct mechanical output and 20.0 percent of the total gross energy output consists of useful thermal energy output on a rolling 3 year

basis.

T = 1.0 for all other affected stationary combustion turbines.

(ii) If applicable to your affected stat ionary combustion turbine, calculate (Pt) PS using the following equation:

ሺܲݐሻ ௉ௌ ൌ ܳ
௠ ൈ 	ܪ

3.6	 ൈ	 10 ଽ

Where:

Q

m = Measured steam flow in kilograms (kg) (or pounds (lb)) for the operating

hour.

H = Enthalpy of the steam at measured temperature and pressure ( relative to

ISO SATP conditions , as applicable) in Joules per kilogram (J/kg) (or Btu/lb).

3.6 x 10 9 = Conversion factor (J/MWh) (or 3.413 x 10 6 Btu/MWh).

(iii) You must determine the hourly gross energy output for each operating hour in which there is no electric output, but there is mechanical output or useful thermal output. In addition you must determine the hourly gross CO 2 emissions for each operating hour in which there is no useful output.

(iv) In the case for which compliance is demonstrated according to § 60.4373(f) for affected stationary combustion turbines that vent to a common stack, then you must calculate the hourly gross energy output (electric, mechanical, and/or thermal, as applicable) by summing the hourly gross energy output you determined for each of your individual affected stationaryPage **18** of **45**

combustion turbines that vent to the common stack; and you must express the operating time as “stack operating hours” (as defined in § 72.2 of this chapter).

(4) You must calculate the total gross output for the affected stationary combustion turbine’s compliance period by summing the hourly gross output values for the affected stationary combustion turbine determined from paragraph (a)(2) of this section for all of the operating hours in the applicable compliance period.

(5) You must calculate the CO 2 mass emissions rate for the affected stationary combustion turbine by dividing the total CO 2 mass emissions value as calculated according to the requirements of paragraph (a)(2) of this section by the total gross output value as calculated according to the requirements of paragraph (a)(4) of this section.

(b) If the CO 2 mass emissions rate for the affect ed stationary combustion turbine determined according to the procedures specified in paragraph (a) of this section is less than or equal to the CO 2 emissions standard in Table 2 of this subpart applicable to the affected stationary combustion turbine, then your affected stationary combustion turbine is in compliance with the emissions standard. If the average CO 2 mass emissions rate is greater than the CO 2 emissions standard in Table 2 of this subpart ap plicable to the affected stationary combustion turbine, then your affected stationary combustion turbine has excess CO 2 emissions.

9. Section 60.4375 is amended by revising the section heading to read as follows:

§ 60.4375 What reports must I submit to comply with my NO

x and SO 2 emissions limits?

* * * * *

10. Section 60.4376 is added to read as follows:

§ 60.4376 What notifications and reports must I submit to comply with my CO 2 emissions

standard?

(a)(1) You must prepare and submit the notifi cations specified in §§ 60.7(a)(1) and (a)(3) and 60.19, as applicable to your affected stationary combustion turbine.

(2) You must prepare and submit notifications specified in § 75.61 of this chapter, as applicable to your affected st ationary combustion turbine.

(b) You must prepare and submit reports according to paragraphs (b)(1) through (d) of this section, as applicable.

(1) For stationary combustion turbines that are required, by § 60.4333(c), to conduct initial and on-going compliance determinations on a 12-operating month ro lling average basis for the standard in § 60.4326, you must submit electronic quarterly reports as follows. After you have accumulated the first 12-operating months for the affected stationary combustion turbine, you must submit a report for the calendar quarter that includes the 12th-o perating month no later than 30 days after the end of that quarter. Thereafter, you must submit a report for each subsequent calendar quarter, no later than 30 days after the end of the quarter.

(2) In each quarterly report, you must include the following information, as applicable:

(i) Each rolling average CO 2 mass emissions rate for whic h the last (12th) operating month in a 12-operating month compliance period falls within the calendar quarter. You must calculate each average CO 2 mass emissions rate according to the requirements of § 60.4374. YouPage **19** of **45**

must report the dates (month and year) of the 1st and 12th-operating months in each compliance period for which you performed a CO 2 mass emissions rate calculation. If there are no compliance periods that end in the quarter, you must include a statement to that effect;

(ii) If one or more compliance periods end in the quarter, you must identify each operating month in the calendar quarter with excess CO 2 emissions;

(iii) The percentage of valid CO 2 mass emission rates (as defined in § 60.4374) in each 12-operating month compliance period described in paragraph (b)(2)(i) of this section (i.e., the

total number of valid CO 2 mass emission rates in that period divided by the total number of operating hours in that period, multiplied by 100 percent); and

(iv) The CO 2 emissions standard (as identified in Table 2 of this subpart) with which your affected stationary combustion turbine is complying.

(3) The final quarterly report of each calendar year must contain the following:

(i) Net electric output sold to an electric grid over the 4 quarters of the calendar year; and

(ii) The potential electric output of the stationary combustion turbine.

(c) You must submit all electronic reports re quired under paragraph (b) of this section using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool provided by

the Clean Air Markets Division in the Offi ce of Atmospheric Programs of the EPA.

(d) You must meet all applicable reporting re quirements and submit reports as required under subpart G of part 75 of this chapter.

11. Section 60.4391 is added to read as follows:

§ 60.4391 What records must I maintain to comply with my CO 2 emissions limits?

(a) You must maintain records of the info rmation you used to demonstrate compliance with this subpart as specified in § 60.7(b) and (f).

(b) You must follow the applicable recordkeeping requirements and maintain records as required under subpart F of part 75 of this chapter.

(c) You must keep records of the calculati ons you performed to determine the total CO 2 mass emissions for:

(1) Each operating month (for all affected units);

(2) Each compliance period, including, as applicable, each 12-operating month compliance period.

(d) You must keep records of the applicable data recorded and calculations performed that you used to determine your affected stat ionary combustion turbine’s gross output for each operating month.

(e) You must keep records of the calculations you performed to determine the percentage

of valid CO 2 mass emission rates in each compliance period.

(f) You must keep records of the calculations you performed to assess compliance with each applicable CO 2 mass emissions standard in § 60.4326.

(g) You must keep records of the calculations you performed to determine any site-Page **20** of **45**

specific carbon-based F-factors you used in the emissions calculations (if applicable).

(h)(1) Your records must be in a form suitable and readil y available for expeditious

review.

(2) You must keep each record for 5 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record to demonstrate compliance with a 12-operating month emissions standard.

(3) You must keep each record on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to § 60.7. You may keep the records off site and electronically for the remaining year(s) as required by this subpart.

12. Section 60.4395 is revised to read as follows:

§ 60.4395 When must I submit my reports?

All of your reports required under § 60.7(c) must be postmarked by the 30th day after the end of each 6-month period, except as specified in § 60.4376

13. Section 60.4421 is added to read as follows:

§ 60.4421 What definitions with respect to CO 2 emissions apply to this subpart?

As used in this subpart:

Base load rating means 100 percent of the manufacturer's design heat input capacity of the combustion turbine engine at ISO conditions using the higher heating value of the fuel (heat input from duct burners is not included).

Excess emissions means a specified averaging period over which either:

(1) The CO 2 emissions rate of your affected stationary combustion turbine exceeds the applicable emissions standard in Table 2 of this subpart or § 60.4330; or

(2) The recorded value of a particular monitored parameter is outside the acceptable range specified in the parameter monitoring plan for the affected unit.

