SDAPCD RULE X-DA STDS.OF PERF.FOR ELEC.UTILITY STEAM GEN.               
LAST REVISED 05/24/82

               
               SUBPART Da - Standards of Performance for Electric Utility
                            Steam Generating Units Constructed After 
                            September 18, 1978 (Delegation Effective 5/24/82)


               RULE 260.40a.  APPLICABILITY AND DESIGNATION OF AFFECTED
                              FACILITY

               (a)  The affected facility to which this subpart applies is
          each electric utility steam generating unit:

                    (1)  That is capable of combusting more than 63 million
               kcal (250 million Btu/hour) heat input of fossil fuel
               (either alone or in combination of any other fuel); and

                    (2)  For which construction or modification is
               commenced after September 18, 1978.

               (b)  This subpart applies to electric utility combined cycle
          gas turbines that are capable of combusting more than 63 million
          kcal (250 million Btu/hour) heat input of fossil fuel in the
          steam generator.  Only emissions resulting from combustion of
          fuels in the steam generating unit are subject to this subpart.
          (The gas turbine emissions are subject to Subpart GG.)

               (c)  Any change to an existing fossil fuel-fired steam
          generating unit to accommodate the use of combustible materials,
          other than fossil fuels, shall not bring that unit under the
          applicability of this subpart.

               (d)  Any change to an existing steam generating unit
          originally designed to fire gaseous or liquid fossil fuels, to
          accommodate the use of any other fuel (fossil or nonfossil),
          shall not bring that unit under the applicability of this
          subpart.


               RULE 260.41a.  DEFINITIONS

               As used in this subpart, all terms not defined herein shall
          have the meaning given them in the Act and in Subpart A of this
          Regulation.

               (a)  "Steam Generating Unit" means any furnace, boiler, or
          other device used for combusting fuel for the purpose of
          producing steam (including fossil fuel-fired steam generators
          associated with combined cycle gas turbines; nuclear steam
          generators are not included).

               (b)  "Electric Utility Steam Generating Unit" means any
          steam electric generating unit that is constructed for the
          purpose of supplying more than one-third of its potential
          electric output capacity and more than 25 MW electrical output to
          any utility power distribution system for sale.  Any steam
          supplied to a steam distribution system for the purpose of
          providing steam to a steam-electric generator that would produce
          electrical energy for sale is also considered in determining the
          electrical energy output capacity of the affected facility.

               (c)  "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.

               (d)  "Subbituminous Coal" means coal that is classified as
          subbituminous A, B, or C according to the American Society of
          Testing and Materials' (ASTM) Standard Specification for
          Classification of Coals by Rank D388-66.

               (e)  "Lignite" means coal that is classified as lignite A or
          B according to the American Society of Testing and Materials'
          (ASTM) Standard Specification for Classification of Coals by Rank
          D388-66.

               (f)  "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.

               (g)  "Potential Combustion Concentration" means the
          theoretical emissions (ng/J, lb/million Btu heat input) that
          would result from combustion of a fuel in an uncleaned state
          without emission control systems, and

                    (1)  For particulate matter is:

                         (i)  3,000 ng/J (7.0 lb/million Btu) heat input
                    for solid fuel; and

                         (ii) 75 ng/J (0.17 lb/million Btu) heat input for
                    liquid fuels.

                    (2)  For sulfur dioxide is determined under Subsection
               60.48a(b) of Part 60, Chapter I, Title 40, Code of Federal
               Regulations, Section 60.48a.

                    (3)  For nitrogen oxides is:

                         (i)  290 ng/J (0.67 lb/million Btu) heat input for
                    gaseous fuels;

                         (ii) 310 ng/J (0.72 lb/million Btu) heat input for
                    liquid fuels; and

                         (iii)990 ng/J (2.30 lb/million Btu) heat input for
                    solid fuels.

               (h)  "Combined Cycle Gas Turbine" means a stationary turbine
          combustion system where heat from the turbine exhaust  gases is
          recovered by a steam generating unit.

               (i)  "Interconncected" means that two or more electric
          generating units are electrically tied together by a network of
          power transmission lines, and other power transmission equipment.

