NC0004979_Comments to Draft Permit_20161213

SOUTHERN ENVIRONMENTAL LAW CENTER
Telephone [phone] SOUTH PACK SQUARE. SUITE 700 Facsimile 828-258-2024
ASHEVILLE, NC 28801-3494
May 5, 2015
VIA EMAIL AND U.S. MAIL
Mr. S. Jay Zimmerman, Acting Director
DENR Division of Water Resources
1617 Mail Service Center
Raleigh, N.C., 27699-1617
[e-mail]
[e-mail]
Re: Draft NPDES Permit — Allen Steam Station, #NC0004979
Dear Mr. Zimmerman:
i ECEWED/NiODENWR
DEC 13 2016
Water Qtialiiy
Permitting Section
On behalf of the Catawba Riverkeeper Foundation, Inc. (the "Foundation"), the
Waterkeeper Alliance and the Sierra Club, we submit the following comments on the draft
National Pollutant Discharge Elimination System ("NPDES") permit noticed for public comment
by the North Carolina Department of Environment and Natural Resources ("DENR"), Division
of Water Resources ("DWR"), which purports to allow an unlimited number of unspecified and
uncontrolled point source discharges from the Allen Steam Station ("Allen") coal ash lagoons
owned and operated by Duke Energy Carolinas LLC ("Duke") into Lake Wylie ("the Lake") on
the Catawba River. Each of the undersigned organizations have many members who rely on the
quality of Lake Wylie and the Catawba River for their livelihoods and additional members who
regularly fish, swim, boat and regularly recreate on these waters.
As set forth below, the proposed permit violates the Clean Water Act ("CWA") because
it purports to allow uncontrolled leakage from this wastewater treatment facility rather than
requiring the leaks to be stopped. For this and other deficiencies highlighted below, the draft
permit must be withdrawn, substantially revised and reissued for public comment.
I. The Proposed Permit Violates North Carolina's Groundwater Rules
A. DENR Must Impose Conditions To Prevent Further Groundwater
Contamination
Because of groundwater contamination at or beyond the compliance boundary at Allen,
the state groundwater rules prohibit DENR from issuing the proposed NPDES permit for the
Allen coal ash lagoons.
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North Carolina's groundwater rules state that "the [Environmental Management]
Commission will not approve any disposal system subject to the provisions of G.S. 143-215.1
which would result in a violation of a groundwater quality standard beyond a designated
compliance boundary." 15A N.C.A.C. 2L .0103(b)(2). This prohibition applies to the Allen
permit. The draft permit states on its face that it is issued under the authority of "North Carolina
General State 143-215.1." The Allen coal ash lagoons are qualifying "disposal systems" for
purposes of the Groundwater Rule, with a compliance boundaries set by the rule. 15A N.C.A.C.
2L.0107. Because DENR issues this permit under authority delegated by the Environmental
Management Commission (15A NCAC 02A .0105), this prohibition applies to DENR as well.
There is no question that the disposal system authorized by this permit will result in a
violation of a groundwater quality standard at a designated compliance boundary. It already has.
There is an extensive history of documented groundwater contamination at the compliance
boundary at Allen. Indeed, DENR has ordered Duke Energy to undertake assessment activities
and filed an enforcement case in Superior Court nearly two years ago seeking injunctive relief to
abate groundwater contamination at the site. In its enforcement case DENR alleged, under oath,
that exceedances of the groundwater standards for nickel, iron, and manganese, uncorrected,
"pose a serious danger to the health, safety, and welfare of the people of the State of North
Carolina and serious harm to the water resources of the State." Complaint % 117-119, 197.
Duke's own monitoring well data indicates additional exceedances for boron. Revised
Groundwater Assessment Plan at 6. These exceedances have been documented since at least
2011. A 2014 drinking water supply well and receptor survey map indicates a potential plume of
groundwater contamination stretching beyond Duke's compliance boundary, past its property
boundary and onto private property. Allen Drinking Water Receptor Survey, Fig. 1. The
existence of this plume is supported by the monitoring data recently released indicating the
presence of coal -ash constituents in 51 private water supply wells surrounding the Allen plant
mentioned below. On this record, DENR cannot reissue a permit for a failing wastewater
treatment system without imposing new conditions to correct this long track record of
groundwater contamination.
Similarly, the Groundwater Rule bars the EMC (and DENR acting on delegated
authority) from approving an NPDES permit that would result in "the impairment of existing
groundwater uses or increased risk to the health or safety of the public due to the operation of a
waste disposal system." 15A N.C.A.C. 2L .0103(b)(3). Here too, no prognostication is required
to determine if the coal ash ponds will violate this prohibition. The Allen coal ash ponds have
already caused an impairment of existing groundwater uses. In February 2015 DENR began
collecting groundwater samples from residential wells within 1,000 feet of Allen ash ponds. On
April 16, 2015, DENR advised 51 homeowners neighboring the Allen plant 96% of the homes
sampled — to stop drinking or cooking with water from their residential wells because they have
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been contaminated with constituents characteristic of coal ash including vanadium and
hexavalent chromium.
Groundwater violations at the compliance boundary for Allen and impairment of
neighboring groundwater uses will only continue, in violation the Groundwater Rule, if the ash is
allowed to remain in the unlined lagoons where it will continue leaching pollutants into the
groundwater. Because this disposal system has already resulted in violations of groundwater
quality standards and will continue to do so, DENR cannot issue the proposed NPDES permit
without imposing conditions sufficient to ensure these violations will cease. Requiring final
closure of the Allen ash impoundments and removal of the ash to safe, dry lined storage is the
only assured solution to arresting ongoing violations of groundwater quality standards at the
compliance boundary.
B. DENR Must Define Compliance and Review Boundaries and Require
Groundwater Monitoring Pursuant to the Groundwater Rule.
The Groundwater Rule directs that "[t]he [compliance] boundary shall be established by
the Director, or his designee at the time of permit issuance." 15A NCAC 02L .0107(c)
(emphasis added). The draft permit as distributed to the public for comment includes no map
designating a compliance boundary for the Allen facility. This is a critical omission.
Prior maps issued by DENR for Allen have drawn the compliance boundary for the
facility,so that it extends underneath Lake Wylie. But DENR does not have the discretion to
draw a compliance boundary past the property boundary of Duke Energy. 15 NCAC 02L
.0107(a), (b). Because Lake Wylie was formed by the impoundment of the Catawba River, a
navigable river held in public trust by the state of North Carolina for the benefit of all citizens,
Duke Energy does not own the lake bed underneath Lake Wylie, and the compliance boundary
must be drawn to stop at the lake shore. Furthermore, the General Assembly has clarified that
"[m]ultiple contiguous properties under common ownership" may be treated as a single property
for purposes of drawing the compliance boundary, but only if they are "permitted for use as a
waste disposal system." N.C.G.S. § 143-215.1. Even if Duke Energy wants to assert that it
owns title to the lakebed of the Lake Wylie, Duke Energy cannot claim, and DENR cannot, as a
matter of federal law treat a water of the United States (Lake Wylie) as part of a waste disposal
site.
.This requirement of law, that compliance boundaries cannot extend underneath adjacent
jurisdictional waters, is also common sense. As DENR has acknowledged, groundwater
routinely discharges into surface water bodies and most surface waters serve as groundwater
divides. This makes it impossible to measure compliance with groundwater standards under a
surface water body because the groundwater constantly interacts with the surface water. For that
reason, Duke Energy's Groundwater Assessment Plan for the Allen site proposes to assess