Gross energy output means:

(1) The gross electric or direct mechanical output from both the combustion turbine engine and any associated steam turbine(s) or integrated equipment plus any useful thermal output measured relative to ISO SATP conditions (except for GHG calculations in § 60.4374 as only 75 percent credit is given) that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application).

(2) For a CHP stationary combustion turbine wh ere at least 20.0 percent of the total gross energy output consists of electric or direct mechan ical output and at least 20.0 percent of the total gross energy output consists of useful thermal output on a rolling 3-year basis, the sum of the gross electric or direct mechan ical output from both the combustion turbine engine and any associated steam turbine(s) divided by 0.95 plus any useful thermal output measured relative to

ISO SATP conditions (except for GHG calculations in § 60.4374 as only 75 percent credit is given) that is not used to generate additional el ectric or mechanical output or to enhance thePage **21** of **45**

performance of the unit (e.g., steam delivered to an industrial process for a heating application).

Net-electric salesoutput means:

(1) The gross electric sales to the utility power distribution system minus purchased

power on a 3 calendar year rolling average basis ; or

(2) For combined heat and power facilities wh ere at least 20.0 percent of the total gross energy output consists of electric or direct mechan ical output and at least 20.0 percent of the total gross energy output consists of useful thermal ou tput on a 3 calendar year rolling average basis, the gross electric sales to the utility power distribution system minus purchased power of the thermal host facility or facilities on a three calendar year rolling average basis;. and

(3) Electricity supplied to other facilities that produce electricity to offset auxiliary loads are included when calculating net-electric sales.

Net-electric output means: the amount of gross generation a generator produces, as measured at the generator terminals, less the electricity used to operate the plant (i.e., auxiliary loads); such uses include fuel handling equipment, pumps, fans, pollution control equipment, other electricity needs, and transformer losses as m easured at the transmission side of the step up transformer (e.g., the point of sale).

Net energy output means:

(i) Except as provided under paragraph (ii) of this definition, the net electric or mechanical output from both the combustion turbine engine and any associated steam turbine(s) or integrated equipment plus 75 percent of the useful thermal output; or

(ii) For combined heat and power facilities wh ere at least 20.0 percen t of the total gross energy output consists of electric or direct mechan ical output and at least 20.0 percent of the total gross energy output consists of thermal output on a rolling 3 year basis, the net electric or mechanical output from both the combustion turbine engine and any associated steam turbine(s) or integrated equipment divided by 0.95, plus 75 percent of the useful thermal output.

Operating month means a calendar month during which any fuel is combusted in the affected stationary combustion turbine.

Potential electric output means 33 percent or the design electric output efficiency on a net output basis (at the election of the owner/operator of the affected facility) multiplied by the base load rating (expressed in MMBtu/h) of the stat ionary combustion turbine, multiplied by 10 6
Btu/MMBtu, divided by 3,413 Btu/KWh, divide d by 1,000 kWh/MWh, and multiplied by 8,760 h/yr (e.g., a 35 percent efficient stationary combustion turbine with a 100 MW (341 MMBtu/h) fossil-fuel heat input capacity would have a 310,000 MWh 12-month potential electric output capacity).

Standard ambient temperature and pressure (SATP) conditions means 298.15 Kelvin (25 o C, 77 o F)) and 100.0 kilopascals (14.504 psi, 0.987 atm) pressure. The enthalpy of water at SATP conditions is 45 Btu/lb.

Stationary combustion turbine means all equipment, including but not limited to the combustion turbine engine, the fuel, air, lubrica tion and exhaust gas systems, control systems, heat recovery system, steam turbine, fuel compressor, heater, and/or pump, post-combustion emission control technology, and any ancillary components a nd sub-components plus anyPage **22** of **45**

integrated equipment that provides electricity or useful thermal output to the combustion turbine engine, heat recovery system or auxiliary equipment. Stationary means that the combustion turbine is not self propelled or intended to be propelled while performing its function. It may, however, be mounted on a vehicle for portability.

Useful thermal output means the thermal energy made available for use in any heating application (e.g., steam delivered to an industrial process for a heating application, including thermal cooling applications) that is not used fo r electric generation, mechanical output at the affected facility, or to directly enhance the performance of the affected facility (e.g., economizer output is not useful thermal output, but thermal ener gy used to reduce fuel moisture is considered useful thermal output). Useful thermal output for affected facilities with no condensate return (or other thermal energy input to the affected facility) or where measuring the energy in the condensate (or other thermal energy input to the affected facility) would not meaningfully impact the emission rate calculation is measured agai nst the energy in the thermal output at SATP conditions. Affected facilities with meaningful en ergy in the condensate return (or other thermal energy input to the affected facility) must measur e the energy in the condensate and subtract that energy relative to SATP conditions from the measured thermal output.Page **23** of **45**

14. Table 2 to Subpart KKKK of Part 60 is added to read as follows:

Table 2 to Subpart KKKK of Part 60 – Carbon Dioxide Emission Limits for Stationary

Combustion Turbines

Note: all numerical values have a minimum of 2 significant figures

Affected Stationary Combustion Turbine CO 2 Emission Standard

Stationary combustion turbine that has a design heat input to the turbine engine of greater than 250 MW (850 MMBtu/h), that combusts over 90% natural gas on a heat input basis on a 3 year rolling average basis, and that supplieswhere net-electric sales consist of more than one-third of its potential electric output and more than 219,000 MWh netelectric output to a utility distribution system on a 3 year rolling average basis. 450 kilograms (kg) of CO 2 per megawatt-hour (MWh) of gross output (1,000 lb/MWh) on a 12-operating month rolling average

Stationary combustion turbine that has a design heat input to the turbine engine greater than 73 MW (250 MMBtu/h) and equal to or less than 250 MW (850 MMBtu/h), that combusts over 90% natural gas on a heat input basis on a 3 year rolling average basis, and where netelectric sales consist of that supplies more than one-third of its potential electric output and more than 219,000 MWh net-electric output to a utility distribution system on a 3 year rolling average basis.. 500 kg of CO 2 per MWh of gross output (1,100

lb CO 2 /MWh) on a 12-operating month rolling

average

Stationary combustion turb ine that either has a design heat input to the turbine engine of 73 MW (250 MMBtu/h) or less, that combusts 90% or less natural gas on a heat input basis on a 3 year rolling average basis, or where netelectric sales consist ofthat supplies one-third or less of its potential electric output or 219,000 MWh or less net-electric output to a utility distribution system on a 3 year rolling average basis. No emission standardPage **24** of **45**

15. Table 3 to Subpart KKKK of Part 60 is added to read as follows:

Table 3 to Subpart KKKK of Part 60 – Applicability of Subpart A General Provisions to Stationary Combustion Turbine CO 2 Emissions Standards in Subpart KKKK

General

Provisions

citation Subject of citation Applies to subpart

KKKK Explanation

§ 60.1 Applicability Yes
§ 60.2 Definitions Yes
§ 60.3 Units and Abbreviations Yes
§ 60.4 Address Yes

§ 60.5 Determination of

construction or

modification Yes

§ 60.6 Review of plans Yes

§ 60.7 Notification and Recordkeeping Yes Only the requirements to submit the notification in § 60.7(a)(1) and (a)(3)
§ 60.8 Performance tests No

§ 60.9 Availability of

Information Yes

§ 60.10 State authority Yes

§ 60.11 Compliance with

standards and

maintenance requirements No

§ 60.12 Circumvention Yes § 60.13 Monitoring requirements Yes

§ 60.14 Modification No

§ 60.15 Reconstruction No § 60.16 Priority list No

§ 60.17 Incorporations by

reference Yes

§ 60.18 General control device requirements No

§ 60.19 General notification and reporting requirements YesPage **25** of **45**

16. Part 60 is amended by adding subpart TTTT to read as follows:

Subpart TTTT -- Standards of Performance for Greenhouse Gas Emissions for Electric Utility Generating Units

Sec.