               (j)  "Electric Utility Company" means the largest
          interconnected organization, business, or governmental entity
          that generates electric power for sale (e.g., a holding company
          with operating subsidiary companies).

               (k)  "Principal Company" means the electric utility company
          or companies which own the affected facility.

               (l)  "Neighboring Company" means any one of those electric
          utility companies with one or more electric power
          interconnections to the principal company and which have
          geographically adjoining service areas.

               (m)  "Net System Capacity" means the sum of the net electric
          generating capability (not necessarily equal to rated capacity)
          of all electric generating equipment owned by an electric utility
          company (including steam generating units, internal combustion
          engines, gas turbines, nuclear units, hydroelectric units, and
          all other electric generating equipment) plus firm contractual
          purchases that are interconnected to the affected facility that
          has the malfunctioning flue gas desulfurization system.  The
          electric generating capability of equipment under multiple
          ownership is prorated based on ownership unless the proportional
          entitlement to electric output is otherwise established by
          contractual arrangement.

               (n)  "System Load" means the entire electric demand of an
          electric utility company's service area interconnected with the
          affected facility that has the malfunctioning flue gas desul-
          furization system plus firm contractual sales to other electric
          utility companies.  Sales to other electric utility companies
          (e.g., emergency power) not on a firm contractual basis may also
          be included in the system load when no available system capacity
          exists in the electric utility company to which the power is
          supplied for sale.

               (o)  "System Emergency Reserve" means an amount of electric
          generating capacity equivalent to the rated capacity of the
          single largest electric generating unit in the electric utility
          company (including steam generating units, internal combustion
          engines, gas turbines, nuclear units, hydroelectric units, and
          all other electric generating equipment) which is interconnected
          with the affected facility that has the malfunctioning flue gas
          desulfurization system.  The electric generating capability of
          equipment under multiple ownership is prorated based on ownership
          unless the proportional entitlement to electric output is
          otherwise established by contractual arrangement.

               (p)  "Available System Capacity" means the capacity
          determined by subtracting the system load and the system
          emergency reserves from the net system capacity.

               (q)  "Spinning Reserve" means the sum of the unutilized net
          generating capability of all units of the electric utility
          company that are synchronized to the power distribution system
          and that are capable of immediately accepting additional load.
          The electric generating capability of equipment under multiple
          ownership is prorated based on ownership unless the proportional
          entitlement to electric output is otherwise established by
          contractual arrangement.

               (r)  "Available Purchase Power" means the lesser of the
          following:

                    (1)  The sum of available system capacity in all
               neighboring companies.

                    (2)  The sum of the rated capacities of the power
               interconnection devices between the principal company and
               all neighboring companies, minus the sum of the electric
               power load on these interconnections.

                    (3)  The rated capacity of the power transmission lines
               between the power interconnection devices and the electric
               generating units (the unit in the principal company that has
               the malfunctioning flue gas desulfurization system and the
               unit(s) in the neighboring company supplying replacement
               electrical power) less the electric power load on these
               transmission lines.

               (s)  "Spare Flue Gas Desulfurization System Module" means a
          separate system of sulfur dioxide emission control equipment
          capable of treating an amount of flue gas equal to the total
          amount of flue gas generated by an affected facility when
          operated at maximum capacity divided by the total number of non-
          spare flue gas desulfurization modules in the system.

               (t)  "Emergency Condition" means that period of time when:

                    (1)  The electric generation output of an affected
               facility with a malfunctioning flue gas desulfurization
               system cannot be reduced or electrical output must be
               increased because:

                         (i)  All available system capacity in the
                    principal company interconnected with the affected
                    facility is being operated, and

                         (ii) All available purchase power interconnected
                    with the affected facility is being obtained, or

                    (2)  The electric generation demand is being  shifted
               as quickly as possible from an affected facility with a
               malfunctioning flue gas desulfurization system to one or
               more electrical generating units held in reserve by the
               principal company or by a neighboring company, or

                    (3)  An affected facility with a malfunctioning flue
               gas desulfurization system becomes the only available unit
               to maintain a part or all of the principal company's system
               emergency reserves and the unit is operated in spinning
               reserve at the lowest practical electric generation load
               consistent with not causing significant physical damage to
               the unit.  If the unit is operated at a higher load to meet
               load demand, an emergency condition would not exist unless
               the conditions under (a) of this definition apply.
               