compliance with it's the compliance boundary, as previously drawn by DENR, by `modeling"
the contamination in groundwater under Lake Wylie. DENR must specify a compliance
boundary for the Allen plant that complies with the requirements of North Carolina law and
facilitates credible measurement of groundwater compliance.' To meet that task, the compliance
boundary cannot be beneath a surface water body.
Finally, the permit must be amended to impose a robust groundwater monitoring program
that complies with the requirements of the Groundwater Rule. Currently the draft rule states
only that "[t]he permittee shall conduct groundwater monitoring to determine the compliance of
this NPDES permitted facility with the current groundwater standards ... in accordance with the
sampling plan approved by the Division." Draft Permit Condition A(14). Historically, DENR
has required Duke Energy to monitor groundwater contamination only at the compliance
boundary. But the Groundwater Rule requires more. All lands within a compliance boundary
carry the Restricted Designation under the Groundwater Rule; and all lands carrying the Restrict
Designation must have a `monitoring system sufficient to detect changes in groundwater quality
within the RS designated area." 15A NCAC 02L .0104(b), (d) (emphasis added). Under the
Groundwater Rule, it is not enough to monitor at the compliance boundary to confirm violations
after they happen; rather Duke Energy must monitor groundwater within the RS -designated
compliance boundary to detect when "contaminant concentrations increase" so that "additional
remedial action or monitoring" can be required if necessary. Id. at .0104(d).
H. The Draft Permits Sets Deficient Technology -Based Effluent Limits
Any NPDES permit issued by DENR for the Allen facility must set effluent limits reflecting
the best available technology to eliminate discharges whenthat core objective of the Clean Water
Act is achievable for a given waste stream. At the Allen plant, the best available technology is
zero discharge for all major waste streams involving its ash impoundments, including the
contaminated seeps that the draft permit proposes to authorize into perpetuity. Ultimately, the
guaranteed solution to stopping seeps is permanently and responsibly closing these failing
wastewater treatment ponds and removing residual coal ash to a lined landfill.
A. DENR Failed to Require Zero Liquid Discharge as the BAT for Waste Streams
at the Allen Plant
The Clean Water Act requires this NPDES permit to impose technology-based effluent
limits ("TBELs") reflecting "the minimum level of control that must be imposed in a permit."
40 C.F.R. § 125.3. For the pollutants at issue in the Allen permit, TBELs must reflect the
pollution reduction achievable by "application of the best available technology economically
1 Furthermore, DENR must designate a review boundary for the Allen plant. Every NPDES permitted facilities with
a compliance boundary also has a review boundary which is defined as the point "midway between a waste
boundary and a compliance boundary at which groundwater monitoring is required." 15 NCAC 02L.0102(20).
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achievable" ("BAT"'). 40 CFR 125.3(a)(2)(iii)-(v). Whether or not Duke Energy implements the
specific technology determined to be the BAT, it must comply with the effluent limitations that
could be achieved by the BAT. The BAT sets a stringent treatment standard that requires
"elimination of discharges of all pollutants if... such elimination is technologically and
economically achievable." 33 U.S.C. § 1311(b)(2)(A).
EPA's current effluent limitation guidelines (ELGs) for coal-fired power plants do not
define the treatment that is "technologically and economically achievable" for most of the waste
streams relevant to the Allen permit, including FGD waste, bottom ash transport water, ash pond
discharge, and ash pond seeps. "Where promulgated effluent limitations guidelines only apply to
certain aspects of the discharger's operation, or to certain pollutants, other aspects or activities
are subject to regulation on a case-by-case basis in order to carry out the provisions of the Act."
40 C.F.R. § 125.3(c)(3). As a result, DWR must use "best professional judgment" ("BPJ") to
establish BAT for waste streams not subject to the 1982 effluent limitation guidelines. 33 U.S.C.
§ 1342(a)(1); 40 C.F.R. § 125.3(a). When applying BPJ "[i]ndividual judgments []take the place
of uniform national guidelines, but the technology-based standard remains the same." Texas Oil
& Gas Assn v. U.S. E.P.A., 161 F.3d 923, 929 (5th Cir. 1998). In other words, the DWR must
operate within strict sideboards when identifying BAT based on BPJ. North Carolina regulations
require that "[a]ny state NPDES permit will contain effluent limitations and standards required
by ... the Clean Water Act which is hereby incorporated by reference including any subsequent
amendments and editions." 15A N.C. Admin. Code 211.0118.
There are two steps in determining BAT. First, the permit writer must assess what
technologies are "available." Second, of the available technologies the permit writer must assess
which are economically achievable. The technology that obtains the highest reduction in
pollutants and is also economically achievable is the BAT.
The initial determination under BAT, technological availability, is "based on the
performance of the single best -performing plant in an industrial field." Chem. Mfrs. Assn v. U.S.
E.P.A., 870 F.2d 177, 226 (5th Cir.) decision clarified on reh'g, 885 F.2d 253 (5th Cir. 1989); see
Am. Paper Inst. v. Train, 543 F.2d 328, 346 (D.C. Cir. 1976)(BAT should "at a minimum, be
established with reference to the best performer in any industrial category"). In short, if the
technology is being utilized by any plant in the industry, it is available. See Kennecott v.
U.S E.P.A., 780 F.2d 445, 448 (4th Cir. 1985)(" In setting BAT, EPA uses not the average plant,
but the optimally operating plant, the pilot plant which acts as a beacon to show what is
possible").
Further, "Congress contemplated that EPA might use technology from other industries to
establish the [BAT]." 780 F.2d at 453 (emphasis added). International facilities can also be used
to define BAT. Am. Frozen Food Inst. v. Train, 539 F.2d 107, 132 (D.C. Cir. 1976). Even pilot
studies and laboratory studies can be used to establish BAT; the technology need not be in ,
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commercial use to be considered available. See American Paper Inst. v. Train, 543 F.2d 328,
353 (D.C. Cir. 1976).
After completing an expansive technological availability analysis, DWR must determine
if the technology is economically achievable, i.e., whether it can "be reasonably borne by the
industry." Waterkeeper Alliance, Inc. v. U.S E.P.A., 399 F.3d 486, 516 (2d Cir. 2005)(citations
omitted). For a facility -specific BPJ determination, a technology is economically achievable if it
can be reasonably borne by the facility owner; in this case, Duke Energy.
Here, DWR inexplicably limited its consideration of technological and economic
availability to two facilities in the same industry, owned by the same parent company, located
within 125 miles of the Allen plant. Allen Fact Sheet at 4. This level of analysis is falls short of
DWR's obligations under the Clean Water Act. An adequate review of existing technologies
reveals multiple technologies which achieve zero liquid discharge for waste streams from FGD
systems, bottom ash transport water,2 and ash pond discharge. The costs of these technologies
can reasonably be borne by Duke Energy, the nation's largest utility. Because the Clean Water
Act mandates that BAT limits eliminate a discharge if, "on the basis of information available . .
such elimination is technologically and economically achievable," zero liquid discharge must be
incorporated as the BAT for these waste streams. 33 U.S.C. § 1311(b)(2)(A).
1) Zero Liquid Discharge is BAT for FGD Wastewater
A zero -liquid discharge limit for FGD wastewater is the BAT for the Allen Plant. It
cannot reasonably be disputed that technology is available which would achieve zero liquid
discharge for FGD wastewaters. EPA Region 1 recently found zero liquid discharge to be the
BAT for the Merrimack Station in New Hampshire because "technologies are capable of
eliminating the direct discharge of pollutants." Merrimack Station Revised NPDES Permit No.
NH0001465 Fact Sheet at XX. The specific technology, physical -chemical treatment plus vapor
compression evaporation ("VCE") and crystallizer systems, is also being used to achieve zero
liquid discharge at Kansas City Power & Light's Iatan plant and several Italian plants. Id. One
purveyor of mechanical evaporation technology, Veolia Water Solutions and Technologies,
describes it as "a simple and economical approach to [zero liquid discharge].0 To quote EPA:
these systems "are the best performing treatment systems for the purpose of reducing discharges
of pollutants to the Nation's waters. In other words, these systems make the greatest `... further
progress toward the national goal of eliminating the discharge of all pollutants. ' 33 USC
1311 (b) (2) (A). " Revised NPDES Permit No. NH0001465 Fact Sheet at 17 (emphasis in
original).
2 Duke is already meeting its zero liquid discharge BAT requirements for fly ash transport water through utilization
of a dry fly ash handling system.
3 http://www.et3a.gov/reizionl/nodes/MmTimarkstation/pdfs/ar/AR102O.pdf
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With technology is available, zero liquid discharge is the BAT for the Allen plant if the
cost of such technology can reasonably be borne by Duke. Here, we know that it can because
Duke has already installed zero liquid discharge technology at its Mayo plant and that plant
remains economically viable. That is, Duke installed zero liquid discharge technology at the
Mayo plant at a predicted cost of $120,000,000 despite that fact that, at the time, Duke did not
consider zero liquid discharge to be the BAT. Mayo NPDES No. NC00038377 Fact Sheet at 2.
2) Zero Liquid Discharge is BAT for bottom ash transport water
Similarly, the technology necessary for zero liquid discharge of bottom ash transport
water is also indisputably available. Over 30% of coal-fired power plants and petroleum coke -
fired power plants already utilize these technologies4 and 83% of coal-fired units built in the last
twenty years installed dry bottom ash handling systems. 78 Fed. Reg. 34470. In considering
new effluent limitation guidelines for steam electric power generators, EPA concluded that "all
plants ... are capable of installing and operating dry handling or close -loop systems for bottom
ash for bottom ash transport water." Id.
Duke Energy has installed zero liquid discharge bottom ash handling systems at least at
two plants in its North Carolina fleet, Cliffside and Mayo. These plants have remained
economically viable with dry bottom ash handling systems in operation. EPA estimated that
installation of zero liquid discharge bottom ash handling systems would be particularly
economically feasible for plants with a generating capacity over 400 MW, such as Allen. 78
Fed. Reg. 34470. Moreover, the Allen plant is required to convert to dry bottom ash handling
within the term of this NPDES permit — by 2019. N.C.G.S. § 130A -309.210(f). Because zero
liquid discharge technology is available, is economically achievable, and will soon be required
by the State of North Carolina, it must be the BAT for bottom ash transport water.
3) Zero Liquid Discharge is BAT for ash pond discharge
For decades, the ash management system at the Allen plant has operated by sluicing wet
ash to ponds for long -term -storage. In the ponds, ash is removed from the ash transport water
through settling. The removed ash, now no longer a part of the wastewater treatment system, is
then stored in the ponds while the ash transport water is discharged to Lake Wylie. Technology-
based effluent limitations apply to the ash transport water being discharged to Lake Wylie as the
result of applying TBELs to particular waste streams (FGD, bottom ash transport water, etc), but
TBELs also apply to separate discharges from the removed ash. To wit, "[t]echnology-based
effluent limitations shall be established ... for solids, sludges, filter backwash, and other
pollutants removed in the course of treatment or control of wastewaters in the same manner as
for otherpollutants." 40 C.F.R § 125.3(g)(emphasis added).
4 For a list of available technologies see 78 Fed. Reg.34453-34454.
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As applied to ash ponds, this regulatory system contemplates two different TBELs: one for
the permitted outfall and another for the discharge of pollutants removed in the course of
treatment or control of wastewaters. There is no question that discharges from removed
substance via seeps or other means, which are themselves contaminated with residual coal ash
that has settled out of the impoundment, are subject to TBELS and an independent BAT analysis
like any other waste stream. Indeed, DWR has recognized that TBELs must be set for
discharges from the "removed substances" through seeps (Outfalls 010 and 011) as well as for
the historically permitted outfall (Outfall 002).
We note that DWR's own fact sheet acknowledges that "[t]he CWA NPDES permitting
program does not normally envision permitting of uncontrolled releases from treatment systems;
such releases are difficult to monitor and control, and it is difficult to accurately predict their
impact on water quality. Releases of this nature would typically be addressed through an
enforcement action requiring their elimination rather than permitting." Draft Allen Fact Sheet at
2. Nonetheless, DWR takes the position that seeps at Duke Energy's Allen facility somehow get
preferential treatment as a "unique circumstance where the occurrence of the seeps is attributable
to an original pond design that will require long-term action to fully address." Fact Sheet at 2.
Regardless, "unique circumstances" do not excuse DWR from correctly calculating BAT
and applying TBELs. Just as DWR failed to complete the proper analysis for determining BAT
as applied to FGD waste and bottom ash transport water, DWR failed to follow the proper
procedure in calculating the BAT for discharges from "pollutants removed in the course of
treatment or control of wastewaters" at the Allen plant, resulting in improper TBELs. The
technology to achieve zero liquid discharge from removed substances in ash basins is readily
available, economically achievable, and is currently being implemented at ash basins across
South Carolina and at Duke Energy's own facilities in North Carolina — closure of the ponds and
removal of the ash to dry, lined storage to ensure it does not continue to be a source of unabated
and polluted seepage. Moreover, the fact sheet concedes that zero discharge of seeps is
achievable and ultimately required, but fails to set TBELS or a schedule for implementation
reflecting that technological solution.
a. Closure of these failing wastewater treatment plants and removal of the coal ash
is, of course, technologically achievable and therefore required by law.
As explained above, the BAT for internal waste streams currently discharging to the ash
ponds is zero liquid discharge. DENR and EPA both require wastewater treatment facilities that
are no longer in service to be closed pursuant to an approved closure plan that addresses the fate
of residual sludge removed in the wastewater treatment process. The fact sheet acknowledges
that additional "action to close or otherwise address coal ash impoundments and their threats to
surface waters and groundwater" is necessary. Fact Sheet at 3.
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Moreover, even if the Allen plant had a continuing need for an onsite wastewater
treatment facility, the current wastewater treatment facility is failing and releasing
"uncontrolled" seeps into nearby surface waters, and cannot be reauthorized. Wastewater
treatment systems operate by retaining pollutants removed by its designed treatment system and
then discharging treated water. By allowing uncontrolled and undesigned leaks and flows from
the walls, sides, bottom, and dam of this supposed wastewater treatment facility, DENR would
be permitting a wastewater treatment facility that is fundamentally defective. Such authorization
defeats the very purpose of the waste treatment system authorized by the permit — the treatment
and removal of pollutants from industrial wastewater. Uncontrolled seeps, and the removed
wastewater pollutants they contain, bypass the controlled release of treated and monitored
wastewater via the riser system at the permitted discharge.
Because the Allen plant has no continuing legitimate need for these wastewater treatment
ponds and cannot obtain reauthorization for these failing wastewater treatment facilities, DENR
must mandate closure of the ponds and elimination of contaminated seeps through the best
available technology — removing the source of that contamination, the residualcoal ash, to dry
lined storage. DENR does not need to look far for proof that this solution is achievable.
Multiple examples are found right here in the Carolinas.
In South Carolina, SCE&G had unpermitted seeps and groundwater contamination at its
Wateree Station facility on the portion of the Catawba River called the Wateree River. Today,
SCE&G is in the midst of removing all its coal ash from unlined lagoons at Wateree Station to
safe, dry, lined storage in a landfill away from the Wateree River. SCE&G has already removed
approximately 600,000 tons of coal ash from its Wateree facility. In filings with the South
Carolina Public Service Commission, SCE&G has publicly stated its commitment to clean up the
coal ash at its other facilities in South Carolina as well.
Similarly, South Carolina's Public Service Authority utility, known as Santee Cooper,
has also committed to excavate its coal ash from unlined lagoons and store it in dry, lined
landfills or recycle it for concrete. Santee Cooper's Executive Vice President of Corporate
Services described the removal and recycling of the unlined coal ash from the lagoons as "cost-
effective" and a "triple win" for the utility's customers, the environment, and the local economy.
At last report, Santee Cooper has already removed 164,000 tons from its Grainger Generating,
Station in Conway, SC, where unlined coal ash at a retired facility had contaminated the
groundwater and adjacent wetlands with arsenic and other pollutants. Santee Cooper has
removed 1201000 tons from its Jefferies Generating Station in Moncks Corner, SC. And it will
begin removing the coal ash from its Winyah Generating Station in Georgetown, SC, in May of
this year.
Also, in April 2015, conservation groups signed an agreement with Duke Energy for
Duke to remove all the coal ash — more than three million tons — from its W. S. Lee facility on the
Saluda River in Anderson County, South Carolina. Attachment A. Duke will remove all the
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coal ash to dry, lined storage away from the river, including the ash from two leaking lagoons
and in an ash storage area near the lagoons. In September 2014, the South Carolina Department
of Health and Environmental Control entered into a consent enforcement agreement with Duke
Energy in which Duke was required to remove coal ash from two other storage areas on the
Saluda River's banks at the Lee facility. Attachment B.
Duke Energy's other coal ash site in South Carolina, the H.B. Robinson facility, stores
4.2 million tons of coal ash on the shore of Lake Robinson and Black Creek in Darlington
County, SC. This site has serious groundwater contamination and a history of low-level
radioactive waste being disposed of in the unlined coal ash basin. On April 30, 2015, after
months of public pressure from conservation groups calling for a cleanup, Duke publicly
committed to excavating all the coal ash at Robinson' and storing it in a dry, lined landfill on site.
Sammy Fretwell, "Duke to clean up toxin -riddled waste pond in Hartsville," The State (Apr. 30,
2015).
Finally, Duke Energy has agreed to remove ash at four facilities in North Carolina:
Asheville, Dan River, Riverbend, and Sutton. These facilities are plainly implementing a
technology which results in the elimination of discharges — the ultimate goal under the Clean
Water Act. 33 U.S.C. -§ 1311(b)(2)(A).
The technology to achieve zero liquid discharge from the ash basins is not only available,
but is economically achievable. SCE&G and Santee Cooper have both stated that ash removal
has not affected the economic viability of its plants or had any effect on customer rates. In fact,
Santee Cooper has described the decision to remove ash as a win -win-win that is good for its
customers.5 Ash removal projects in North Carolina, such as at Duke Energy's Asheville plant
where 3 million tons of ash have already been removed, also demonstrate the economic benefit,
more than "achievability," of removing stored ash from ponds. Zero liquid discharge is both
technologically and economically achievable and represents BAT for discharges from the
removed substances in the Allen coal ash ponds. And it eliminates the continuing seepage into
groundwater and surface waters, as well as the risk of a catastrophic dam failure or spill, such as
Duke Energy's Dan River spill in February 2014
b. The permit acknowledged that zero discharge is attainable for seeps but fails to
impose corresponding TBELS or any schedule of completion.
Not only has DENR failed to account for the proven solution of removing coal ash, the fact
sheet itself concedes the existence of a zero discharge technological solution available to Duke
Energy to address coal ash seeps but fails to impose TBELs based on that technology.
5 http://www.wcne.com/story/news/pohties/2014/07/04/11127148/
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The Fact Sheet acknowledgesthat "[r]eleases of this nature would typically be addressed
through an enforcement action requiring their elimination ...." Fact Sheet at 2. The Fact
Sheet further recognizes the availability of a zero discharge solution — collection and "rerouting
the discharge" and "discontinuing the discharge." Condition A(21) n.l. Nonetheless, DENR
requires no action from Duke Energy to complete those measures, attempting to defer instead to
the eventual completion of a state process under the Coal Ash Management Act. This approach
is fraught with problems. Fundamentally, a deferred an unenforceable promise of future action
under a separate state statute does not satisfy the requirements of the Clean Water Act.
First, CAMA is not a part of the North Carolina's federally approved delegated CWA
program, cannot pre-empt CWA requirements, and indeed has not been approved by EPA as part
of the delegated CWA authority for review and issuance of NPDES permitsDENR has an
obligation under federal law to put in place a Clean Water Act permit that complies with and
carries out the requirements of the Clean Water Act, regardless of any state law
provisions. Indeed, EPA can withdraw North Carolina's authority to manage its own CIean
Water Act program if the State fails to follow federal regulations or if the "State legislature .:
strik[es] down or limit[s]" a state agency's authority to implement the Clean Water Act consistent
with federal law. 40 C.F.R. § 123.63(a)(1)(i-ii). Recognizing this, the General Assembly was
clear that the requirements of Coal Ash Management Act are "in addition to any other
requirements for identifying discharges," "for the assessment of discharges," or "for corrective
action tgo prevent unpermitted discharges" from coal ash impoundments. N.C.G.S. § 1320A -
309.212(a)(1), (b), (c). Therefore, the Allen permit, which is issued under the Clean Water Act,
must require the cleanup of these primitive coal ash storage sites and the removal of the ash to
safe, dry, lined storage — apart from any requirements of CAMA.
Second, while the fact sheet is explicit that permitting illegal seeps is "an interim measure"
pending implementation of the BAT, the draft permit does not require implementation of the
ultimate solution. The Clean Water Act requires the ultimate solution. DENR must require
compliance with the discharge limits achievable by the implementation of the best available
technology now.
EPA regulations unambiguously prolu'bit the use of compliance schedules6 to comply with
BAT requirements. Under EPA regulations, DWQ may use compliance schedules to achieve
"compliance with CWA [Clean Water Act] and regulations ... as soon as possible, but not later
than the applicable statuto , deadline under the CWA." 40 C.F.R. § 122.47(a)(1)(emphasis
added). Here, the relevant statutory deadlines have passed for the permitted wastestreams. See
33 U.S.C. § 1311(b)(2). "[A] permit writer may not establish a compliance schedule in a permit
for TBELs [technology-based effluent limits] because the statutory deadlines for meeting
technology standards ... have passed." EPA Permit Writers Manual, Section p. 9-8 (2010); see
6 EPA defines a compliance schedule as "a schedule of remedial measww, ... including an enforceable sequence of
interim requirements (for example, actions, operations, or milestone events) ...: ' 40 CY R § 122.2.
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also EPA Permit Writers Manual, Section 9.1.3 p. 148 (1996). Thus, EPA regulations prohibit
use of compliance schedules to comply with attainable BAT limits for seeps.
Even if DENR did have the authority to delay compliance with limits attainable through
an acknowledged BAT, the draft permit does not impose a valid a compliance schedule. The
Fact Sheet notes that installation of a BAT solution for seeps would require construction and
time to implement, but sets no time limits for implementation of those requirements. A
compliance schedule must impose "an enforceable sequence of interim requirements" leading to
Clean Water Act compliance. 40 C.F.R. § 122.2 (emphasis added).. Under a valid compliance
schedule, the time between interim dates must not exceed one year. id. The Draft Permit requires
no concrete steps towards ultimate achievement of the zero discharge BAT standard
acknowledged by the draft permit as attainable for seep discharges.
M. The TBELs set by the Permit are Deficient Even Under DENR's Faulty
Determination of the BAT For Ash Ponds.
Without explanation, DENR recognizes that technology-based effluent limits set by the
permit for mercury, arsenic, selenium and nitrate from the coal ash seeps can be met through a
variety of technologies including "installation of the treatments system, rerouting the discharge
to the existing treatments system, or discontinuing the discharge." Condition A(21) n.l. As
explained above, the proven solution of closing ash ponds and removing ash, together with
DENR's acknowledgement that other zero discharge options exist for the seep waste stream,
confirm that zero discharge is the BAT for seeps. Nonetheless, DENR appears to have set
TBELs for seeps based on the lesser technological option of installing a wastewater treatment
system. However, even taking DENR's deficient approach to the BAT at face value, DENR has
failed to set TBELs achievable by implementation of a wastewater treatment system for the seep
waste streams from "Outfall 10" and "Outfall 11" and the primary discharge from Outfall 2.
First, the permit sets technology-based effluent limitations (TBELs) for only one metal,
Mercury, from Outfall 2. But DENR offers no reliable scientific basis for using,mercury as the
sole moxy for the mobility of all heavy metals in .the coal ash discharge. Coal ash contains
different concentrations of various contaminants depending on the origin of the coal, and each of
these contaminants may behave very differently depending upon the site-specific
conditions. Trace metals can form complexes with ions (such as chloride or sulfate) or dissolved
organic carbon. Some metals form complexes much more readily than others. These complexes
change the speciation of the metal in the water and thus can greatly impact its mobility (typically
making it more mobile). Mobility of different metals can also be significantly impacted by pH
or other site-specific factors.
DENR, instead, defends this assumption with the statement in the new draft ELG's for
power plants that four parameters (total Arsenic, Total Mercury, Total Selenium, and Nitrate) are
12