Applicability

§ 60.5508 What is the purpose of this subpart? § 60.5509 Am I subject to this subpart?

Emission Standards

§ 60.5515 What greenhouse gases are regulated by this subpart? § 60.5520 What CO 2 emissions standard must I meet?

General Compliance Requirements

§ 60.5525 What are my general requirements for complying with this subpart? § 60.5530 Affirmative defense for violati on of emission standards during malfunction

Monitoring and Compliance Determination Procedures

§ 60.5535 How do I monitor and collect data to demonstrate compliance? § 60.5540 How do I demonstrate compliance with my CO 2 emissions standard and

determine excess emissions?

Notifications, Reports, and Records

§ 60.5550 What notifications must I submit and when? § 60.5555 What reports must I submit and when? § 60.5560 What records must I maintain? § 60.5565 In what form and how long must I keep my records?

Other Requirements and Information

§ 60.5570 What parts of the General Provisions apply to my affected facility? § 60.5575 Who implements and enforces this subpart? § 60.5580 What definitions apply to this subpart?

Applicability

§ 60.5508 What is the purpose of this subpart?

This subpart establishes emission standards and compliance schedules for the control of greenhouse gas (GHG) emissions from a steam generating unit, IGCC, or a stationary combustion turbine that commences construction after January 8, 2014 or commences Comment [FC15]: Make consistentPage **26** of **45**

modification or reconstruction after [INS ERT DATE OF PUBLICATION IN THE FEDERAL REGISTER].

§ 60.5509 Am I subject to this subpart?

(a) Except as provided for in paragraph (b) of this section, the subpart applies to any steam generating unit, IGCC, or stationary combustion turbine that serves a generator capable of selling greater than 25 MW t o a utility power distribution system and that commences construction after January 8, 2014 or commences modification or reconstruction after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER].

(b) You are not subject to the requirements of th is subpart if your affected facility meets any one of the conditions specified in paragraphs (b)(1) through (b)(5) of this section.

(1) The proposed Wolverine EGU project described in Permit to Install No. 317-07 issued by the Michigan Department of Environm ental Quality, Air Quality Division, effective June 29, 2011 (as revised July 12, 2011).

(2) The proposed Washington County EGU project described in Air Quality Permit No. 4911-303-0051-P-01-0 issued by the Georgia Department of Natural Resources, Environmental Protection Division, Air Protection Branch, eff ective April 8, 2010, provided that construction had not commenced for NSPS purposes as of January 8, 2014.

(3) The proposed Holcomb EGU project described in Air Emission Source Construction Permit 0550023 issued by the Kansas Department of Health and Environment, Division of Environment, effective December 16, 2010, provided that construction had not commenced for NSPS purposes as of January 8, 2014.

(4) Your affected facility is a municipal wast e combustor unit that is subject to subpart Eb of this part.

(5) Your affected facility is a commercial or industrial solid waste incineration unit that is subject to subpart CCCC of this part.

Emission Standards

§ 60.5515 What greenhouse gases are regulated by this subpart?

(a) The greenhouse gas regulated by this subpart is carbon dioxide (CO 2 ).

(b) PSD and Title V Thresholds for Green house Gases. (1) For purposes of 40 CFR 51.166(b)(49)(ii), with respect to GH G emissions from aff ected facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 51.166(b)(48) and in any SIP approved by the EPA that is interpreted to incorporate, or specifically incorporates, 40 CFR 51.166(b)(48).

(2) For purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG emissions from affected facilities, the “pollutant that is subj ect to the standard promulgated under section

111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 52.21(b)(49).

(3) For purposes of 40 CFR 70.2, with respect to greenhouse gas emissions from affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” Comment [FC16]: Add to avoid covering large industrial units that to not generate sufficient electricity to be subject to the 219,000 MWh requirement.Page **27** of **45**

shall be considered to be the pollutant that otherwise is "subject to regulation" as defined in 40

CFR 70.2.

(4) For purposes of 40 CFR 71.2, with respect to greenhouse gas emissions from affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is "subject to regulation" as defined in 40

CFR 71.2.

§ 60.5520 What CO 2 emissions standard must I meet?

(a) For each affected facility subject to this subpart, you must not discharge from the affected facility stack into the atmosphere any gases that contain CO 2 in excess of the applicable

CO 2 emissions standard specified in Table 1 or Table 2 to this subpart, as applicable (e.g., the emission standards in Table 2 are not applicable to steam generating units and IGCC facilities subject to an approved CAA section 111(d) plan), of this subpart , except for owners and operators of modified affected facilities complying with the standards specified in paragraph (b) of this section, as applicable to the affected facility.

(b) The owner or operator of a modified steam generating unit or IGCC facility complying with the requirements of this paragrap h are not required to comply with the emission limit in Table 2 to this subpart.

(1) If the affected facility is not subject to an approved CAA section 111(d) plan (state or federal), the owner/operator may elect to comply with a site-specific 12-operating month rolling average CO 2 emission limit calculated as 2 percent lower than (i.e., 98 percent) the best demonstrated annual historical operating perform ance for the affected facility using historical

CO 2 emissions data for the calendar years 2002 through the most recent full calendar year the affected facility was operating prior to the modifi cation using either recorded net output emission rate data or gross electrical output and CO 2 emissions data as reported under part 75 of this chapter. If incomplete or no data has been submitted under part 75 of this chapter, the Administrator or delgated authority shall ap prove the use of alternate data sources. The equivalent net output-based standard shall be calculated from gross output-based data assuming a 7.5 percent auxiliary (i.e., parasitic) load (i.e., the best annual value is divided by 0.925); or

(2) If the affected facility is subject to an approved CAA section 111(d) plan (state or federal), a site-specific 12-operating month rolling average CO 2 emission limit determined by the CAA section 111(d) implementing authority based on the affected facility performing an energy assessment by an energy professional or engineer that have expertise in evaluating energy systems to identify appli cable energy efficiency projects that you will implement at the affected facility to improve the affected facility’s operating performance. You must maintain a copy of the most recent energy assessment report. The energy assessment must include at a minimum the elements in paragraphs (b)(2)(i) through (b)(2)(iii) of this section.

(i) A visual inspection of the facility to identify steam leaks or other sources of reduced efficiency,

(ii) A review of available engineering pl ans and facility operation and maintenance procedures and logs, and

(iii) A comprehensive report detailing the ways to improve efficiency, the cost of specific improvements, benefits, and the time frame for recouping those investments.Page **28** of **45**

General Compliance Requirements

§ 60.5525 What are my general requirements for complying with this subpart?

(a) You must be in compliance with the emissi on standards in this subpart that apply to your affected facility at all times. However, you must make a compliance determination only at the end of the applicable operating month, as provided in paragraphs (a)(1) and (2) of this

section.

(1) For each affected facility subject to a CO 2 emissions standard based on a 12-operating month rolling average, you must determine co mpliance monthly by calculating the average CO 2 emissions rate for the affected facility at the end of each 12-operating month period.

(2) For each affected facility subject to a CO 2 emissions standard based on an 84- operating month rolling average, you must determine compliance monthly by calculating the average CO 2 emissions rate for the affected facility at the end of each 84-operating month period.

