The Council of Industrial Boiler Owners (“CIBO”) is a national trade association of industrial boiler owners, architect-engineers, related equipment manufacturers, and universities representing 20 major industrial sectors. CIBO was formed in 1978 to promote the exchange of information between industry and government relating to energy and environmental policies, laws, and regulations affecting industrial boilers. CIBO membership represents industries as diverse as chemical, paper, cogeneration, steel, automotive, refining, brewing, combustion engineering, and food products. CIBO members also include operators of boiler facilities at over a dozen major universities. Operators of industrial boilers are heavy users of utility generated power and through their electricity prices will pay a substantial portion of the utility industry’s cost of meeting multi-emission legislation requirements. Any additional impact on non-utility industries must be carefully considered to minimize adverse economic impact.

There is little doubt that cap-and-trade proposals enjoy efficiencies and cost-effectiveness that old-style command-and-control regulations cannot hope to achieve. Indeed, the experience of the last decade with the Acid Rain SO2 trading program demonstrates that initial environmental goals can be exceeded at lower costs than anticipated. However, current Congressional and Administration proposals are far broader in scope and much more restrictive than existing cap-and-trade programs.

Therefore, as the legislative process moves forward, it is important that implementation, allocation, technical feasibility, and other details be very carefully considered. Industrial boiler owners will remain active participants in this process, evaluating the impacts of proposals on the cost of industrial energy generated and purchased. Legislative proposals that increase the demand for a specific fuel such as natural gas are of critical importance to industry due to reduced availability and the resultant increase in price. Any increased gas demand must be mitigated by reasonable emissions control requirements and policies that provide commensurate gas supplies so that industry can retain global competitiveness.

Utility boilers generate steam at a relatively constant rate for the sole use of powering turbines that produce electricity. Comparatively, industrial boilers have markedly different purposes throughout a variety of industries. The rapid, widely fluctuating demand for steam in most industrial processes means that industrial boilers do not operate steadily at maximum capacity. In general, industrial boilers will have a much lower annual operating load or capacity factor than typical utility boilers. Further, many industrial boilers are designed to accommodate a wide variety of fuels, sometimes in mixtures, including by-products and process residuals whose use as fuel provides additional environmental benefits. Designing highly effective pollution control systems for these multi-fuel boilers is often difficult. As a result of these important differences between utility and industrial boilers, any new multi-emission rule could have a much greater impact on the final output steam cost and emission control cost for industrial boilers.

Multi-Emission Legislation

A. Multi-Emission Legislation Should Clarify and Consolidate Air Emission Requirements 

CIBO believes that implementation of reasonable multi-emission control requirements on electric utility sources in a comprehensive and orderly fashion could provide a higher level of regulatory certainty than the existing multiple levels of regulatory requirements coupled with changing interpretation and enforcement of those programs. This certainty could allow more efficient and lower cost compliance on a long-term basis. Lower utility compliance costs would benefit all consumers. However, any multi-emission program must be coordinated and coupled with existing programs and any overlap eliminated in order to optimize program effectiveness.

Any participating facility should not be regulated by overlapping requirements for any given pollutant under New Source Review (“NSR”), New Source Performance Standards (“NSPS”), Best Available Retrofit Technology (“BART”), National Emission Standards for Hazardous Air Pollutants (“NESHAP”), and other specified provisions of the Clean Air Act. Any comprehensive cap-and-trade program must be accompanied by substantial and appropriate reform of inconsistent regulatory approaches.

B. Multi-Emission Reduction Legislation Should Only Address NOx, SO2, and Mercury.

While supportive of a properly structured cost-effective three-emission approach, it is important to allow for a delayed implementation of mercury (Hg) specific controls. CIBO believes that limiting reductions only to criteria pollutant emissions (NOx and SO2) in a first phase would allow for an evaluation of the level and impact of collateral mercury emissions reductions. After assessing the reductions that result from implementation of the first phase of controls, the need for further mercury emission reductions can be determined, and an appropriate, properly targeted control program can be developed. While the efficacy of a NOx and SO2 trading program has already been demonstrated, the situation for Hg could be very different, at least until cost-effective mercury removal technologies have been adequately demonstrated in the field and the commercial development of cost-effective continuous measuring devices has occurred.