               (u)  "Electric Utility Combined Cycle Gas Turbine" means any
          combined cycle gas turbine used for electric generation that is
          constructed for the purpose of supplying more than one-third of
          its potential electric output capacity and more than 25 MW
          electrical output to any utility power distribution system for
          sale.  Any steam distribution system that is constructed for the
          purpose of providing steam to a steam electric generator that
          would produce electrical power for sale is also considered in
          determining the electrical energy output capacity of the affected
          facility.

               (v)  "Potential Electrical Output Capacity" is defined as 33
          percent of the maximum design heat input capacity of the steam
          generating unit (e.g., a steam generating unit with a 100-MW (340
          million Btu/hr) fossil fuel heat input capacity would have a 33-
          MW potential electrical output capacity).  For electric utility
          combined cycle gas turbines the potential electrical output
          capacity is determined on the basis of the fossil fuel firing
          capacity of the steam generator exclusive of the heat input and
          electrical power contribution by the gas turbine.

               (w)  "Anthracite" means coal that is classified as
          anthracite according to the American Society of Testing and
          Materials' (ASTM) Standard Specification for Classification of
          Coals by Rank D388-66.

               (x)  "Solid-Derived Fuel" means any solid, liquid, or
          gaseous fuel derived from solid fuel for the purpose of creating
          useful heat and includes, but is not limited to, solvent refined
          coal, liquified coal, and gasified coal.

               (y)  "24-Hour Period" means the period of time between 12:01
          a.m. and 12:00 midnight.

               (z)  "Resource Recovery Unit" means a facility that combusts
          more than 75 percent non-fossil fuel on a quarterly (calendar)
          heat input basis.

               (aa) "Noncontinental Area" means the State of Hawaii, the
          Virgin Islands, Guam, American Samoa, the Commonwealth of Puerto
          Rico, or the Northern Mariana Islands .

               (bb) "Boiler Operating Day" means a 24-hour period during
          which fossil fuel is combusted in a steam generating unit for the
          entire 24 hours.


               RULE 260.42a.  STANDARD FOR PARTICULATE MATTER

               (a)  On and after the date on which the performance test
          required to be conducted under Rule 260.8 is completed, no owner
          or operator subject to the provisions of this subpart shall cause
          to be discharged into the atmosphere from any affected facility
          any gases which contain particulate matter in excess of:

                    (1)  13 ng/J (0.03 lb/million Btu) heat input derived
               from the combustion of solid, liquid, or gaseous fuel;
                    
                    (2)  1 percent of the potential combustion
               concentration (99 percent reduction) when combusting solid
               fuel; and

                    (3)  30 percent of potential combustion concentration
               (70 percent reduction) when combusting liquid fuel.

               (b)  On and after the date the particulate matter
          performance test required to be conducted under Rule 260.8 is
          completed, no owner or operator subject to the provisions of this
          subpart shall cause to be discharged into the atmosphere from any
          affected facility any gases which exhibit greater than 20 percent
          opacity (6-minute average), except for one 6-minute period per
          hour of not more than 27 percent opacity.


               RULE 260.43a.  STANDARD FOR SULFUR DIOXIDE

               (a)  On and after the date on which the initial performance
          test required to be conducted under Rule 260.8 is completed, no
          owner or operator subject to the provisions of this subpart shall
          cause to be discharged into the atmosphere from any affected
          facility which combusts solid fuel or solid-derived fuel, except
          as provided under sections (c), (d), (f) or (h) of this rule, any
          gases which contain sulfur dioxide in excess of:

                    (1)  520 ng/J (1.20 lb/million Btu) heat input and 10
               percent of the potential combustion concentration (90
               percent reduction), or

                    (2)  30 percent of the potential combustion
               concentration (70 percent reduction), when emissions are
               less than 260 ng/J (0.60 lb/million Btu) heat input.