IL
acceptable proxy parameters for all other metals in the coal ash impoundment waste stream. But
even if those four parameters could collectively stand in for all other contaminates at all power
plants, DENR sets TBEL limits for only one of them for out Outfall 2 — Mercury. This omission
is glaring in that DENR is clearly aware that the ash pond has the potential to discharge any of
the four metals it identifies as "proxies" (and many more) because it purports to set WQBELs for
those same parameters from Outfalls 10 and 11. If the ash pond discharges a pollutant, it must
be analyzed under the Clean Water Act and a TBEL assigned that ensures that it is treated
through the best available technology. Although DENR sets limits for all four proxy metals
nominated by EPA at the FGD internal Outfall 5, the draft permit ignores the contribution of
bottom ash and other waste streams to the arsenic, selenium and nitrate/nitrite loading in the ash
basins. DENR must set independent TBELs for Outfall 2, "Outfall 10," and "Outfall 11."
Thus, relying on mercury as the only TBEL metal means significant contaminants in the
Allen seep discharges may not be controlled. Metals such as cadmium,.nickel, and zinc are
typically present in coal ash in greater concentrations than mercury — often orders of magnitude
greater. Accordingly, TBELs need to be added for thallium, vanadium, cadmium, nickel, and
zinc. Data from groundwater monitoring wells surrounding the ash ponds as well as from nearby
residential drinking water wells reveal the presence of unsafe levels of vanadium and nickel
attributable to the Allen ash ponds. DWR's own monitoring data referenced as justification for
establishing maximum allowable parameter concentrations from seeps confirms that the ponds
are discharging cadmium, nickel, and zinc at far greater quantities than the TBEL set for
mercury. Draft Permit at 14.
The only other TBELs set by the permit for Outfall 2 are for Copper and Iron, but those
limits apply only "during a chemical metal cleaning." Condition A.(2) n.1. Because metal
cleaning wastes currently discharge to the very large volume of wastewater in the ash pond, there
is no reliable justification for limiting the application of TBELs to the specific days when metal
cleaning is occurring, without accounting for the time required for the metal cleaning waste
stream to assimilate into the contents of the ash basin and eventually impact the permitted
discharge at Outfall 2 and the new "Outfall 10" and "Outfall 11.11 Seep sampling collected by the
Catawba Riverkeeper Foundation as well as seep sampling performed by DENR confirms that
copper and iron are present in the ash ponds and being discharge on a regular basis even when
metal cleaning wastes are not actively being discharge to the ponds. EPA's Draft Merrimack
Station NPDES permit set TBELs for many more pollutants than DENR did for Allen's Outfall
002. EPA, Determination of Technology -Based Effluent Limits for the Flue Gas Desulfurization
Wastewater at Merrimack Station in Bow, New Hampshire (Sept. 23, 2011), at 48-49.
Attachment C. In addition to the four pollutants DENR included for Outfall 002, EPA included
TBELs for cadmium, chromium, copper, lead, manganese, zinc, chlorides, and total dissolved
solids. Technology-based numerical effluent limitations for these substances should be added to
13