(b) At all times you must operate and maintain each affected facility, including associated equipment and monitoring equipment, in a manner consistent with safety and good air pollution control practice. The Administrator will determin e if you are using consistent operation and maintenance procedures based on information ava ilable to the Administrator that may include, but is not limited to, fuel use records, monitori ng results, review of operation and maintenance procedures and r ecords, review of reports required by this subpart, and inspection of the facility.

(c) You must conduct an initial compliance determination for your affected facility for the applicable emissions standard in § 60.5520, according to the requirements in this subpart, within 30 days after the end of the initial compliance period for the CO 2 emissions standards applicable to your affected facility (i.e., 12-ope rating months or 84-operating months). The first operating month included in this compliance period is the month in which emissions reporting is required to begin under §75.64(a) of this chapter.

§ 60.5530 Affirmative defense for violation of emission standards during malfunction.

In response to an action to enforce the standards set forth in § 60.5520, you may assert an affirmative defense to a claim for civil penalties fo r violations of such standards that are caused by malfunction, as defined at 40 CFR 60.2. Appropriate penalties may be assessed if you fail to meet your burden of proving all of the requirements in the affirmative defense. The affirmative defense shall not be available for claims for injunctive relief.

(a) Assertion of affirmative defense. To establish the affirmative defense in any action to enforce such a standard, you must timely meet the reporting requirements in paragraph (b) of this section, and must prove by a preponderance of evidence that:

(1) The violation:

(i) Was caused by a sudden, infrequent, and unavoidable failure of air pollution control equipment, process equipment, or a process to operate in a normal or usual manner; and

(ii) Could not have been prevented through careful planning, proper design or better operation and maintenance practices;

(iii) Did not stem from any activity or event that could have been foreseen and avoided, or planned for;Page **29** of **45**

(iv) Was not part of a recurring pattern indicative of inadequate design, operation, or maintenance;

(2) Repairs were made as ex peditiously as possible when the violation occurred;

(3) The frequency, amount and duration of the violation (including any bypass) were minimized to the maximum extent practicable;

(4) If the violation resulted from a bypass of control equipment or a process, then the bypass was unavoidable to prevent loss of life, personal injury, or severe property damage;

(5) All possible steps were taken to minimize the impact of the violation on ambient air quality, the environment, and human health;

(6) All emissions monitoring and control syst ems were kept in operation if at all possible, consistent with safety and good air pollution control practices;

(7) All of the actions in response to the violation were documented by properly signed, contemporaneous operating logs;

(8) At all times, the affected source was operated in a manner consistent with good practices for minimizing emissions; and

(9) A written root cause analysis has been prepared, the purpose of which is to determine, correct, and eliminate the primary causes of the ma lfunction and the violation resulting from the malfunction event at issue. The analysis shall also specify, using best monitoring methods and engineering judgment, the amount of any emissions that were the result of the malfunction.

(b) Report. The owner or operator seeking to assert an affirmative defense shall submit a written report to the Administrator to demonstrat e, with all necessary supporting documentation, that it has met the requirements set forth in paragraph (a) of this section. This affirmative defense report is due after the initial occurrence of the exceedance of the standard in § 60.5520, and on the same quarterly reporting schedule as in § 60.5555 (which may be the end of any applicable averaging period). If such quarterly report is due less than 45 days afte r the initial occurrence of the violation, the affirmative defense report may be included in the following quarterly report required in § 60.5555(a).

Monitoring and Compliance Determination Procedures

§ 60.5535 How do I monitor and collect data to demonstrate compliance?

(a) You must prepare a monitoring plan in accordance with the applicable provisions in § 75.53(g) and (h) of this chapter.

(b) You must measure the hourly CO 2 mass emissions from each affected facility using the procedures in paragraphs (b)(1) through (5) of this section, except as provided in paragraph (c) of this section.

(1) You must install, certify, ope rate, maintain, and calibrate a CO 2 continuous emission monitoring system (CEMS) to directly measure and record CO 2 concentrations in the affected facility exhaust gases emitted to the atmosphere and an exhaust gas flow rate monitoring system according to § 75.10(a)(3)(i) of this chapter. If you measure CO 2 concentration on a dry basis, you must also install, certify, operate, maintain, and calibrate a continuous moisture monitoring system, according to § 75.11(b) of this chapter.Page **30** of **45**

(2) For each monitoring system you use to determine the CO 2 mass emissions, you must meet the applicable certification and quality assurance procedures in § 75.20 of this chapter and Appendices B and D to part 75 of this chapter.

(3) You must use a laser device to measure the dimensions of each exhaust gas stack or

duct at the flow monitor and the reference met hod sampling locations prior to the initial setup (characterization) of the flow monitor. For circ ular stacks, you must measure the diameter at three or more distinct locations and average the results. For rectangular stacks or ducts, you must measure each dimension (i.e., depth and width) at three or more distinct locations and average

the results. If the flow rate m onitor or reference method sampling site is relocated, you must repeat these measurements at the new location.

(4) You must use only unadjusted exhaust ga s volumetric flow rates to determine the hourly CO 2 mass emissions from the affected facility; you must not apply the bias adjustment factors described in section 7.6.5 of Appendix A to part 75 of this chapter to the exhaust gas flow

rate data.

(5) If you choose to use Method 2 in Appendix A-1 to this part to perform the required relative accuracy test audits (RATAs) of the part 75 flow rate monitoring system, you must use a calibrated Type-S pitot tube or pitot tube asse mbly. You must not use th e default Type-S pitot

tube coefficient.

(c) If your affected facility exclusively combus ts liquid fuel and/or gaseous fuel as an alternative to complying with paragraph (b) of this section, you may determine the hourly CO 2 mass emissions by using Equation G-4 in Appendix G to part 75 of this chapter according to the requirements in paragraphs (c)(1) and (2) of this section.

(1) You must implement the applicable procedures in appendix D to part 75 of this chapter to determine hourly unit heat input rates (MMBtu/h), based on hourly measurements of fuel flow rate and periodic determinations of the gross calorific value (GCV) of each fuel

combusted.

(2) You may determine site-specific carbon-based F-factors (F

c ) using Equation F-7b in section 3.3.6 of appendix F to part 75 of this chapter, and you may use these F

c values in the emissions calculations instead of using the default F

c values in the Equation G-4 nomenclature.

(d) You must install, calibrate, maintain, and operate a sufficient nu mber of watt meters to continuously measure and record the gross or net electric output from th e affected facility. Measurements must be performed using 0.2 cl ass electricity metering instrumentation and calibration procedures as specified under ANSI Standards No. C12.20. If the affected facility is a CHP facility, you must also install, calibrate, maintain, and operate meters to continuously determine and record the total useful recovered thermal energy. For process steam applications, you will need to install, calibrate, maintain, and operate meters to continuously determine and record steam flow rate, temperature, and pressure. If the affected facility has a direct mechanical drive application, you must submit a plan to the Administrator or delegated authority for approval of how gross or net energy output will be determined. Your plan shall ensure that you install, calibrate, maintain, and operate meters to continuously determine and record each component of the determination.

(e) If two or more affected facilities se rve a common electric generator, you must apportion the combined hourly gross or net output to the individual affected facilities using aPage **31** of **45**

plan approved by the Administrator (e.g., using steam load or heat input to each affected EGU). Your plan shall ensure that you install, calibra te, maintain, and operate meters to continuously determine and record each component of the determination.

