State of California
AIR RESOURCES BOARD
State of California
Asilomar Conference Center
Firelight Forum
(Corner of Asilomar Blvd. and Sinex Ave.)
800 Asilomar Boulevard
Pacific Grove, CA 93950
June 24, 1981
10:00 a.m.
AGENDA
Page
81-11-1 CONTINUATION OF Public Meeting to Further Consider 001
a Suggested Control Measure for the Control of
Emissions of Photochemically Reactive Organic
Compounds From Oil and Gas Production Operations
and Gas Processing Plants.
81-11-2 Public Meeting to Consider Minimum Guidelines 342
for the Control of Emissions From Coal-Fired Power
Plants.
81-11-3 Other Business
a. Closed Sessions
1. Personnel (as authorized by State Agency Open
Meeting Act).
2. Litigation (Pursuant to the attorney-client
privilege).
b. Research Proposals 603
c. Delegations to Executive Officer
1983 and Subsequent Model-Year Assemblyline
Test Procedures.
SMOKING NOT PERMITTED AT MEETINGS OF THE CALIFORNIA AIR RESOURCES
BOARD.
ITEM NO.: 81-11-1
SUMMARY AND STATEMENT OF REASONS FOR PROPOSED APPROVAL OF
SUGGESTED CONTROL MEASURE.
BACKGROUND
Federal and state laws have established health-based ambient air
quality standards for ozone and oxidant, respectively. In many
areas of California, these federal and state standards are not
being met and are not expected to be met by 1982.
Federal law requires states to develop and implement "as
expeditiously as practicable" all reasonably available control
measures to reduce photochemical oxidants in nonattainment areas.
See, e.g., 1977 Clean Air Act, Section 172(b). EPA recommends
the adoption of "all reasonably available control technologies"
in nonattainment areas.
The Air Resources Board (ARB) is given broad authority under the
Health and Safety Code to coordinate, encourage, and review the
efforts of local districts in their efforts to attain and
maintain state and national ambient air quality standards. See,
e.g., Health and Safety Code Sections 39003, 39500, 39600, 39602,
39605, and 41500.
The ARB staff has estimated that fugitive hydrocarbon emissions
from valves, pipe connections, diaphragms, pumps, compressor,
hatches, sight glasses, meters, and seals in oil and gas
production fields and in gas processing plants total 60 tons of
hydrocarbon compounds per day in California, according to
conservative methods of estimation. The air basins in which the
emissions are concentrated -- South Coast, San Joaquin Valley,
and South Central Coast -- are federal nonattainment areas for
ozone and also experience numerous violations of the state
ambient air quality standard for oxidant. None of these air
basins is expected to achieve ozone attainment in the South Coast
Air Basin by 1987, the deadline set by the Clean Air Act, will be
very difficult to achieve. Accordingly, reductions of emissions
of hydrocarbon compounds are needed in these air basins.
The State Implementation Plan contains commitments to adopt
controls to achieve reductions of fugitive hydrocarbon emissions
in oil and gas production operations.
The Ventura County Air Pollution Control District staff, working
with the ARB staff and others, held a number of workshops with
industry regarding control of fugitive hydrocarbon emissions.
The staffs now propose that the Board approve the suggested
control measure in this report, which the staffs have found to be
technically feasible, economically reasonable, and without
significant adverse environmental impacts.
If approved by the Board, the suggested control measure will be
forwarded to appropriate air pollution control districts for
consideration as an addition to their rules when necessary for
attainment and maintenance of the state and national ambient air
quality standards for oxidant and ozone, respectively.
The suggested control measure would become an enforceable
regulation only after adoption into the regulations of a
districts. Approval by the Board of the suggested control
measure does not create an enforceable regulation.
ITEM NO.: 81-11-2
Public Meeting to Discuss Proposed Guidelines for the Control of
Emissions from Coal-Fired Power Plants.
SUMMARY
Two California Utilities, Southern California Edison and Pacific
Gas and Electric, have proposed coal-fired power plants for
construction in California. Before such facilities can be built,
they must meet air quality requirements. In California, these
requirements include those established by the Environmental
Protection Agency (EPA), the Air Resources Board (ARB), and the
local air pollution control districts (APCDs).
Current EPA standards for coal-fired power plants are specified
in the New Source Performance Standards (NSPS) applicable to such
plants. These standards represent minimum control requirements
and are applicable nationwide. The staff has reviewed these
standards as well as the actual permit conditions set by EPA and
believes they do not usually represent the best available control
technology.
Local districts' new source review rules require the application
of the best available air pollution control technology on a new
major sources. In reviewing the applications for coal-fired
power plants, the district in which the facility is being
proposed must, therefore, make a determination of what is the
best available technology. In order to assist these agencies in
the review process and to ensure consistent requirements, the
staff has developed proposed minimum guidelines for controlling
emissions of sulfur dioxide, oxides of nitrogen, and particulate
matter from new coal-fired power plants. These guidelines are
being proposed as minimum guidelines; more stringent requirements
may be considered by the local APCDs on a case-by-case basis.
In developing these guidelines, the staff has reviewed the work
of EPA and other research organizations, observed similar
facilities in Japan, and conducted a workshop with the utilities,
manufacturers and other state and local agencies.
The proposed minimum guidelines are: a 95 percent reduction of
sulfur dioxide (SO2) when the inlet concentration to the SO2
control device exceeds 300 ppm, and a proportionately lower
percent reduction resulting in an outlet concentration not to
exceed 15 ppm when the inlet concentration to the SO2 control
device is equal to or less than 300 ppm; 0.005 grains per actual
cubic foot (gr/ACF) for particulate matter; and 0.45 pound per
million (lb/mm) Btu of heat input for oxides of nitrogen (NOx)
below 50 percent of rated capacity, and 0.09 lb/mm BTU of heat
input at 50 percent, and greater, of rated capacity. Guidelines
for compliance determination and emission monitoring are also
specified.
Control technologies needed to achieve the proposed guideline
levels are readily available today. These include combustion
modifications and ammonia-based flue gas treatment for NOx, flue
gas desulfurization for SO2 and a baghouse for particulate
matter.
The capital cost of installing the control equipment necessary to
achieve the proposed emission levels ranges from $42 to $66/kw
for NOx controls (in addition to combustion modifications),
approximately $34/kw for particulate matter controls, and $96 to
$179/kw for SO2 controls. Based on a total coal-fired power
plant capital cost of $1175 to $1357/kw, the control equipment
accounts for 15 to 21 percent of the total capital cost.
The levelized cost of installing the control equipment necessary
to achieve the proposed emission levels ranges from 4.4 to 6.5
mills/kwh for NOx controls (in addition to combustion
modifications), 1.0 to 2.0 mills/kwh for particulate matter
controls, and 6.7 to 12.4 mills/kwh for SO2 controls. The sum of
the control equipment levelized costs should represent somewhat
less than 15 to 21 percent of the total plant levelized cost.
The staff has not identified any significant adverse
environmental or other impacts that would result from
installation of control equipment to meet the emission limits
recommended by these guidelines.