the Allen permit. Additionally, the Allen permit should include TBELs for boron and sulfates
which Duke Energy has asserted are typical of contamination in the ash pond.
As explained above, the BAT for waste streams into and out of the ash ponds is zero
discharge. But even if zero discharge could be defensibly ignored, the draft permit must be
revised to set responsible TBELs for the ash pond discharges from Outfall 2,"Outfall 10," and
"Outfall l 1." Secondary treatment options for ash pond discharge are now established and
would be the BAT even if it were true that zero discharge is not available. At the Merrimack
Station, EPA correctly found that the BAT for FGD wastewater was zero liquid discharge. But
in processing the permit application, EPA developed arsenic, chromium, copper, mercury,
selenium and zinc TBELs for Merrimack Station's FGD wastewater based on "statistical analysis
of self-monitoring data ... at Duke Energy's Allen and Belews Creek Stations." Attachment C
at 32. In its draft permit, DENR states that it based its TBELs on the "95th percentile of the
effluent data" discharging over five years from Duke Energy's A11en, Marshall, and Belews
Creek facilities. Fact Sheet at 4 (emphasis added). If data from Allen and Belews Creek was
sufficient to develop TBELS for Merrimack, it is more than sufficient to develop TBELs here.
Nonetheless, the draft permit sets no TBEL limits at all for metals in Outfall 2, aside from
mercury, and authorizes discharges at concentrations that are significantly higher than the
originally proposed Merrimack TBELs — again, even though these are supposedly based on the
same facilities analyzed by EPA for that permit, including Allen and Belews Creek. DENR
appears not to have performed the same rigorous TBEL analysis that EPA did, nor does it appear
to have looked to more sophisticated permits and treatment technologies like the Merrimack
facility.
For example, the arsenic limit in these permits is higher than the draft Merrimack permit.
Arsenic is a known carcinogen that causes multiple forms of cancer in humans. It is also a toxic
pollutant, 40 C.F.R. § 401.15, and a priority pollutant, 40 C.F.R. Part 423 App'x A. Arsenic is
also associated with non -cancer health effects of the skin and the nervous system. In the draft
Merrimack permit, where EPA analyzed the treatment technology at Allen and Belews Creek
and based its limits.on what could be achieved, EPA set the monthly average at 8 ug/L.
Attachment C at 39. But the Allen draft permit sets no limit for arsenic from Outfall 2 and sets .h
monthly limit for internal Outfall 5 and "Outfalls 10 and 11" of 10.5 ug/L. Similarly, EPA's
draft Merrimack permit limit for selenium set the monthly average at 10 ug/L, versus 13.6 ug/L
in the Allen permit for internal Outfall 5 and "Outfalls 10 and 11" (and no limit for Outfall 2);
and the draft Merrimack permit set a selenium daily maximum of 19 ug/L, versus 25.5 ug/L in
the Allen permit for internal Outfall 5 and "Outfalls 10 and 11" (and no limit for Outfall 2).
Attachment C at 47.
7 See htty://www.charlotteobserver.com/news/local/article19l53437.html.
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For Mercury, EPA noted that it could have set the monthly average limit at 22 ng/L in the
draft Merrimack permit, versus 47 ng/L for Allen, but then noted that the Merrimack facility
actually incorporates an additional "polishing" step that allowed the technology based limit for
mercury in the Merrimack permit to be set at just 14 ng/L. Attachment C at 44. If this limit is
achievable in New Hampshire, it should be achievable in North Carolina, as well, regardless of
the requirements of the TMDL.
IV. The Draft Permit Authorizes Uncontrolled and Unidentilliable Leaks from Lagoons
In Violation of the Clean Water Act, Defeats the Purpose of the Permit in Violation
of the Clean Water Act, and Violates the Public Notice and Comment and Other
Requirements of the Clean Water Act
The proposed permit (section A.21) purports to authorize any leaking -streams of
contaminated coal ash wastewater discharging from the Allen lagoons into Lake Wylie that may
emerge anywhere along the facility's property line, now or in the future — without being
identified and characterized in the NPDES application or the permit itself.
A. The Proposed Permit Violates the CWA's Prohibition on Unpermitted Point
Source Discharges
Each of these streams of contaminated water is a point source discharge to surface waters
of the United States. Thus, the proposed permit purports to authorize unspecified point source
discharges, in violation of the CWA, 33 U.S.C. § 1311(a).
Under the CWA, "[elvery identifiable point that emits pollution is a point source which
must be authorized by a NPDES permit ...." U.S. v. Tom Kat Dev., Inc., 614 F. Supp. 613, 614
(D. Alaska 1985) (citing 40 C.F.R. § 122.1(b) (1). Accord U.S. v. Earth Sciences, Inc., 599 F.2d
368, 373 (10th Cir. 1979); Legal Envtl Assistance Found., Inc. v. Hodel, 586 F. Supp. 1163, 1168
(E.D. Tenn. 1984); U.S, v. Saint Bernard Parish, 589 F. Supp. 617 (E.D. La. 1984)). The
"NPDES program requires permits for the discharge of `pollutants' from any `point source' into
`waters of the United States."' 40 C.F.R. § 122.1(b)(1) (emphasis added).
Rather than complying with this straightforward requirement of the CWA, the proposed
Permit instead declares that a fictional "Outfall 010" would encompass any and all "seeps
entering the river from the upstream edge of permittee's property to the downstream property
boundary ... as if entering at one location." This approach is impermissible under the Clean
Water Act.
The proposed permit attempts to limit the total amount of seep discharge and maximum
allowable pollutant concentrations — but those limits are totally impracticable. The Fact Sheet
itself acknowledges that the seeps are "difficult to monitor and control, and it is difficult to
'accurately predict their impact on water quality." Indeed, Duke Energy is unable even to
complete a competent application for an NDPES permit for these future wastestreamms because it
15