Mercury caps may be particularly problematic. It is an open question whether or not controls at levels currently proposed for mercury are technologically feasible. In any event, mercury controls may force unanticipated levels of fuel switching away from coal. The result of such action would be to cause economic dislocation for users of natural gas, including industrial applications, feedstocks and even home heating. Therefore, CIBO believes that levels of mercury control attributable to NOx and SO2 controls should first be evaluated before additional mercury controls are adopted.

CO2 should be separately addressed in a comprehensive program that could provide a balanced approach that equitably addresses the issue in the most effective manner with minimal damage to the economy.

C. Any Multi-Emission Initiative Should Provide a Clear Objective, Provide for Fuel Flexibility and Have Reasonable, Achievable and Cost Effective Caps.

A multi-emission control program should clearly articulate the improvements that are attributable to this legislation over and above those already in place. However, emissions limits should not be so stringent as to directly or indirectly lead to levels of fuel switching or equipment replacement that cause the demand for natural gas to exceed the deliverable supply. It should be recognized that the Acid Rain Program success in achieving emissions reductions at lower cost per ton than predicted resulted from the ability to over-control on some units in order to attain a reasonable overall reduction level. However, while EPA is justifiably proud of the results of the Acid Rain Program, new multi-emission proposals differ in scope and economic assumptions in profound ways from existing cap-and-trade programs. As a result, policymakers must be cautious in relying too closely on the Acid Rain Program as precedent for proposed actions.

If the percent reduction is set so high as to require extreme reductions on every unit, then there will be very few allowances available for trading. A dearth of credits will severely compromise the cost effectiveness of the trading program and limit fuel flexibility. This could result in the shutdown of some coal capacity and require installation of gas-fired capacity in order to meet electrical demand.

To the extent multi-emission limitations result in increased gas demand, legislation should provide for access to and delivery of commensurate supplies of gas. It would be catastrophic if we relied on only one or two energy sources and a disruption occurred. Long-term diversification of energy sources is critical to ensure that national security is maintained. When periodic shortages occur, the availability of alternative energy sources is critical to maintain global competitiveness at minimal cost.

D. Logistics of a Multi-Emission Initiative

The level of reductions of each emission must be considered in combination when determining potential environmental impact and approaches to compliance with associated costs rather than independently, since individual units will need to address all requirements at once.

Emission reduction levels and timing must be set in a manner that provides full consideration of all relevant factors, such as:

• Technological capabilities based on real world design and operational variability, including the range of fuel characteristics.
• Impacts of multi-emission reductions on other air, water, and solid waste emissions and energy use.
• Economics that consider site specific variables and complexities, and the timing of emissions reductions. Timing must consider all relevant issues, such as equipment availability, skilled labor availability, time required for study and project implementation.

E. Applicability of Multi-Emission Initiative

To determine applicability of a multi-emission initiative, CIBO believes the existing Acid Rain Title IV definitions of affected facilities (specifically, Clean Air Act § 402(17), (24) and (25), 42 U.S.C.S. § 7651a (2001); § 405(g)(6)(A), 42 U.S.C.S. § 7651d (2001); and § 410(d), 42 U.S.C.S. § 7651i (2001)) should continue to be used to provide consistency with existing programs. See attached for definitions.

Also, new and existing affected units that have undergone BACT/LAER or MACT evaluations since 1990 should be considered as meeting the reduction requirements under any multi-emission legislation for a specified period of time.

F. Provisions for Voluntary Opt-In Should be Provided

Similar to the Acid Rain Program, industrial units should be given the opportunity for voluntary opt-in to the program. Opt-ins could be of use to certain sources providing that requirements are established on an equitable cost-effective basis, recognizing the inherent differences between industrial and utility units in areas of operational flexibility, high levels of required reliability, fuel flexibility and diversity of fuels, and higher control costs due to economies of scale. With 19 different industrial sectors utilizing industrial boilers, and with economic assumptions being different for each, optional participation is the only form of participation that makes sense for industrial energy.

NSR Clarification is Necessary to Improve Energy Efficiency and Facility Safety.