(f) In accordance with § 60.13(g), if two or more affected facilities that implement the continuous emission monitoring provisions in paragraph (b) of this section share a common exhaust gas stack and are subject to the same emissions standard under § 60.5520, you may monitor the hourly CO 2 mass emissions at the common stack in lieu of monitoring each EGU separately. If you choose this option, the hourly gross or net load (electric, thermal, and/or mechanical, as applicable) must be the sum of th e hourly loads for the individual affected facility and you must express the operating time as “stack operating hours” (as defined in § 72.2 of this chapter). If you attain compliance with the applicable emissions standard in § 60.5520 at the common stack, each affected facility sharing the stack is in compliance.

(g) In accordance with § 60.13(g), if the exhaust gases from an affected facility that implements the continuous emission monitoring prov isions in paragraph (b) of this section are emitted to the atmosphere through multiple stacks (or if the exhaust gases are routed to a common stack through multiple ducts and you elect to monitor in the ducts), you must monitor the hourly CO 2 mass emissions and the “stack operati ng time” (as defined in § 72.2 of this chapter) at each stack or duct separately. In this case, you must determine compliance with the applicable emissions standard in § 60.5520 by summing the CO 2 mass emissions measured at the individual stacks or ducts and dividing by the total gross or net output for the affected facility.

§60.5540 How do I demonstrate compliance with my CO 2 emissions standard and

determine excess emissions?

(a) You must calculate the CO 2 mass emissions rate for your affected facility by using the hourly CO 2 mass emissions and total gross or net output data determined and recorded according to the procedures in § 60.5535 for each operating hour in the compliance period for the CO 2 emissions standard applicable to the affected facility (i.e., 12- or 84-operating month rolling average period), and the calculation procedures in paragraphs (a)(1) through (a)(5) of this

section.

(1) You can only use operating hours in the compliance period for the compliance determination calculation if valid data are obtained for all parameters you used to determine the hourly CO 2 mass emissions and the gross or net output data are used for the compliance

determination calculation. You must not include operating hours in which you used the substitute data provisions of part 75 of this chapter for any of those parameters in the calculation. For the compliance determination calculation, you must obtain valid hourly CO 2 mass emission values for a minimum of 95 percent of the operating hours in the compliance period for the CO 2 emissions standard applicable to the affected facility.

(2) You must calculate the total CO 2 mass emissions by summing the valid hourly CO 2 mass emissions values for all of the operating hours in the applicable compliance period.

(3) For each operating hour of the compliance period that you used in paragraph (a)(2) of

this section to calculate the total CO 2 mass emissions, you must dete rmine the affected facility’s corresponding hourly gross or net output according to the procedures in paragraphs (a)(3)(i) and (ii) of this section, as appropriate for the type of affected facility. For an operating hour in which there is no gross or net electric load, but there is mechanical or useful thermal output, you mustPage **32** of **45**

still determine the gross or net output for that hour. In additio n, for operating hours in which there is no useful output, you still need to determine the CO 2 emissions for that hour. For hours or partial hours where there is no gross gene ration, net electric output shall be zero.

(i) Calculate P gross /net for your affected facility using the following equation:

ܲ

௚௥௢௦௦ /௡௘௧ = ሺ ܲ݁ ሻ ௌ் ൅ ሺ ܲ݁ ሻ ஼் ൅ ሺ ܲ݁ ሻ ூா െ ሺܲ݁ሻ ிௐ
T ൅ 	0.75 ൈ ሾ ሺ ܲݐ ሻ ௉ௌ ൅ ሺ ܲݐ ሻ ுோ ൅ ሺ ܲݐ ሻ ூா ሿ

Where: a

P gross /net = Gross or net energy output of your affected facility in megawatt-hours in ( MWh )

. (Pe) ST = Electric energy output plus mechanic al energy output (if any) of steam

turbines in MWh.

(Pe) CT = Electric energy output plus mechanical energy output (if any) of stationary combustion turbine(s) in MWh.

(Pe) IE = Electric energy output plus mechanic al energy output (if any) of your affected facility’s integrated equipment that provides electricity or mechanical energy to the affected facility or auxiliary equipment in MWh.

(Pe) FW = Electric energy used to power boiler feedwater pumps at steam generating units in MWh. Not applicable to stationary combustion turbines , or IGCC

facilities , or facilities complying with a net output based standard

. (Pt) PS = Useful thermal energy output of steam ( measured relative to ISO SATP

conditions , as applicable) that is used for applications that do not generate additional electricity, pro duce mechanical energy output, or enhance the performance of the affected facility. This is Cc alculated using the equation specified in paragraph (g)(3)(iii )(B) of this section in MWh.

(Pt) HR = Hourly useful thermal energy output ( measured relative to ISO SATP

conditions , as applicable) from heat recovery that is used for applications other than steam generation or performance enhancement of the affected facility in MWh.

(Pt) IE = Useful thermal energy output ( relative to ISO SATP conditions , as applicable) from any integrated equipment that provides thermal energy to the affected facility or auxiliary equipment in MWh.

T = Electric Transmission and Distribution Factor.

T = 0.95 for a combined heat and power affected facility where at least on an annual basis 20.0 percent of the total gross or net energy output consists

of electric or direct mech anical output and 20.0 percent of the total gross

or net energy output consists of useful thermal energy output on a rolling 3 year basis.

T = 1.0 for all other affected facilities.Page **33** of **45**

(ii) If applicable to your affected facility, you must calculate (Pt) PS using the following equation:

ሺܲݐሻ ௉ௌ ൌ ܳ
௠ ൈ 	ܪ

3.6	 ൈ	 10 ଽ

Where:

Q

m = Measured steam flow in kilograms (kg) (or pounds (lb)) for the operating

hour.

H = Enthalpy of the steam at measured temperature and pressure ( relative to

ISO SATP conditions , as applicable) in Joules per kilogram (J/kg) (or Btu/lb).

3.6 x 10 9 = Conversion factor (J/MWh) (or 3.413 x 10 6 Btu/MWh).

(4) You must calculate the total gross or net output for the affected facility’s compliance period by summing the hourly gross or net output values for the affected facility that you determined from paragraph (a)(2) of this section for all of the operating hours in the applicable compliance period.

(5) You must calculate the CO 2 mass emissions rate for the affected facility by dividing

the total CO 2 mass emissions value calculated according to the procedures in paragraph (a)(2) of this section by the total gross or net output value calculated according to the procedures in paragraph (a)(4) of this section.

(b) If the CO 2 mass emissions rate for your affected facility that you determined according to the procedures specified in paragraph (a) of this section is less than or equal to the

CO 2 emissions standard in Table 1 of this subpart applicable to the affected facility, then your affected facility is in compliance with the emissions standard. If the average CO 2 mass emissions rate is greater than the CO 2 emissions standard in Table 1 of this subpart applicable to the affected facility, then your affected facility has excess CO 2 emissions.

Notification, Reports, and Records

§ 60.5550 What notifications must I submit and when?

(a) You must prepare and submit the notifications specified in §§ 60.7(a)(1) and (a)(3) and 60.19, as applicable to your affected facility.

(b) You must prepare and submit notifications specified in § 75.61 of this chapter, as applicable to your affected facility.

§ 60.5555 What reports must I submit and when?

(a) You must prepare and submit reports according to paragraphs (a) through (d) of this section, as applicable.