lacks the most fundamental information required by Form 2C — the Outfall locations and flow
characteristics. See Permit Writer's Handbook 4.3.5. And even if these requirements could be
put into effect — which is highly unlikely, as DENR acknowledges — they could not remedy this
fundamental flaw in the permit's approach to the polluted leaks.
. The proposed permit's blanket authorization of the seeps violates the most basic
principles of the Clean Water Act. DENR itself acknowledges in the Fact Sheet that "[t]he CWA
NPDES permitting program does not normally envision permitting of uncontrolled releases from
treatment systems" and "[r]eleases of this nature would typically be addressed through an
enforcement action requiring their elimination rather than permitting." Fact Sheet at 2
(emphasis added). DENR's statements are even more striking in light of the fact an enforcement
action filed by DENR is currently pending against Duke Energy for those very same seeps at
Allen.
Finally, DENR's proposal to issue a CWA permit that attempts to authorize an unlined
impoundment to continue leaking into surface and groundwater water is plainly inconsistent with
performance standards under the new federal CCR rule promulgated by EPA under RCRA
(published in the federal register April 20, 2015). Under that rule, existing unlined
impoundments that have documented violations of groundwater standards are subject to closure
pursuant to a suite of federal requirements. E.g., 40 C.F.R. § 257.101. In contrast, DENR's
proposal to try to "legalize" the leaking impoundments is at odds with the federal CCR rule —
which will not even allow these types of leaky impoundments to continue to operate as is. Like
the CWA requirements for BAT and zero discharge, so too complimentary federal requirements
for CCR storage do not allow leaky unlined impoundments that have contaminated groundwater
to stay in operation.
B. The Proposed Permit's Blanket Authorization of the Seeps Violates the
CWA's Public Participation Requirements
As well, this arrangement would allow Duke to evade public notice and comment and the
opportunity for a public hearing and for judicial review, along with all the other requirements of
the state NPDES permitting program, 33 U.S.C. § 1342(b). A new undesigned and
undesignated flow of polluted water may spring from this supposed wastewater treatment facility
at any time. The permit asserts that these newly identified seeps "will not be considered as new
outfalls." Condition A(21). It further promises that new seeps will be "administratively added"
to the permit. That new outfall will not have been the subject of the public notice, comment, and
hearing requirements, or any other requirements of the Clean Water Act. Instead, this permit
purports to authorize those discharges and outfalls in advance, without any of the process and
protections required by the Clean Water Act. As drafted, this permit is evades the Clean Water
Act entirely for these new and undescribed outfalls and discharges.
16

But it is beyond the authority of DENR to authorize new point source discharges without
proceeding through the procedures of a modification of the NPDES permit with public comment
and EPA oversight. EPA's regulations authorize limited administrative changes to an active
permit through minor modifications, none of which condone the administrative addition of a new
NPDES outfall. 40 U.S.C. § 122.63. Ultimately, this promise of a permit shield and
administrative amendment of Duke Energy's permit has the effect of bypassing public comment,
EPA oversight and judicial review for the life of this permit for a poorly defined and monitored
(waste stream). This scheme is inconsistent with the requirements of the Clean Water Act.
V. The Draft Permit Fails to Set Protective Water Quality Based Effluent Limits
A. Duke Energy Must Comply with Water Quality Standards at all Points in Lake
Wylie Because the Draft Permit Fails to Specify a Mixing Zone.
In prior communications with Duke Energy regarding pollution discharge and thermal
impact to Lake Wylie caused by Duke Energy's effluent, DENR has referenced a "mixing zone"
below Duke Energy's discharge, but neither the prior nor the current permit authorizes a mixing
zone for this facility. Under North Carolina law a mixing zone must be "defined by the
division." 15A NCAC 02B .0204. The mixing zone must be drawn so that it does not result in
acute toxicity, offensive conditions, undesirable aquatic life or result in a dominance of nuisance
species outside of the assigned mixing zone, or endangerment to the public health or welfare. Id.
Federal law likewise requires mixing zones to be defined to a discrete area designed to allow
adequate mixing of pollutants and protect over all water quality. See generally 2010 Pertnit
Writer's Manual Chapter 6. The draft permit not only fails to define a mixing zone but provides
no basis from which to reliably determine whether water quality standards and permit conditions
are being met outside the undefined mixing zone. A related deficiency is that the fact sheet fails
to explain how the mixing zone is calculated to comply with the minimum requirements of the
Clean Water Act and state law.
B. Water Quality Based Effluent Limits for Ash Pond Seeps are Inadequate
The method by which many of the effluent limitations for the seeps were set appears to
be arbitrary and capricious. The draft permit (at A.17) states that "[t]he maximum allowable
parameter concentration in Table I is determined by multiplying the highest baseline seep
concentration levels by 10." The Fact Sheet states that the reasonable potential analysis (RPA)
analyzed the highest concentration for each parameter chosen from the 12 identified seeps, and it
also states that there was no reasonable potential to violate water quality standards or EPA
criteria. But there is no information in the permit about what "baseline seep concentration
levels" were used in this flawed approach. Thus, there is no way for the public to evaluate how
17

these limits were established because they are presented in a vacuum. The Fact Sheet's
explanation of the reasonable potential analysis (p. 4) states only that the "highest concentration
for each constituent was chosen from one of the 12 seeps", and analyzed for potential water
quality violations.
Furthermore, the effluent limits and RPA for the draft limit are inadequate because they
assume that the waste stream is being diluted by the full flow of the Catawba River. To the
contrary, the Catawba frequently remains nearly stagnant as its flow is regulated by Duke
Energy. In those instances, discharged effluent accumulates in the water surrounding the Allen
plant rather than is carried downstream.
The fact sheet acknowledges that the bodies of water between the ash ponds and Lake
Wylie are jurisdictional waters protected by state law and the federal Clean Water Act. For
example, the fact sheet suggests that action to remediate the unchecked and illegal seep
discharges from the Allen impoundments would delay ultimate closure of the impoundments
because work to collect,and reroute the discharges would require construction which "would
require 401 permits, which will create a substantial delay with ash pond decommissioning ..:."
Of course, 401 certification would be required from the state of North Carolina, only if, as is the
case here, such construction activities would be impacting jurisdictional waters. While the state
seems genuinely concerned about assuring that those jurisdictional waters receive full Clean
Water Act protections from any construction activities needed to arrest illegal discharges, it has
failed entirely to apply Clean Water Act procedures required to protect those receiving waters
from the impacts of illegal pollution.
In this respect, DENR's approach to these seeps reflects the application submitted by
Duke Energy which argues in its "Allen Steam Station Surface Water and Seep Monitoring
August and September 2014" in the permit file, that the seeps analyzed indicate "that there is
little potential for Allen Steam Station to influence water quality in Lake Wylie" but ignore the
impact on water quality within receiving water bodies between the impoundment and Lake
Wylie. Indeed the map submitted by Duke Energy with its Surface Water Sampling Report
(Figure 2) to identify surface water sampling locations in Lake Wylie indicates a blue -line
jurisdictional stream buried beneath the ash pond and emerging from its toe.
DENR must conduct a full jurisdictional analysis of waters flowing into Lake Wylie from
Duke Energy's property to determine if any are jurisdictional waters that must meet water quality
standards and conduct an RPA of the impact illegal seeps from the toe of Duke Energy's coal ash
impoundments may have on those waters. ,
C. Duke Energy's 316(a) Demonstration is Inadequate to Justify a Variance from
North Carolina's Water Quality Standard for Temperature.
18