               (b)  On and after the date on which the initial performance
          test required to be conducted under Rule 260.8 is completed, no
          owner or operator subject to the provisions of this subpart shall
          cause to be discharged into the atmosphere from any affected
          facility which combusts liquid or gaseous fuels (except for
          liquid or gaseous fuels derived from solid fuels and as provided
          under sections (e) or (h) of this rule), any gases which contain
          sulfur dioxide in excess of:

                    (1)  340 ng/J (0.80 lb/million Btu) heat input and 10
               percent of the potential combustion concentration (90
               percent reduction), or

                    (2)  100 percent of the potential combustion
               concentration (zero percent reduction) when emissions are
               less than 86 ng/J (0.20 lb/million Btu) heat input.

               (c)  On and after the date on which the initial performance
          test required to be conducted under Rule 260.8 is complete, no
          owner or operator subject to the provisions of this subpart shall
          cause to be discharged into the atmosphere from any affected
          facility which combusts solid solvent refined coal (SRC-I) any
          gases which contain sulfur dioxide in excess of 520 ng/J (1.20
          lb/million Btu) heat input and 15 percent of the potential
          combustion concentration (85 percent reduction) except as
          provided under Section (f) of this rule; compliance with the
          emissions limitation is determined on a 30-day rolling average
          basis and compliance with the percent reduction requirement is
          determined on a 24-hour basis.

               (d)  Sulfur dioxide emissions are limited to 520 ng/J (1.20
          lb/million Btu) heat input from any affected facility which:

                    (1)  Combusts 100 percent anthracite,

                    (2)  Is classified as a resource recovery facility, or

                    (3)  Is located in a noncontinental area and combusts
               solid fuel or solid-derived fuel.

               (e)  Sulfur dioxide emissions are limited to 340 ng/J (0.80
          lb/million Btu) heat input from any affected facility which is
          located in a noncontinental area and combusts liquid or gaseous
          fuels (excluding solid-derived fuels).

               (f)  The emission reduction requirements under this rule do
          not apply to any affected facility that is operated under an SO2
          commercial demonstration permit issued by the Administrator in
          accordance with the provisions of Rule 260.45a.

               (g)  Compliance with the emission limitation and percent
          reduction requirements under this rule are both  determined on a
          30-day rolling average basis except as provided under Section (c)
          of this rule.

               (h)  When different fuels are combusted simultaneously, the
          applicable standard is determined by proration using the
          following formula:

                    (1)  If emissions of sulfur dioxide to the atmosphere
               are greater than 260 ng/J (0.60 lb/million Btu) heat input

                                   ESO2  =  [340x + 520y]/100 and

                                   PSO2  =  10 percent

                    (2)  If emissions of sulfur dioxide to the atmosphere
               are equal to or less than 260 ng/J (0.60 lb/million Btu)
               heat input:

                                   ESO2  =  [340x + 520y]/100 and

                                   PSO2  =  [90x + 70y]/100

               where,

                    ESO2  is the prorated sulfur dioxide emission limit
                          (ng/J heat input),

                    PSO2  is the percentage of potential sulfur dioxide
                          emission allowed (percent reduction 
                          required = 100 - PSO2),

                    x    is the percentage of total heat input derived from
                         the combustion of liquid or gaseous fuels (excluding 
                         solid-derived fuels),

                    y    is the percentage of total heat input derived from 
                         the combustion of solid fuel (including solid-
                         derived fuels).


               RULE 260.44a.  STANDARD FOR NITROGEN OXIDES

               (a)  On and after the date on which the initial performance
          test required to be conducted under Rule 260.8 is completed, no
          owner or operator subject to the provisions of this subpart shall
          cause to be discharged into the atmosphere from any affected
          facility, except as provided under Section (b) of this rule, any
          gases which contain nitrogen oxides in excess of the following
          emission limits, based on a 30-day rolling average.