(1) For affected facilities that are required by § 60.5525 to conduct initial and on-going compliance determinations on a 12- or 84-operating month rolling average basis for the standard in § 60.5520 you must submit electronic quarterly reports as follows. After you have accumulated the first 12-operating months for the affected facility (or, the first 84-operatingPage **34** of **45**

months for an affected facility electing to comply with the 84 -operating month standard), you must submit a report for the calendar quarter that includes the twelfth (or eighty-fourth) operating month no later than 30 days after the end of that quarter. Thereafter, you must submit a report for each subsequent calendar quarter, no later than 30 days after the end of the quarter.

(2) In each quarterly report you must include the following information, as applicable:

(i) Each rolling average CO 2 mass emissions rate for which the last (12th or eightyfourth) operating month in a 12- or 84-operating month compliance period falls within the calendar quarter. You must calculate each average CO 2 mass emissions rate according to the procedures in § 60.5540. You must report the dates (month and year) of the first and twelfth (or eighty-fourth) operating months in each compliance period for which you performed a CO 2 mass emissions rate calculation. If there are no compliance periods that end in the quarter, you must include a statement to that effect;

(ii) If one or more compliance periods end in the quarter you must identify each operating month in the calendar quarter with excess CO 2 emissions;

(iii) The percentage of valid CO 2 mass emission rates (as defined in § 60.5540) in each 12- or 84-operating month compliance period descri bed in paragraph (a)(1)(i) of this section (i.e.,

the total number of valid CO 2 mass emission rates in that peri od divided by the total number of operating hours in that period, multiplied by 100 percent); and

(iv) The CO 2 emissions standard (as identified in Table 1 of this subpart) with which your affected facility is complying.

(3) In the final quarterly report of each calendar year, you must include the following:

(i) Gross electric output sold to an electric grid over the 4 quarters of the calendar year;

and

(ii) The potential electric output of the facility.

(b) You must submit all electronic reports re quired under paragraph (a) of this section using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool provided by

the Clean Air Markets Division in the Of fice of Atmospheric Programs of EPA.

(c) You must meet all applicable reporting requirements and submit reports as required under subpart G of part 75 of this chapter.

(d) If your affected unit employs geologic se questration to meet th e applicable emission limit, you must report in accordance with the requirements of 40 CFR part 98, subpart PP and

either:

(1) if injection occurs onsite, report in accordance with the requirements of 40 CFR part 98, subpart RR, or

(2) if injection occurs offsite, transfer the captured CO 2 to a facility or facilities that reports in accordance with the requirements of 40 CFR part 98, subpart RR.

§ 60.5560 What records must I maintain?

(a) You must maintain records of the info rmation you used to demonstrate compliance with this subpart as specified in § 60.7(b) and (f).Page **35** of **45**

(b) You must follow the applicable recordkeeping requirements and maintain records as required under subpart F of part 75 of this chapter.

(c) You must keep records of the calculati ons you performed to determine the total CO 2 mass emissions for:

(1) Each operating month (for all affected units);

(2) Each compliance period, including, as applicable, each 12-operating month compliance period and the 84-operating month compliance period.

(d) You must keep records of the applicable data recorded and calculations performed that you used to determine your affected facility’s gross or net output for each operating month.

(e) You must keep records of the calculations you performed to determine the percentage

of valid CO 2 mass emission rates in each compliance period.

(f) You must keep records of the calculations you performed to assess compliance with each applicable CO 2 mass emissions standard in § 60.5520.

(g) You must keep records of the calculations you performed to determine any sitespecific carbon-based F-factors you used in the emissions calculations (if applicable).

§ 60.5565 In what form and how long must I keep my records?

(a) Your records must be in a form suitable and readily available for expeditious review.

(b) You must maintain each record for 5 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record except those records required to demonstrate compliance with an 84-operating month compliance period. You must maintain records required to demonstrate compliance with an 84-operating month compliance period for at least 10 years following the date of each occurrence, measurement, maintenance, corrective action, report, or record.

(c) You must maintain each record on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to § 60.7. You may maintain the records off site and electronically for the remaining year(s) as required by this subpart.

Other Requirements and Information

§ 60.5570 What parts of the General Provisions apply to my affected facility?

Notwithstanding any other provision of this chapter, certain parts of the General Provisions in §§ 60.1 through 60.19, listed in Table 2 of this subpart, do not apply to your affected facility.

§ 60.5575 Who implements and enforces this subpart?

(a) This subpart can be implemented and enforced by the EPA, or a delegated authority such as your state, local, or tribal agency. If the Administrator has delegated authority to your state, local, or tribal agency, then that agency (as well as the EPA) has the authority to implement and enforce this subpart. You should contact your EPA Regional Office to find out if this subpart is delegated to your state, local, or tribal agency.

(b) In delegating implementation and enforcement authority of this subpart to a state,Page **36** of **45**

local, or tribal agency, the Administrator reta ins the authorities listed in paragraphs (b)(1) through (5) of this section and does not transfer them to the state, local, or tribal agency. In addition, the EPA retains oversight of this subpart and can take enforcement actions, as appropriate.

(1) Approval of alternatives to the emission standards.

(2) Approval of major alternatives to test methods.

(3) Approval of major alte rnatives to monitoring.

(4) Approval of major alternatives to recordkeeping and reporting.

(5) Performance test and data reduction waivers under § 60.8(b).

§ 60.5580 What definitions apply to this subpart?

As used in this subpart, all terms not define d herein will have the meaning given them in the Clean Air Act and in subpart A (General Provisions of this part).

Affirmative defense means, in the context of an enforcement proceeding, a response or defense put forward by a defendant, regarding which the defendant has the burden of proof, and the merits of which are independently and object ively evaluated in a judicial or administrative proceeding.

Base load rating means the maximum amount of heat input (fuel) that a steam generating unit can combust on a steady state basis, as determ ined by the physical design and characteristics of the steam generating unit at ISO conditions. For a stationary combustion turbine, base load rating means 100 percent of the design heat input capacity of the simple cycle portion of the stationary combustion turbine at ISO conditions (heat input from duct burners is not included).

Coal means all solid fuels classified as anthr acite, bituminous, subbituminous, or lignite by the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see § 60.17), coal refuse, and petroleum coke. Synthetic fuels derived from coal for the purpose of creating useful heat, including but not limited to solvent-refined coal, gasified coal (not meeting the definition of natural gas), coal-oil mi xtures, and coal-water mixtures are included in this definition for the purposes of this subpart.

Coal refuse means waste products of coal mining, physical coal cleaning, and coal preparation operations ( e.g. culm, gob, etc.) containing coal, matrix material, clay, and other organic and inorganic material.

Combined cycle facility means an electric generating unit that uses a stationary

combustion turbine from which the heat from the turbine exhaust gases is recovered by a heat recovery steam generating unit to generate additional electricity.

Combined heat and power facility or CHP facility , ( also known as “cogeneration”) means an electric generating unit that that use a steam-g enerating unit or stationary combustion turbine to simultaneously produce both electric (or mechanical) and useful thermal energy from the same primary energy source.

Distillate oil means fuel oils that contain no more than 0.05 weight percent nitrogen and comply with the specifications for fuel oil numbers 1 and 2, as defined by the American Society of Testing and Materials in ASTM D396 (incorporated by reference, see § 60.17); diesel fuel oilPage **37** of **45**

numbers 1 and 2, as defined by the American Society for Testing and Materials in ASTM D975 (incorporated by reference, see § 60.17); kerosene, as defined by the American Society of Testing and Materials in ASTM D3699 (incorporated by reference, see § 60.17); biodiesel as defined by the American Society of Testing and Materials in ASTM D6751 (incorporated by reference, see § 60.17); or biodiesel blends as defined by the American Society of Testing and Materials in ASTM D7467 (incorporated by reference, see § 60.17).