Every NPDES permit must impose "any more stringent limitation" necessary to meet
"water quality standards," including state standards for temperature. 33 U.S.C. § 131 l(b)(1)(C).
Section 316(a) of the Clean Water Act provides narrow authority for a variance from water
quality standards for temperature, but only when such effluent limits are "more stringent than
necessary to assure the protection and propagation of a balanced, indigenous population of
shellfish, fish, and wildlife." 33 U.S.C. § 1326(a).
EPA regulations define a balanced, indigenous population as "a biotic community
typically characterized by diversity, the capacity to sustain itself through cyclic seasonal
changes, presence of necessary food chain species and by a lack of domination by pollution
tolerant species." 40 C.F.R. § 125.71(c). An industrial discharger seeking a § 316(a)
temperature variance bears the burden of demonstrating both (1) that effluent limits otherwise
required by the Clean Water Act are "more stringent than necessary" to protect the balanced,
indigenous population and (2) that the thermal discharge allowed by such a variance will protect
the balanced, indigenous population in the future. See 33 U.S.C. § 1326; 40 C.F.R. § 125.73(a)
(the -applicant must demonstrate that water quality standards are more stringent than necessary);
In Re Dominion Energy Brayton Point, 12 E.A.D. 490, 552 (2006) (EPA Environmental Appeals
Board held that § 1326(a) and EPA regulations "clearly impose the burden of proving that the...
thermal effluent limitations are too stringent on the discharger seeking the variance'). Absent a
meritorious demonstration, the applicant must comply with water quality. standards.
Duke Energy's demonstration is deficient for failure to analyze the cumulative shift in
aquatic populations in Lake Wylie over time. The demonstration as drafted speaks only to the
change in the most recent sample period but fails to demonstrate by reference to an unimpacted
water body that the cumulative effect of its thermal discharge shave not caused a shift in the
population of the lake. The impacts of past discharges on the aquatic community cannot be
ignored in a § 316(a) demonstration. In particular, shifts in species composition and other
adverse impacts attributable to past discharges cannot be disregarded. The balanced, indigenous
population of fish, shellfish and wildlife contemplated by the Act is the population that exists
absent the impacts of the applicant's thermal discharge. See 40 C.F.R. § 125.71(c) (balanced
indigenous community excludes "species whose presence or abundance is attributable to the
introduction of pollutants that will be eliminated by compliance" with water quality standards);
40 C.F.R. § 125.73(a) (demonstration must consider "the cumulative impact of its thermal
discharge together with all other significant impacts on the species affected"); In re Dominion
Energy Brayton Point, 12 E.A.D. at 557 ("[T]he population under consideration is not
necessarily just the population currently inhabiting the water body but a population that may
have been present but for the appreciable harm.")
EPA's Environmental Appeals Board ("EAB") has ruled on the exact question of
whether a shift to a thermally tolerant species composition is acceptable and found that such a
19

shift contravened the very purposes of the Clean Water Act. In Public Service Company of
Indiana, 1 E.A.D. 590, 28 (1979) the EAB found that:
[Section] 316(a) speaks only of "a balanced, indigenous population..",_
[A]ccording to [applicant], the indefinite article "a" cannot be "tortured" into the
definite phrase "the balance which would exist in the absence of heat." However,
these arguments ... would render the general goal of the Act -- to "restore and
maintain the chemical, physical, and biological integrity of the Nation's waters" --
a dead letter. Section 316(a) must ... be read in a manner which is consistent
with the Act's general purposes. Consequently, § 316(a) cannot be read to mean
that a balanced indigenous population is maintained where the species
composition, for example, shifts ... from thermally sensitive to thermally
tolerant species. Such shifts are at war with the notion of "restoring" and
"maintaining" the biological integrity of the Nation's waters.
More recently, the EAB again emphasized that a § 316(a) demonstration may not "ignore
the fact that the abundance of certain species ... has been altered over the past several decades"
because such an interpretation would be "inconsistent with the regulations, the legislative history
of section 316(a), the purpose of the CWA, and prior case law." In Re Dominion Energy
Brayton Point, 12 E.A.D. at 558.
In June of 201-0; the EPA highlighted a track records of deficiency related to Duke's
316(a) demonstrations for the Allen plant including a failure to identify impacted wildlife,
identify the full scope of the thermal plume, break down fish surveys between heat sensitive and
intolerant species, analyze present data to clearly demonstrate that affected communities have
not shifted to primarily heat tolerant assemblages, and demonstrate that community assemblages
in the heat affected portions of the receiving water are not significantly different from affected
communities with regard to the number of nonindigenous species. Duke Energy's BIP
demonstrations continue to fail to meet most of these requirements. In particular, Duke Energy
analyzed its cumulative impacts by reference to a reach of the Catawba River between the Allen
plant and the Catawba Nuclear Station, a heavily impacted body of water. Furthermore, the BIP
demonstration submitted by Duke Energy for Allen demonstrates an increase in the pollution
tolerant species in affected reaches of the Catawba in the past four years over prior assessments.
D. The EMC Cannot Issue a 316(a) Thermal Variance
In any event, only the EMC can issue a variance from the temperature standard and the
EMC as currently constituted cannot do so. To administer the Clean Water Act pursuant to
delegated federal authority, the state "board or body which approves all or portions of permits
20

shall not include as a member any person who receives, or has during'the previous 2 years
received, a significant portion of income directly or indirectly from permit holders or applicants
for a permit." 40 C.F.R. § 123.25(c). In North Carolina, that "body or board" is the
Environmental Management Commission. N.C. Gen. Stat. § 143-215.1. Because the
Environmental Management Commission as a whole cannot comply with the prohibition on
receiving a significant portion of income from permit holders or applicants, permitting authority
rests in a NPDES Committee, which must include at least five non -conflicted members of the
EMC. 15A NCAC .0107(a). The current EMC does not have five non -conflicted members and
is thus unable to issue the permit.
- The EMC appears well aware of this problem. A March 2015 spreadsheet of EMC
committees has not only transformed the "NPDES Committee" required under state law (15A
N.C. Admin. Code 2A .0107) into the "NPDES Permit Appeals Committee" (signifying a change
from approving permits to only dealing with them on appeal) but does not list a single member
save one ex officio member appointed to all committees. A review of past committee agendas
reveals that there has only been one meeting of the purported NPDES committee since March
2012.
There are currently 14 individuals serving on the North Carolina EMC. Three
Commissioners (Tedder, Martin, Elam) operate consulting firms and four are lawyers or
engineers (Carter, Craven, Puette, Dawson) with practices that deal with environmental
regulatory issues such as NPDES permitting. Four commissioners appear to work for or have
retired from companies that either hold NPDES permits or rely on companies that do (Carrol,
Anderson, Ferrell, Wilsey). Three Commissioners remain who may not receive a "significant
portion of income directly or indirectly from permit holders or applicants for a permit" though
that too is unclear. Even if those Commissioners were not conflicted out of participating on the
EMC's NPDES Committee, the committee still lacks two required members. A permit cannot
issue in this instance because the delegated permitting authority, the EMC NPDES Committee,
cannot meet its regulatory requirements for non -conflicted members.
VI. The Proposed Permit Violates the Clean Water Act's Anti -Backsliding Provisions.
The draft permit would allow Duke Energy to operate a leaking wastewater treatment
system. By definition, these leaks do not discharge through the permitted outfall structures,
which include risers designed to ensure that settled pollutants remain in the lagoons and water is
discharged from the top of the lagoon to the outfall discharge pipes. DENR itself describes its
approach to the seeps as allowing "uncontrolled releases." Fact Sheet at 3. Thus, the proposed
permit would allow Duke Energy to avoid even the minimal treatment technology in place for its
currently permitted outfalls.
This change in policy stands in sharp conflict with the provisions of the existing permit
and, perplexingly, the draft permit itself. Both the draft permit and the existing permit include an
21

important standard condition, known as the Removed Substances provisionat Part II.C.6, which
provides: ,
"Solids, sludges ... or other pollutants removed in the course of treatment or
control of wastewaters shall be utilized/disposed of... in a manner such as to
prevent arty pollutant from such materials from entering waters of the State or
navigable waters of the United States." (emphasis added)
This common-sense provision prohibits pollutants removed by waste treatment facilities
from escaping out into surface and groundwater. As such, the provision is an essential
implementation of state policy and good practice requiring pollutants removed from wastewater
through the operation of a wastewater treatment plant not to be summarily discharged into
waters, in frustration of the core purpose of the state and federal pollution control programs.
DENR itself has cited Duke Energy for violating this provision by allowing liquid
discharges of removed substances to enter navigable waters due to uncontrolled releases from
Duke Energy's coal ash lagoons at its Dan River facility. In a February 28, 2014 Notice of
Violation, DENR cites the discharge "of coal combustion residuals from the ash pond to the Dan
River, class C waters of the State" as violating the Removed Substances provision: `Tailure to
utilize or dispose solids removed from the treatment process in such a manner as to prevent
pollutants from entering waters of the State (Part II, Section C. 6. of NPDES permit)."
In the context of the Allen permit, the removed substances provision is also the
implementation of a required permit component under the implementing regulations of the Clean
Water Act. Those regulations require that "[t]echnology-based effluent limitations shall be
established under this subpart for solids, sludges, filter backwash, and other pollutants removed
in the course of treatment or control of wastewaters in the same manner as for other pollutants"
40 C.F.R. § 125.3(g). Under the prior permit, DENR did not set individual TBELs for
contaminants in seeps from the ash basin but rather took the only responsible step of treating
zero liquid discharge, as implemented through the removed substances provision, as the BAT for
contaminated seeps from a coal ash impoundment. That is, consistent with the requirement to
set TBELs for pollutants removed by the wastewater treatment ash ponds, the prior permit
prohibited My discharge of removed substances to waters of the United States.
The Removed Substances provision is an important component of the Clean Water Act's
protections, and prevents waters of the United States from being polluted by waste treatment
facilities such as the Allen coal ash settling lagoons. In the Matter of 539 Alaska Placer Miners,
Nos. 1085-06-14-402C & 1087-08-03-402C, 1990 WL 324284 at *8 (EPA 1990) (inclusion of
Removed Substance provision "is based on the simple proposition that there is no way one can
prbtect the water quality of the waters of the U.S if the [polluter] is allowed to redeposit the
pollutants collected in his settling ponds") (Doc. 26-9).
22