                    (1)  NOx Emission Limits -            Emission Limit
                                                       ng/J (lb/million Btu)
                    Fuel Type                                Heat Input

          Gaseous fuels:
               Coal-derived fuels  . . . . . . . . . .    210         (0.50)
               All other fuels    . . . . . . . . . . .    86         (0.20)

          Liquid fuels:
               Coal-derived fuels  . . . . . . . . . . .  210         (0.50)
               Shale oil   . . . . . . . . . . . . . . .  210         (0.50)
               All other fuels . . . . . . . . . . . . .  130         (0.30)

          Solid fuels:
               Coal-derived fuels  . . . . . . . . . . .  210         (0.50)
               Any fuel containing more than 
               25% by weight, coal refuse -        Exempt from NOx standards 
                                                   and NO2 monitoring 
                                                   requirements

          Any fuel containing more than 25%, by
               weight, lignite if the lignite is 
               mined in North Dakota, South Dakota, 
               or Montana, and is combusted in a 
               slag tap furnace . . . . . . . . . . . .   340         (0.80)

          Lignite not subject to the 340 ng/J heat
               input emission limit  . . . . . . . . . .  260         (0.60)
          Subbituminous coal  . . . . . . . . . . . . .   210         (0.50)
          Bituminous coal   . . . . . . . . . . . . . .   260         (0.60)
          Anthracite coal . . . . . . . . . . . . . . .   260         (0.60)
          All other fuels  . . . . . . . . . . . . . . .  260         (0.60)


               (2)  NOx Reduction Requirements -
                                                          Percent reduction of
                                                          potential combustion
                    Fuel Type                                 concentration

          Gaseous fuels  . . . . . . . . . . . . . . . .           25%
          Liquid fuels   . . . . . . . . . . . . . . . .           30%
          Solid fuels   . . . . . . . . . . . . . . . . .          65%

               (b)  The emission limitations under Section (a) of this rule
          do not apply to any affected facility which is combusting coal-
          derived liquid fuel and is operating under a commercial
          demonstration permit issued by the Administrator in accordance
          with the provisions of Rule 260.45a.

               (c)  When two or more fuels are combusted simultaneously,
          the applicable standard is determined by proration using the
          following formula:

                         ENO2  =  [86w + 130x + 210y + 260z]/100

               where,

                         ENO2 is the applicable standard for nitrogen
                              oxides when multiple fuels are combusted
                              simultaneously (ng/J heat input);

                         w    is the percentage of total heat input derived
                              from the combustion of fuels subject to the
                              86 ng/J heat input standards;

                         x    is the percentage of total heat input derived
                              from the combustion of fuels subject to the
                              130 ng/J heat input standard;

                         y    is the percentage of total heat input derived
                              from the combustion of fuels subject to the
                              210 ng/J heat input standard; and

                         z    is the percentage of total heat input derived
                              from the combustion of fuels subject to the
                              260 ng/J heat input standard.


               RULE 260.45a.  COMMERCIAL DEMONSTRATION PERMIT

               (a)  An owner or operator of an affected facility proposing
          to demonstrate an emerging technology may apply to the
          Administrator for a commercial demonstration permit.  The
          Administrator will issue a commercial demonstration  permit in
          accordance with Section (e) of this rule.  Commercial
          demonstration permits may be issued only by the Administrator,
          and this authority will not be delegated.

               (b)  An owner or operator of an affected facility that
          combusts solid solvent refined coal (SRC-I) and who is issued a
          commercial demonstration permit by the Administrator is not
          subject to the SO2 emission reduction requirements under Rule
          260.43a(c) but must, as a minimum, reduce SO2 emissions to 20
          percent of the potential combustion concentration (80 percent
          reduction) for each 24-hour period of steam generator operation
          and to less than 520 ng/J (1.20 lb/million Btu) heat input on a
          30-day rolling average basis.

               (c)  An owner or operator of a fluidized bed combustion
          electric utility steam generator (atmospheric or pressurized) who
          is issued a commercial demonstration permit by the Administrator
          is not subject to the SO2 emission reduction requirements under
          Rule 260.43a(a) but must, as a minimum, reduce SO2 emissions to
          15 percent of the potential combustion concentration (85 percent
          reduction) on a 30-day rolling average basis and to less than 520
          ng/J (1.20 lb/million Btu) heat input on a 30-day rolling average
          basis.

