April 19, 2001
Gail Taber Steele
Virginia DEQ
West Central Regional Office
3019 Peters Creek Road
Roanoke, VA 24019

Re: Glen Lyn Power Plant Title IV Acid Rain Permit Amendment

AIRS ID No. 51-071-0002, Registration No. 20460

Dear Ms. Steele:

On behalf of the Blue Ridge Environmental Defense League Board of Directors and over 2,200 members in Virginia, North Carolina, South Carolina, and Tennessee, I write to provide comments on the Glen Lyn Power Plant in Giles County, Virginia. These comments are supplemental to those provided in a letter to you dated February 8, 2001 by Mr. Mark Barker, our Board Vice President from Roanoke, Virginia.

General Comments

The draft permit dated January 5 incorporates a NO_x averaging plan which would take the place of the standard emission limits in units 6, 51, and 52. We recommend denial of the draft permit based on the failure of the alternative contemporaneous emissions limitation plan to protect public health in Giles County, southwest Virginia, and in the nearby states of West Virginia, Kentucky, and North Carolina.

The averaging of air pollution emissions among electric generating units of a particular utility group lacks the sound underpinning of science. It is a political engine which results in pollution hot spots, that is, higher levels of pollution in some communities in return for a promise of lower levels in another. But regional ozone chemistry does not obey human laws. And the proximity of other large pollution sources will confound the predictions of the best computer models. For example, Duke Power’s Belews Creek coal-fired power plant north of Winston-Salem is closer to the Glen Lyn plant than AEP’s Clinch River units in Russell County, Virginia. The huge levels of nitrogen oxides, sulfur dioxide, hydrochloric acid, sulfuric acid, and other pollutants from the Belews Creek plant, added to the pollution of Glen Lyn, will overwhelm the marginal predictions of Virginia DEQ’s computer model which already indicates that the proposed permit will raise local pollution levels to over 95% of national ambient air quality limits. AEP’s 39 unit multi-state averaging plan is a shell game which, if approved by DEQ, would leave the people of Giles County the losers.

Specific Comments

The permitting authority must include explanations for proposed changes in emissions limits and monitoring for the facility. The DEQ’s draft permit’s Statement of Basis cites the statutory and regulatory authority for the issuance of the permit, but omits any explanation or justification for DEQ’s alteration of the existing permit. Nitrogen oxides emissions are principally responsible for ground level ozone pollution which causes shortness of breath, asthma, and shortens people‘s lives. Several questions arise based on our reading of the draft permit:

Will the permittee be required to do more or less monitoring under the new permit? If less monitoring is required, what is the justification for the reduction? If more monitoring is required, how will it be done and under what timetable? How often will the permittee be required to perform ambient monitoring?

Do stack tests indicate that the proposed averaging plan will control pollution levels? How will public health be protected under the alternative contemporaneous emissions limitation plan?

What data, other than computer modeling, indicate that ambient ozone levels will remain at or below current concentrations? How will the permittee or DEQ ensure that NAAQS will be maintained?

The statement of basis must include DEQ’s rationale for new or less strict monitoring requirements and the statutory basis for the changes. A simple listing of rules and regulations is insufficient. Federal rules require that the permit application compliance plans include more than an identification of options under available to the permittee under the law. The permit must include additional information.

40 CFR Ch. I (7–1–96 Edition) § 76.9 (emphasis added)§ 76.9 Permit application and compliance plans.

(c) Information requirements for NOX compliance plans. (1) In accordance with § 72.40(a)(2) of this chapter, a complete compliance plan for NOX shall, for each affected unit included in the permit application and subject to this part, either certify that the unit will comply with the applicable emissions limitation under § 76.5, 76.6, or 76.7 or specify one or more other Acid Rain compliance options for NOX in accordance with the requirements of this part. A complete compliance plan for NOX for a source shall include the following elements in a format prescribed by the Administrator:

(i) Identification of the source;

(ii) Identification of each affected unit that is at the source and is subject to this part;

(iii) Identification of the boiler type of each unit;

(iv) Identification of the compliance option proposed for each unit (i.e., meeting the applicable emissions limitation under § 76.5, 76.6, 76.7, 76.8 (early election), 76.10 (alternative emission limitation), 76.11 (NOX emissions averaging), or 76.12 (Phase I NOX compliance extension)) and any additional information required for the appropriate option in accordance with this part;

(v) Reference to the standard requirements in § 72.9 of this chapter (consistent with § 76.8(e)(1)(i)); and (vi) The requirements of §§ 72.21 (a) and (b) of this chapter.

The proposed permit would allow huge increases in nitrogen oxide pollution. The draft permit contains maximum, rather than minimum, annual heat input limits for units 6, 51, and 52. According to 40 CFR 76.11, a maximum heat input value is required for utility units requesting less stringent emission limits. Therefore, it is fair to say that AEP expects these three units to generate higher annual NO_x emissions.

§ 76.11 Emissions averaging.

(4) Each unit included in an averaging plan shall have a minimum allowable annual heat input value (mmBtu), if it has an alternative contemporaneous annual emission limitation more stringent than that unit’s applicable emission limitation under § 76.5, 76.6, or 76.7, and a maximum allowable annual heat input value, if it has an alternative contemporaneous annual emission limitation less stringent than that unit’s applicable emission limitation under § 76.5, 76.6, or 76.7.

In fact, the three units at Glen Lyn would emit 1,780 tons more NO_x per year if the draft permit is granted by DEQ (Table 1). Added to the 7,022 annual tons of NO_x emitted in 1999, AEP’s emissions in Giles County would increase by 25%. The Glen Lyn plant would go from ninth to sixth place among the dirtiest stationary sources in Virginia. As Mr. Barker demonstrated in his comments of February 8, there has been a rising trend in annual NO_x emissions at Glen Lyn since 1993. The citizens of southwest Virginia already bear a heavy burden from emphysema (7,093), chronic bronchitis (46,884), and asthma (adults 32,439, children 13, 847). The proposed increases in NO_x and dangerous ground level ozone represent an added risk to public health which cannot be justified.

Table 1. Annual Increases in Nitrogen Oxides Under Glen Lyn NOx Averaging Plan

*Data from Virginia Department of Environmental Quality

Conclusion

The Glen Lyn coal-fired electric power plant is one of Virginia’s top NO_x polluters; the plant has gradually increased its NO_x emissions over the last decade. No further increase in hourly emissions or annual emissions should be permitted. Moreover, the Phase II NOx averaging plan would allow increases in total NOx emissions for all of AEP’s 39 units. The only acceptable air pollution plan is one would require lower emissions at each and every plant operating in Virginia.

Respectfully submitted,

Louis Zeller
Blue Ridge Environmental Defense League
Clean Air Campaign Coordinator
PO Box 88
Glendale Springs, NC 28629

Feb 9, 2001 - Comments on Glen Lyn Power Plant Acid Rain Amendment
Virginia's 9 coal-fired electric power plants