Parts of the draft permit purporting to authorize leaks would abandon this sensible,
longstanding and recently enforced prohibition on discharge of removed substances and the
recognition that zero liquid discharge is the acceptable TBEL for the seep wastestream, which is
itself the product of a failing wastewater treatment system. That change in course violates the
Clean Water Act.
The Clean Water Act's NPDES permitting program is structured around progressive
improvements in pollution control technology. The requirement of Best Available Technology
("BAT") is predicated on the concept that as treatment technology improves, it will be
incorporated into National Pollutant Discharge Elimination System permits in order to make
progress towards Congress's "national goal" of eliminating discharges of pollutants to waters of
the United States. 33 U.S.C. §§ 1251(a)(1).
For this reason, the CWA includes anti -backsliding requirements to ensure that the limits
and conditions imposed in new or modified NPDES permits for a facility are at least as stringent
as those in previous permits. 33 U.S.C. § 1342(o); 40 C.F.R. § 122.440)(1) ('[W]hen a permit is
renewed or reissued, interim effluent limitations, standards or conditions must be at least as
stringent as the final effluent limitations, standards, or conditions in the previous permit ...: �.
The CWA's anti -backsliding requirements apply to all NPDES permit provisions
including effluent limits, best management practices and other conditions. 40 C.F.R. §
122.44(1)(1); In the Matter of Star-Kist Caribe, Inc., Petitioner, 2 E.A.D. 758 at *3 (E.P.A. Mar.
8, 1989) (emphasis added). EPA, NPDES Permit Writers' Manual Chapter 7, § 7.2.2, p. 7-4
(Sept. 2010), available at
http://water.epa.gov/polwaste/npdes/basics/upload/pwm chapt 07.pdf.
The proposed permit would, for the first time, abandon zero liquid discharge as the TBEL
for discharges of removed substances from Allen and instead issue a permit to `uncontrolled
releases" of seeps contaminated with coal ash constituents removed by the settling basin. For
this reason, the proposed permit violates the CWA's anti -backsliding requirements. Among
other things, the proposed permit would for the first time: (1) allow uncontrolled and undesigned
releases from the coal ash lagoons, (2) permit a set of undesigned and uncontrolled releases as a
single "outfall"; (3) allow uncontrolled and undesigned releases from a permitted wastewater
treatment facility; (4) allow a permitted wastewater treatment facility to leak polluted water from
the facility into State waters and navigable waters; (5) allow the facility to release discharges that
are prohibited by conditions in its current permit; and (6) create a new meaning and permitted
category of "outfall" to allow uncontrolled, undesigned, and future but -as -of -yet -determined
leaks and flows ofpolluted water.
The reversal under the current permit from the prior TBEL for removed substances
violates the anti -backsliding provisions of the Clean Water Act and its implementing regulations.
DENR cannot now retreat from the progress made towards improving water quality in Lake
23

Wylie under prior permits by relaxing the TBEL standards for removed substances that it is
required to implement in every permit For that reason, the anti -backsliding provision of the
Clean Water Act prohibits DENR from issuing a permit to Duke Energy for seeps of removed
substances for which any liquid discharge is prohibited under Duke Energy's current permit
VII. The Draft Permit Sets Inadequate Monitoring Requirements for Seeps.
The permit must require more frequent monitoring of seeps. The draft permit requires
monthly monitoring of the seeps only for the first year; thereafter, monitoring is required only
twice a year. This is inadequate.
First, the flow and levels of contaminants in the seeps are likely to change from week to
week, so two snapshots per year would make it impossible to accurately assess the amount of
pollutants discharging into Lake Wylie. While DENR has candidly admitted it would be
difficult to accurately monitor the seeps even under the best of circumstances, two samples per
year virtually guarantees the permit's effluent limits and flow requirements will not be enforced.
Second, this arrangement makes it easy for the polluter to cherry -pick two sampling
points per year with low flows to avoid violations.
Third, it makes identifying new seeps far less likely.
Finally, this schedule falls short of the requirements of the Clean Water Act.
Environmental Protection Agency C'EPA") regulations mandate that all permit limits shall,
unless impracticable, be stated as both daily maximum and average monthly discharge
limitations. 40 C.F.R. § 122.4S(d). Nothing in the fact sheet demonstrates or suggests that
monthly, or- even daily, monitoring of seep discharges is impractical.
For all these reasons, monitoring every two weeks should be required until the lagoons
are dewatered and removal begins.
VIII. Conclusion
The draft permit is inconsistent with the requirements of North Carolina and federal law
for these reasons described above. For these reasons, we ask that the permit be withdrawn,
rewritten, and reissued for the public to comment on an NPDES permit that protects water
quality and the public interest.
Sincerely,
Austin D7 Gerken
Amelia Y. Burnette
24

Patrick Hunter
Southern Environmental Law Center
22 South Pack Square, Suite 700
Asheville, NC 28801
828-258-2023
[e-mail]
[e-mail]
[e-mail]
Counsel for
Catawba Riverkeeper Foundation,
Sam Perkins, Catawba Riverkeeper®
421 Minuet Lane Suite #205
Charlotte, NC 28217
[e-mail]
Waterkeeper Alliance
Peter Harrison
19 West Hargett Street, Suite 602b
Raleigh NC 27601
[e-mail]
Sierra Club
Bridget Lee
50 F Street, NW, 8th Floor
Washington, DC 20001
[e-mail]
cc:
Crim McCarthy, EPA Administrator
Heather McTeer Toney, Regional Administrator, Region 4
25

Attachment A
W.S. Lee Steam Station
Settlement Agreement
(April 23, 2015)

i 4
SETTLEMENT AGREEMENT
This Settlement Agreement ("Agreement") is entered this day of
2015, between Upstate Forever and Save Our Saluda (collectively, the
"Conservation Groups"), on the one hand, and Duke Energy Carolinas, LLC ("Duke Energy"),
on the other, on behalf of themselves and their respective successors, predecessors, assigns,
affiliates, parent companies, subsidiaries, shareholders, officers, directors, agents, and
employees.
Whereas the parties hereto earlier entered into an agreement dated September 23, 2014
(attached hereto), under which Duke Energy agreed to remove coal ash from the Inactive Ash
Basin and Ash Fill area located at the site of the coal-fired power plant known as the W.S. Lee
Steam Station on the Saluda River in Anderson County, South Carolina. (hereinafter "W.S.
Lee"), and the Conservation Groups agreed not to take any legal action until after November 10,
2014, pending the outcome of Duke Energy's evaluation of the Primary Ash Basin, Secondary
Ash Basin, and Structural Fill areas;
Whereas the parties hereto have now resolved the matters set out in this Agreement:
Now, therefore, the parties to this Agreement agree as follows:
1. Federal Regulation. The parties acknowledge that the United States
Environmental Protection Agency promulgated the Hazardous and Solid Waste Management
system: Disposal of Coal Combustion Residuals from Electric Utilities ("CCR rule"), which was
published on , 2015, 80 Fed Reg. , and that the CCR rule
sets minimum controlling requirements for management and disposal of coal combustion
residuals and the closure of ash impoundments, and that the CCR rule requires Duke Energy to
1

publish for public availability information regarding implementation of the CCR rule, including
periodic progress reports and monitoring information.
2. Undertakings by Duke Energy. In consideration of the promises contained herein,
the adequacy of which is hereby acknowledged, Duke Energy agrees to implement the following
actions at and with respect to W.S. Lee:
(a) Within one (1) year of receiving all required regulatory permits, license,
and approvals ("approvals"), and the close of any challenges to those approvals,
commence excavating all the coal ash, and further soil removal if required by the
South Carolina Department of Health and Environmental Control ("DHEC") to
prevent impacts to groundwater quality (such ash and soil being hereinafter
referred to jointly as the "Removed Ash and Soil") from the Inactive Ash Basin
and/or Ash Fill, as indicated on the attached Exhibit A, and diligently complete
excavation of both within five (5) years;
(b) Within five (5) years of receiving all required regulatory permits, license,
and approvals, including the Closure Plan submitted to DHEC and approvals
associated with the Closure Plan, including storage or disposal permit
requirements, ("approvals"), and the close of any challenges to those approvals,
commence excavating all the coal ash, and further soil removal if required by
DHEC to prevent impacts to groundwater quality (such ash and soil being
hereinafter referred to jointly as the "Removed Ash and Soil") from the Primary
Ash Basin, Secondary Ash Basin, and/or Structural Fill at W.S. Lee, as indicated
on the attached Exhibit A, and diligently complete excavation of all within ten
(10) years of commencement;
2