               (d)  An owner or operator of an affected facility that
          combusts coal-derived liquid fuel and who is issued a commercial
          demonstration permit by the Administrator is not subject to the
          applicable NOx emission limitation and percent reduction under
          Rule 260.44a(a) but must, as a minimum, reduce emissions to less
          than 300 ng/J (0.70 lb/million Btu) heat input on a 30-day
          rolling average basis.

               (e)  Commercial demonstration permits may not exceed the
          following equivalent MW electrical generation capacity for any
          one technology category, and the total equivalent MW electrical
          generation capacity for all commercial demonstration plants may
          not exceed 15,000 MW.

                                                            Equivalent
                                                            electrical
                                                            capacity (MW
                                                            electrical
               Technology          Pollutant                output)

          Solid solvent refined 
             coal (SRC-I) . . . .     SO2                   6,000-10,000
          Fluidized bed combustion
             (atmospheric)  . . .     SO2                   400-3,000
          Fluidized bed combustion
             (pressurized) . . . .    SO2                   400-1,200
          Coal liquification  . . .   NO2                   750-10,000

                   Total allowable for all technologies         15,000



               RULE 260.46a.  COMPLIANCE PROVISIONS

               (a)  Compliance with the particulate matter emission
          limitation under Rule 260.42a(a)(1) constitutes compliance with
          the percent reduction requirements for particulate matter under
          Rule 260.42a(a)(2) and (3).

               (b)  Compliance with the nitrogen oxides emission limitation
          under Rule 260.44a(a) constitutes compliance with the percent
          reduction requirements under Rule 260.44a(a)(2).

               (c)  The particulate matter emission standards under Rule
          260.42a and the nitrogen oxides emission standards under Rule
          260.44a apply at all times except during periods of startup,
          shutdown, or malfunction.  The sulfur dioxide emission standards
          under Rule 260.43a apply at all times except during periods of
          startup, shutdown, or when both emergency conditions exist and
          the procedures under Section (d) of this rule are implemented.

               (d)  During emergency conditions in the principal company,
          an affected facility with a malfunctioning flue gas
          desulfurization system may be operated if sulfur dioxide
          emissions are minimized by:

                    (1)  Operating all operable flue gas desulfurization
               system modules, and bringing back into operation any
               malfunctioned module as soon as repairs are completed,

                    (2)  Bypassing flue gases around only those flue gas
               desulfurization system modules that have been taken out of
               operation because they were incapable of any sulfur dioxide
               emission reduction or which would have suffered significant
               physical damage if they had remained in operation, and

                    (3)  Designing, constructing, and operating a spare
               flue gas desulfurization system module for an affected
               facility larger than 315 million kcal/hr (1,250 million
               Btu/hr) heat input (approximately 125 MW electrical output
               capacity).  The Control Officer may at his discretion
               require the owner or operator within 60 days of notification
               to demonstrate spare module capability.  To demonstrate this
               capability, the owner or operator must demonstrate
               compliance with the appropriate requirements under sections
               (a), (b), (d), (e), and (i) under Rule 260.43a for any
               period of operation lasting from 24 hours to 30 days when:

                         (i)  Any one flue gas desulfurization module is
                    not operated,

                         (ii) The affected facility is operating at the
                    maximum heat input rate,

                         (iii)The fuel fired during the 24-hour to 30-day
                    period is representative of the type and average sulfur
                    content of fuel used over a typical 30-day period, and

                         (iv) The owner or operator has given the Control
                    Officer at least 30 days notice of the date and period
                    of time over which the demonstration will be performed.

               (e)  After the initial performance test required under Rule
          260.8, compliance with the sulfur dioxide emission limitations
          and percentage reduction requirements under Rule 260.43a and the
          nitrogen oxides emission limitations under Rule 260.44a is based
          on the average emission rate for 30 successive boiler operating
          days.  A separate performance test is completed at the end of
          each boiler operating day after the initial performance test, and
          a new 30-day average emission rate for both sulfur dioxide and
          nitrogen oxides and a new percent reduction for sulfur dioxide
          are calculated to show compliance with the standards.