There is a basic need for administrative reform of NSR interpretation and enforcement practices as applied to all relevant emissions sources. This is required for sources to complete routine maintenance, repair, and replacement as needed to maintain equipment in a safe and efficient condition. Under current EPA interpretation, NSR can be triggered by physical changes to the source which do not increase emissions. This is contrary to NSR’s intent and language. Administrative reform is needed to allow improvements in energy efficiency, and recovery of previously lost (but permitted) capacity without triggering NSR provisions.

While some have argued that NSR reform should be held captive to completion of multi-emission legislation, CIBO believes any such delay in administrative reforms is wholly inappropriate. The legislative process may take years to complete. By contrast, the current NSR interpretation is sacrificing energy efficiency and maintenance activities in the immediate timeframe. Without timely clarification, the current NSR program will continue to undermine environmental, safety, and energy security objectives.

CLEAN AIR ACT

ACID RAIN DEFINITIONS

The following are excerpted from 42 U.S.C.S. § 7651, et seq (2001). Specifically, this document cites §§ 7651a, 7651d, and 7651i. Please note that a mistake exists in the statutory language and “Section 410(e)”, referred to in § 7651a ¶ (24) is a reference to section 410(d), which appears as 42 USCS § 7651i(d).

42 U.S.C.S. § 7651a (2001)

SEC. 402. DEFINITIONS

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(17)(A) The term “utility unit” means-

(i)  a unit that serves a generator in any State that produces electricity for sale, or

(ii) a unit that, during  1985, served a generator in any State that produced electricity for

sale.

(B) Notwithstanding subparagraph (A), a unit described in subparagraph (A) that-

(i) was in commercial operation during 1985, but

(ii) did not, during  1985, serve a generator  in any State that produced electricity for sale

shall not be a utility unit for purposes of this title.

(C) A unit that cogenerates steam and electricity is not a “utility unit” for purposes of this

title unless the unit is constructed  for  the  purpose of  supplying,  or  commences

construction after  the date of enactment of  this title and supplies,  more than  one-third

of  its potential  electric output capacity and more than 25 megawatts electrical output

to any utility power distribution system for sale.

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The term “industrial source” means a unit that does not serve a generator that produces electricity,  a “non-utility unit”  as  defined in  this  section, or  a  process source as defined in section 410(e). [As addressed above, this is a mistake in statutory language, and should read “section 410(d).”]

(25)  The term “nonutility unit” means a unit other than a utility unit.

42 U.S.C.S. § 7651d (2001)

SEC. 405. PHASE II SULFUR DIOXIDE REQUIREMENTS

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(g)(6)(A) Unless the Administrator has approved a designation of such facility under section  410 [42 U.S.C.S. § 7651i], the  provisions of this  title shall not apply to a “qualifying small power production facility” or  “qualifying cogeneration  facility”  (within the  meaning  of section 3(17)(C) or  3(18)(B) of the Federal  Power Act) or to  a “new independent power production facility” as defined in section 416 [42 U.S.C.S. § 7651o]  except that clause (iii)  of such definition in section 416 [42 U.S.C.S. § 7651o(a)(2)(C)]  shall not apply for purposes of this paragraph if, as of the date of enactment,

(i) an applicable power sales agreement has been executed;

(ii) the  facility is  the subject  of a  State regulatory authority order requiring an  electric utility to enter into a  power sales  agreement with,  purchase capacity  from, or (for purposes  of establishing  terms and conditions  of the electric utility’s purchase of power) enter into arbitration concerning, the facility;

(iii) an electric utility has issued a letter of intent or similar  instrument committing  to purchase  power from  the facility  at a previously offered or lower price and a power sales agreement  is executed  within a reasonable  period of time; or

(iv) the facility has been selected as a winning bidder in a utility competitive bid solicitation.

42 U.S.C.S. § 7651i (2001)

SEC. 410 ELECTION FOR ADDITIONAL SOURCES

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(d) Process Sources. Not later than 18 months after enactment of the Clean Air Act Amendments of 1990, the Administrator shall establish a program under which the owner or operator of a process source that emits sulfur dioxide may elect to designate that source as an affected unit for the purpose of receiving allowances under this title. The Administrator shall, by regulation, define the sources that may be designated; specify the emissions limitation; specify the operating, emission baseline and other data requirements; prescribe CEMS or other monitoring requirements; and promulgate permit, reporting, and any other requirements necessary to implement such a program.