Excess emissions means a specified averaging period over which the CO 2 emissions rate is higher than the applicable emissions standard located in Table 1 of this subpart.

Fossil fuel means natural gas, petroleum, coal, and any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating useful heat.

Gaseous fuel means any fuel that is present as a gas at ISO conditions and includes, but is not limited to, natural gas, refinery fuel gas, process gas, coke-oven gas, synthetic gas, and gasified coal.

Gross energy output means:

(1) For stationary combustion turbines and IG CC facilities, the gross electric or direct mechanical output from both the unit (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) plus 75 percent of the useful thermal output

measured relative to ISO conditions that is not used to genera te additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application)

. (2) For electric utility steam generating uni ts, the gross electric or mechanical output from the affected facility (including, but not lim ited to, output from stea m turbine(s), combustion turbine(s), and gas expander(s)) minus any electrici ty used to power the feedwater pumps plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application) ;

(3) For combined heat and power facilities wh ere at least 20.0 percent of the total gross energy output consists of electric or direct mech anical output and 20.0 percent of the total gross energy output consists of thermal output on a rolling 3 year basis, the gross electric or mechanical output from the affected facility (i ncluding, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander (s)) minus any electricity used to power the feedwater pumps (the electric auxiliary load of boiler feedwater pumps is not applicable to IGCC facilities), that difference divided by 0.95, plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to ge nerate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial process for a heating application)

. Heat recovery steam generating unit (HRSG) means a unit in which hot exhaust gases from the combustion turbine engine are routed in order to extract heat from the gases and generate useful output. Heat recovery steam gene rating units can be used with or without duct

burners.

Integrated gasification combined cycle facility or IGCC facility means a combined cycle facility that has a design heat input greater th an 73 MW (250MMBtu/h) heat input of fossil fuelPage **38** of **45**

(either alone or in combination with any other fuel), supplies where net-electric sales consists of one-third or more of its potential electric output and more than 219,000 MWh net-electric output to a utility distribution system on an annual basis, and is desi gned to burn fuels containing 50 percent (by heat input) or more solid-derived fuel not meeting the definition of natural gas plus any integrated equipment that provides electricity or useful thermal output to either the affected facility or auxiliary equipment. The Administra tor may waive the 50 per cent solid-derived fuel requirement during periods of the gasification sy stem construction, startup and commissioning, shutdown, or repair. No solid fuel is directly burned in the unit during operation.

ISO conditions means 288 Kelvin (15 o C), 60 percent relative humidity and 101.3 kilopascals pressure.

Liquid fuel means any fuel that is present as a liquid at IS O conditions and includes, but is not limited to, distillate oil and residual oil.

Mechanical output means the useful mechanical energy that is not used to operate the affected facility, generate electricity and/or thermal energy, or to enhance the performance of the affected facility. Mechanical energy measured in horsepower hour should be converted into MWh by multiplying it by 745.7 then dividing by 1,000,000.

Natural gas means a fluid mixture of hydrocarbons (e.g., methane, ethane, or propane), composed of at least 70 percent methane by volume or that has a gross calorific value between 35 and 41 megajoules (MJ) per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic foot), that maintains a gaseous state under ISO conditions. In addition, natural gas contains 20.0 grains or less of total sulfur per 100 standard cubic feet. Finally, natural gas does not include the following gaseous fuels: landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might result in highly variable sulfur content or heating value.

Net-electric output sales means:

(1) The gross electric sales to the utility power distribution system minus purchased

power on a three calendar year rolling average basis ; or

(2) For combined heat and power facilities wh ere at least 20.0 percent of the total gross energy output consists of electric or direct mechan ical output and at least 20.0 percent of the total gross energy output consists of useful thermal ou tput on a 3 calendar year rolling average basis, the gross electric sales to the utility power distribution system minus purchased power of the thermal host facility or facilities on a three calendar year rolling average basis; and.

(3) Electricity supplied to other facilities that produce electricity to offset auxiliary loads are included when calculating net-electric sales.

Net-electric output means: the amount of gross generation the generator(s) produces (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)), as measured at the generator terminals, less the electricity used to operate the plant (i.e., auxiliary loads); such uses include fuel handling equipment, pumps, fans, pollution control equipment, other electricity needs, and transformer losses as measured at the transmission side of the step up transformer (e.g., the point of sale).

Net energy output means:Page **39** of **45**

(i) Except as provided under paragraph (ii) of this definition, the net electric or mechanical output from the affected facility plus 75 percent of the useful thermal output; or

(ii) For combined heat and power facilities wh ere at least 20.0 percen t of the total gross or net energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross or net energy output consists of thermal output on a rolling 3 year basis, the net electric or mechanical output from the affected f acility divided by 0.95, plus 75 percent of the useful thermal output;

Oil means crude oil or petroleum or a fuel derived from crude oil or petroleum, including distillate and residual oil, and gases derived from solid oil-derived fuels (not meeting the definition of natural gas).

Operating month means a calendar month during which any fuel is combusted in the affected facility at any time.

Potential electric output means 33 percent or the design electric output efficiency on a net output basis multiplied by the maximum design h eat input capacity (expr essed in MMBtu/h) of the steam generating unit, multiplied by 10 6 Btu/MMBtu, divided by 3,413 Btu/KWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 h/yr (e.g., a 35 percent efficient affected facility with a 100 MW (341 MMBtu/h) fossil-fuel heat input capacity would have a 310,000 MWh 12 month potential electric output capacity).

Solid fuel means any fuel that has a definite shape and volume, has no tendency to flow or disperse under moderate stress, and is not li quid or gaseous at ISO conditions. This includes, but is not limited to, coal, biomass, and pulverized solid fuels.

Standard ambient temperature and pressure (SATP) conditions means 298.15 Kelvin (25 o C, 77 o F)) and 100.0 kilopascals (14.504 psi, 0.987 atm) pressure. The enthalpy of water at SATP conditions is 45 Btu/lb.

Stationary combustion turbine means all equipment, including but not limited to the turbine engine, the fuel, air, lubrication and exhaust gas systems, control systems (except emissions control equipment), heat recovery syst em, fuel compressor, heater, and/or pump, postcombustion emission control technology, and an y ancillary components and sub-components comprising any simple cycle stationary combustion turbine, any combined cycle combustion turbine, and any combined heat and power combustion turbine based system plus any integrated equipment that provides electricity or useful thermal output to the combustion turbine engine, heat recovery system or auxiliary equipment. Stationary means that the combustion turbine is not self propelled or intended to be propelled while performing its function. It may, however, be mounted on a vehicle for portability. If a statio nary combustion turbine burns any solid fuel directly it is considered a steam generating unit.