               (f)  For the initial performance test required under Rule
          260.8, compliance with the sulfur dioxide emission limitatio ns
          and percent reduction requirements under Rule 260.43a and the
          nitrogen oxides emission limitation under Rule 260.44a is based
          on the average emission rates for sulfur dioxide, nitrogen
          oxides, and percent reduction for sulfur dioxide for the first 30
          successive boiler operating days.  The initial performance test
          is the only test in which at least  30 days prior notice is
          required unless otherwise specified by the Control Officer.  The
          initial performance test is to be scheduled so that the first
          boiler operating day of the 30 successive boiler operating days
          is completed within 60 days after achieving the maximum
          production rate at which the affected facility will be operated,
          but not later than 180 days after initial startup of the
          facility.

               (g)  Compliance is determined by calculating the arithmetic
          average of all hourly emission rates for SO2 and NOx for the 30
          successive boiler operating days, except for data obtained during
          startup, shutdown, malfunction (NOx only), or emergency
          conditions (SO2 only).  Compliance with the percentage reduction
          requirement for SO2 is determined based on the average inlet and
          average outlet SO2 emission rates for the 30 successive boiler
          operating days.

               (h)  If an owner or operator has not obtained the minimum
          quantity of emission data as required under Rule 260.47a of this
          subpart, compliance of the affected facility with the emission
          requirements under Rule 260.43a and Rule 260.44a of this subpart
          for the day on which the 30-day period ends may be determined by
          the Control Officer by following the applicable procedures in
          Sections 6.0 and 7.0 of Reference Method 19 of Part 60, Chapter
          I, Title 40, Code of Federal Regulations, Appendix A.



               RULE 260.47a.  EMISSIONS MONITORING

               Monitoring requirements shall be those specified in Part 60,
          Chapter I, Title 40, Code of Federal Regulations, Section 60.47a.



               RULE 260.48a.  COMPLIANCE DETERMINATION PROCEDURES
                              AND METHODS

               Procedures and methods for determining compliance shall be
          those specified in Part 60, Chapter I, Title 40, Code of Federal
          Regulations, Section 60.48a.


               RULE 260.49a.  REPORTING REQUIREMENTS

               (a)  For sulfur dioxide, nitrogen oxides, and particulate
          matter emissions, the performance test data from the initial
          performance test and from the performance evaluation of the
          continuous monitors (including the transmissometer) are submitted
          to the Control Officer.

               (b)  For sulfur dioxide and nitrogen oxides the following
          information is reported to the Control Officer for each 24-hour
          period.

                    (1)  Calendar date.

                    (2)  The average sulfur dioxide and nitrogen oxide
               emission rates (ng/J or lb/million Btu) for each 30
               successive boiler operating days, ending with the last 30-
               day period in the quarter; reasons for non-compliance with
               the emission standards; and, description of corrective
               actions taken.

                    (3)  Percent reduction of the potential combustion
               concentration of sulfur dioxide for each 30 successive
               boiler operating days, ending with the last 30-day period in
               the quarter; reasons for non-compliance with the standard;
               and, description of corrective actions taken.

                    (4)  Identification of the boiler operating days for
               which pollutant or dilutent data have not been obtained by
               an approved method for at least 18 hours of operation of the
               facility; justification for not obtaining sufficient data;
               and description of corrective actions taken.

                    (5)  Identification of the times when emissions data
               have been excluded from the calculation of average emission
               rates because of startup, shutdown, malfunction (NOx only),
               emergency conditions (SO2 only), or other reasons, and
               justification for excluding data for reasons other than
               startup, shutdown, malfunction, or emergency conditions.

                    (6)  Identification of "F" factor used for
               calculations, method of determination, and type of fuel
               combusted.

                    (7)  Identification of times when hourly averages have
               been obtained based on manual sampling methods.

                    (8)  Identification of the times when the pollutant
               concentration exceeded full span of the continuous
               monitoring system.

                    (9)  Description of any modifications to the continuous
               monitoring system which could affect the ability of the
               continuous monitoring system to comply with Performance
               Specifications 2 or 3.

               (c)  If the minimum quantity of emission data as required by
          Rule 260.47a is not obtained for any 30 successive boiler
          operating days, the following information obtained under the
          requirements of Rule 260.46a(h) is reported to the Control
          Officer for that 30-day period;

                    (1)  The number of hourly averages available for outlet
               emissions rates (no) and inlet emission rates (ni) as
               applicable.

                    (2)  The standard deviation of hourly averages for
               outlet emission rates (so) and inlet emission rates (si) as
               applicable.

                    (3)  The lower confidence limit for the mean outlet
               emission rate (Eo*) and the upper confidence limit for the
               mean inlet emission rate (Ei*) as applicable.

                    (4)  The applicable potential combustion concentration.

                    (5)  The ratio of the upper confidence limit for the
               mean outlet emission rate (Eo*) and the allowable emission
               rate (Estd) as applicable.

               (d)  If any standards under Rule 260.43a are exceeded during
          emergency conditions because of control system malfunction, the
          owner or operator of the affected facility shall submit a signed
          statement:

                    (1)  Indicating if emergency conditions existed and
               requirements under Rule 260.46a(d) were met during each
               period, and

                    (2)  Listing the following information:

                         (i)  Time periods the emergency condition existed;

                         (ii) Electrical output and demand on the owner or
                    operator's electric utility system and the affected
                    facility;

                         (iii)Amount of power purchased from interconnected
                    neighboring utility companies during the emergency
                    period;

                         (iv) Percent reduction in emissions achieved;

                         (v)  Atmospheric emission rate (ng/J) of the
                    pollutant discharged; and

                         (vi) Actions taken to correct control system
                    malfunction.

               (e)  If fuel pretreatment credit toward the sulfur dioxide
          emission standard under Rule 260.43a is claimed, the owner or
          operator of the affected facility shall submit a signed
          statement:

                    (1)  Indicating what percentage cleaning credit was
               taken for the calendar quarter, and whether the credit was
               determined in accordance with the provision of Section
               60.48a and Method 19 of Appendix A of Part 60, Chapter I,
               Title 40, Code of Federal Regulations.

                    (2)  Listing the quantity, heat content, and date each
               pretreated fuel shipment was received during the previous
               quarter; the name and location of the fuel pretreatment
               facility; and the total quantity and total heat content of
               all fuels received at the affected facility during the
               previous quarter.

               (f)  For any periods for which opacity, sulfur dioxide or
          nitrogen oxides emissions data are not available, the owner or
          operator of the affected facility shall submit a signed statement
          indicating if any changes were made in operation of the emission
          control system during the period of data unavailability.
          Operations of the control system and affected facility during
          periods of data unavailability are to be compared with operation
          of the control system and affected facility before and following
          the period of data unavailability.

               (g)  The owner or operator of the affected facility shall
          submit a signed statement indicating whether:

                    (1)  The required continuous monitoring system
               calibration, span, and drift checks or other periodic audits
               have or have not been performed as specified.

                    (2)  The data used to show compliance was or was not
               obtained in accordance with approved methods and procedures
               of this regulation and is representative of plant per-
               formance.

                    (3)  The minimum data requirements have or have not
               been met; or, the minimum data requirements have not been
               met for errors that were unavoidable.

                    (4)  Compliance with the standards has or has not been
               achieved during the reporting period.

               (h)  For the purposes of the reports required under Rule
          260.7, periods of excess emissions are defined as all 6-minute
          periods during which the average opacity exceeds the applicable
          opacity standards under Rule 260.42a(b).  Opacity levels in
          excess of the applicable opacity standard and the date of such
          excesses are to be submitted to the Control Officer each calendar
          quarter.

               (i)  The owner or operator of an affected facility, shall
          submit the written reports required under this rule and Subpart A
          to the Control Officer for every calendar quarter.  All quarterly
          reports shall be postmarked by the 30th day following the end of
          each calendar quarter.