Steam generating unit means any furnace, boiler, or other device used for combusting fuel and producing steam (nuclear steam generators are not included) that has a design heat input greater than 73 MW (250MMBtu/h) heat input of fossil fuel (either alone or in combination with any other fuel) and that supplieswhere net-electric sales consist of one-third or more of its potential electric output and more than 219,000 MWh net-electric output to a utility distribution

system on an annual basis plus any integrated equipment that provides electricity or useful thermal output to the affected facility or auxiliary equipment.Page **40** of **45**

Useful thermal output means the thermal energy made available for use in any industrial or commercial process, or used in any heating or cooling application

, (e.g., steam delivered to an industrial process for a heating application, in cluding thermal cooling applications) i.e., total thermal energy made available for processes and applications other thanthat is not used for electric generation, mechanical output at the affected facility, or to directly enhance the performance of the affected facility (e.g., economizer output is not useful thermal output, but thermal energy used to reduce fuel moisture is considered useful thermal output)

. Useful

Tt hermal output for affected facilities with no condensate return (or other thermal energy input to the affected facility) or where measuring the energy in the condensate (or other thermal energy input to the affected facility) would not meanin gfully impact the emission rate calculation is measured against the energy in the thermal output at SATP conditions. Affected facilities with meaningful energy in the condensate return (or other thermal energy input to the affected facility) must measure the energy in the condensate and subtract that energy relative to SATP conditions from the measured thermal output. this subpart means the energy in recovered thermal output measured against the energy in the thermal output at ISO conditions

.Page **41** of **45**

Table 1 to Subpart TTTT of Part 60 – CO 2 Emission Standards for Affected Facilities that Commenced Construction after January 8, 2014

Note: all numerical values have a minimum of 2 significant figures

Affected Facility CO 2 Emission Standard Stationary combustion tu rbine that has a base load rating heat input to the turbine engine of greater than 250 MW (850 MMBtu/h), that combusts over 90% natural gas on a heat input basis on a 3 year rollin g average basis, and that supplieswhere net-electric sales consist of more than one-third of its potential electricoutput and more than 219,000 MWh netelectric output to a utility distribution system on a 3 year rolling average basis. 450 kilograms (kg) of CO 2 per megawatt-hour (MWh) of gross output (1,000 lb/MWh) on a 12-operating month rolling average

Stationary combustion turbine that has a design heat input to the turbine engine greater than 73 MW (250 MMBtu/h) and equal to or less than 250 MW (850 MMBtu/h), that combusts over 90% natural gas on a heat input basis on a 3 year rolling average basis, and where netelectric sales consist of that supplies more than one-third of its potential electric output and more than 219,000 MWh net-electric output to a utility distribution system on a 3 year rolling average basis. 500 kg of CO 2 per MWh of gross output (1,100

lb CO 2 /MWh) on a 12-operating month rolling

average

Steam generating unit that burns fossil fuel for more than 10.0 percent of the average annual heat input during a 3 year rolling average basis. 500 kg of CO 2 per MWh of gross energy output (1,100 lb CO 2 /MWh) on a 12-operating month rolling average basis;

or 480 kg of CO 2 per MWh of gross energy output (1,050 lb CO 2 /MWh) on an 84- operating month rolling average basis.

Integrated gasification combined cycle (IGCC) facility that burns fossil fuel for more than 10.0 percent of the average annual heat input during a 3 year rolling average basis. 500 kg of CO 2 per MWh of gross energy output (1,100 lb CO 2 /MWh) on a 12-operating month rolling average basis;

or 480 kg of CO 2 per MWh of gross energy output (1,050 lb CO 2 /MWh) on an 84- operating month rolling average basis.

Stationary combustion turb ine that either has a design heat input to the turbine engine of 73 MW (250 MMBtu/h) or less, that combusts 90% or less natural gas on a heat input basis on No emission standardPage **42** of **45**

a 3 year rolling average basis, or where netelectric sales consist of that supplies one-third or less of its potential electric output or 219,000 MWh or less net-electric output to a utility distribution system on a 3 year rolling average basis. Steam generating unit or IGCC facility that burns fossil fuel for 10.0 percent or less of the average annual heat input during a 3 year rolling average basis. No emission standardPage **43** of **45**

Table 2 to Subpart TTTT of Part 60 – CO 2 Emission Standards for Affected Facilities (Except Modified Steam Generating Units and IGCC Facilities Subject to an Approved CAA Section 111(d) Plan) 1 that Commenced Reconstructi on or Modification after [INSERT DATE OF PUBLICAITON IN THE FEDERAL REGISTER]

Note: all numerical values have a minimum of 2 significant figures

Affected Facility CO 2 Emission Standard Stationary combustion tu rbine that has a base load rating heat input to the turbine engine of greater than 250 MW (850 MMBtu/h), that combusts over 90% natural gas on a heat input basis on a 3 year rolling average basis,

and where net-electric sales consist of more than one-third of its po tential electric output and more than 219,000 MWh net-electric output to a utility distribution system on a 3 year rolling average basis. 460 kilograms (kg) of CO 2 per megawatt-hour (MWh) of gross output (1,000 lb/MWh) on a 12-operating month rolling average

Stationary combustion turbine that has a design heat input to the turbine engine greater than 73 MW (250 MMBtu/h) and equal to or less than 250 MW (850 MMBtu/h), that combusts over 90% natural gas on a heat input basis on a 3 year rolling average basis,

and where net-electric sales consist of more than one-third of its po tential electric output and more than 219,000 MWh net-electric output to a utility distribution system on a 3 year rolling average basis. 510 kg of CO 2 per MWh of gross output (1,100 lb CO 2 /MWh) on a 12-operating month rolling average

Stationary combustion tu rbine that either has a design heat input to the turbine engine of 73 MW (250 MMBtu/h) or less, that combusts 90% or less natural gas on a heat input basis on a 3 year rolling average basis, or where

net-electric sales consist of one-third or less of its potential electric output or 219,000 MWh or less net-electric output to a utility distribution system on a 3 year rolling average

basis. No emission standard

Steam generating unit or integrated gasification combined cycle (IGCC) facility that has a design heat input of 590 MW (2,000 MMBtu/h) or less and that burns fossil fuel for more than 10.0 percent of the average 950 kg of CO 2 per MWh of net energy output (2,100 lb CO 2 /MWh) on a 12-operating month rolling average basis;

1 The emission standards in Table 2 are not applicable to modified steam generating units and IGCC facilities subject to an approved CAA section 111(d) planPage **44** of **45**

annual heat input during a 3 year rolling average basis. Steam generating unit or IGCC facility that has a design heat input greater than 590 MW (2,000 MMBtu/h) and that burns fossil fuel for more than 10.0 percent of the average annual heat input during a 3 year rolling average basis. 860 kg of CO 2 per MWh of net energy output (1,900 lb CO 2 /MWh) on a 12-operating month rolling average basis;

Steam generating unit or IGCC facility that burns fossil fuel for 10.0 percent or less of the average annual heat input during a 3 year rolling average basis. No emission standardPage **45** of **45**

Table 32 to Subpart TTTT of Part 60 – Applicab ility of Subpart A General Provisions to Subpart TTTT

General

Provisions

citation Subject of citation Applies to subpart

TTTT Explanation

§ 60.1 Applicability Yes

§ 60.2 Definitions Yes Additional terms defined in § 60.5580
§ 60.3 Units and Abbreviations Yes
§ 60.4 Address Yes

§ 60.5 Determination of

construction or

modification Yes

§ 60.6 Review of plans Yes

§ 60.7 Notification and Recordkeeping Yes Only the requirements to submit the notification in § 60.7(a)(1) and (a)(3)
§ 60.8 Performance tests No

§ 60.9 Availability of

Information Yes

§ 60.10 State authority Yes

§ 60.11 Compliance with

standards and

maintenance requirements No

§ 60.12 Circumvention Yes § 60.13 Monitoring requirements Yes

§ 60.14 Modification No

§ 60.15 Reconstruction No § 60.16 Priority list No

§ 60.17 Incorporations by

reference Yes

§ 60.18 General control device requirements No

§ 60.19 General notification and reporting requirements Yes