(c) Dewater all impoundments in compliance the W.S. Lee NPDES permit, as
modified (the "Lee NPDES permit");
(d) Dispose of Removed Ash and Soil in lined storage meeting the
requirements in Paragraph 3 below, and approved and properly permitted
pursuant to applicable law and regulation, unless beneficially recycled in a
manner that does not result in application to the surface or subsurface of the land
except in a lined facility meeting all the requirements set forth in subparagraphs
(a) and (b) of Paragraph 3 of this Agreement.
(e) Thereafter, stabilize and close, or reuse for disposal, all the areas from
which Removed Ash and Soil were taken (collectively the "Lee Impoundments")
in accordance with applicable law, regulation, and the approved Closure Plan.
(f) Timely apply for all permits and approvals necessary to facilitate the
removal of coal ash and soil from the Lee Impoundments;
(g) Close the Lee Impoundments, which may include reuse of the impoundment
as a lined landfill, in compliance with the CCR rule and as part of the CCR rule's
required Closure Plan, identify all permits required from DHEC and apply for those in a
timely manner, as required by the CCR Closure Plan;
(h) Sample and analyze groundwater as required by the CCR rule and by the
existing NPDES permit and any additional requirements imposed by DHEC;
(i) If in two consecutive sample periods, the concentration of any monitored
groundwater constituent increases from the prior period's measurement in any
sampling well, then Duke Energy shall report the event to DHEC and confer with
DHEC on what remedial action is needed, if any, provided that no reporting or

remedial action shall be required for any concentrations below the applicable
groundwater standard.
3. Duke Energy and the Conservation Groups agree to the following.
(a) All of the Removed Ash and Soil from the Lee Impoundments shall be
deposited into a properly permitted facility meeting, at a minimum, all siting,
construction and engineering requirements of 40 C.F.R. Part 258 (Subtitle D of
RCRA) and, if disposal occurs in South Carolina, South Carolina's sanitary
landfill regulation for Class III landfills (Regulation 61-107.19, Part V), except
that a lined landfill on the Lee site that meets all other requirements of this
Paragraph may have a waste boundary located 500 feet or more from the Saluda
River. Duke Energy will not seek approval of a design pursuant to 40 C.F.R. §
258.40(a)(1), S.C. Code Regs. 61-107.19, or under the laws of another state
unless it has obtained prior written approval of the Conservation Groups for that
design.
(b) Removed Ash under this Consent Order will be stored in a lined CCR
landfill space meeting all requirements established by applicable statute, law, and
regulation. CCR landfill is defined in the CCR rule. Any material that is
commingled with Ash shall be disposed of in accord with applicable federal or
state regulations. Nothing in this Paragraph shall prohibit the Company from
disposing, depositing, or processing Removed Ash through beneficial reuse
including lined structural fill applications, lined mine reclamations, abrasives,
filter materials, concrete, cement or such other technologies as provided for under
state and federal law (including the CCR rule, as applicable). In no event shall
4

J 4
any Removed Ash and Soil be placed in a solid waste landfill that does not meet
the requirements set forth in subparagraphs (a) and (b) of this Paragraph. If the
Removed Ash and Soil is removed to and stored in a lined structural fill site, or
used for another beneficial purpose, the Removed Ash and Soil will not be
permanently deposited on the surface or subsurface of the land except in a lined ti
facility meeting all the requirements set forth in subparagraphs (a) and (b) of this
Paragraph, provided that Removed Ash and Soil may be relocated and stored
temporarily on the surface of the land if part of permanent lined disposal on site in
compliance with the approved Closure Plan. Duke Energy shall not place coal
ash in or on any perennial stream at the Lee site.
4. Undertakings of the Conservation Groups. In consideration of the promises
contained herein, the adequacy of which is hereby acknowledged, the Conservation Groups
agree:
(a) The Conservation Groups will not object to, contest, or sue with regard to
the Closure Plan for the Lee Impoundments or with regard to any approval needed
to comply with this Agreement provided that the closure plan and any approval is
consistent with the terms of this Agreement.
(b) The Conservation Groups, on behalf of themselves and their successors,
predecessors, assigns, affiliates, parent companies, subsidiaries, officers,
directors, agents, and employees, hereby completely release and forever discharge
Duke Energy from all civil claims that could have been alleged by the
Conservation Groups related to unpermitted discharges from the Lee
Impoundments, contamination of groundwater from the Lee Impoundments,
5

NPDES permit violations related to the Lee Impoundments, and for management
of coal ash at W.S. Lee in compliance with this Agreement; provided, however,
that nothing in this paragraph shall limit the Conservation Groups' right to
enforce compliance with the terms and conditions of this Agreement.
(c) The Conservation Groups, on behalf of themselves and their successors,
predecessors, assigns, affiliates, parent companies, subsidiaries, officers,
directors, agents, and employees, hereby covenant not to bring a citizen suit for
coal ash pollution from the Lee Impoundments under the CCR rule or the South
Carolina Pollution Control Act, so long as Duke Energy is substantially in
compliance with all terms and conditions of this Agreement.
(d) The Conservation Groups shall not object to or otherwise contest or sue in
connection with any of the following:
(i) The Closure Plan for the Lee Impoundments, provided that plan is
consistent with the terms of this Agreement;
(ii) Any and all permits and approvals necessary to effectuate this
Agreement, facilitate the removal of coal ash and soil from the Lee
Impoundments, and close the Lee Impoundments consistent with and as
provided in this Agreement, including but not limited to any permit to
construct or operate an onsite landfill for the disposal of coal ash and soil.
5. Force Majeure. Duke Energy agrees to perform all requirements under this
Agreement within the time limits established under this Agreement, unless the
performance is delayed by a force majeure.
on

(a) For purposes of this Agreement, a force majeure is defined as any event
arising from causes beyond the control of the company, or any entity controlled
by the company or its contractors, which delays or prevents performance of any
obligation under this Agreement despite best efforts to fulfill the obligation and
includes but is not limited to war, civil unrest, act of God, or act of a
governmental or regulatory body delaying performance or making it impossible,
including, without limitation, any appeal or decision remanding, overturning,
modifying, or otherwise acting (or failing to act) on a permit or similar permission
or action that prevents or delays an action needed for the performance of any of
the work contemplated under this Agreement such that it prevents or substantially
interferes with its performance within the time frames specified herein.
(b) The requirement that Duke Energy exercise "best efforts to fulfill the
obligation" includes using commercially reasonable efforts to anticipate any
potential force majeure event and to address the effects of any potential force
majeure event: (i) as it is occurring, and (ii) following the potential force majeure
event, such that the delay is minimized to the greatest extent possible.
(c) Force majeure does not include financial inability to complete the work,
increased cost of performance, or changes in business or economic circumstances.
(d) Failure of a permitting authority to issue a necessary approval in a timely
fashion may constitute a force majeure where the failure of the permitting
authority to act prevents Duke Energy from meeting the requirements in this
agreement, and is beyond the control of Duke Energy, and Duke Energy has taken
all steps available to it to obtain the necessary permit, including but not limited to
7

submitting a complete permit application, responding to requests for additional
information by the permitting authority in a timely fashion, and accepting lawful
permit terms and conditions after expeditiously exhausting any legal rights to
appeal terms and conditions imposed by the permitting authority.
6. Warrant o� f Capacity to Enter into Agreement. The parties represent that they
have the legal capacity to enter into this Agreement, and that this Agreement is not for the
benefit of any party other than those who .have entered into this Agreement, and gives no rights
or remedies to any third parties.
7. Entire Agreement. This Agreement contains the entire understanding and
agreement between the parties to this Agreement with respect to the matters referred to herein.
No other representations, covenants, undertakings, or other prior or contemporaneous
agreements, oral or written, respecting such matters, which are not specifically incorporated
herein, shall be deemed in any way to exist or to bind any of the parties to this Agreement. The
parties to this Agreement acknowledge that all terms of this Agreement are contractual and not
merely a recital.
8. Modification by Writing Only. The parties agree that this Agreement may be
modified only by a writing signed by all parties to this Agreement and that any oral agreements
are not binding until reduced to writing and signed by the parties to this Agreement.
9. Binding upon Successors and Assigns. The parties to this Agreement agree that
this Agreement is binding upon the parties' respective successors and assigns.
10. Execution in Counterparts. This Agreement may be executed in multiple
counterparts, each of which shall be deemed an original Agreement, and all of which shall
constitute one agreement to be effective as of the Effective Date. Photocopies or facsimile

copies of executed copies of this Agreement may be treated as originals. A duly authorized
attorney may sign on behalf of a corporate entity.
11. Notice and Communication Between the Parties.
(a) Notices required or authorized to be given pursuant to this Agreement
shall be sent to the _P ersons at the addresses set out below in subparagraph (c). Notices
are effective upon receipt. Duke Energy will contemporaneously provide counsel for the
Conservation Groups with copies of all: (i) reports submitted to DHEC that are required
by this Agreement, as well as any reports submitted to DHEC regarding any spills or
releases of coal ash into the Saluda River and any breaks or breaches of the Lee
Impoundments); (ii) groundwater monitoring data and NPDES discharge monitoring
reports) submitted to DHEC; and (iii) permit applications, including the Closure Plan,
submitted to DHEC that are related to the undertakings specified in this agreement;
provided however, that any portion of any such report or data that is deemed proprietary
information by a Duke Energy contractor, shall be redacted to the extent that it is
submitted to DHEC as proprietary information; only those portions deemed proprietary
information will be redacted. Commencing six months after the execution of this
Settlement Agreement, and continuing each six months thereafter until one year after
excavation of the Removed Ash and Soil has been completed, Duke Energy will provide
counsel for the Conservation Groups with a written report summarizing its actions under
this Agreement, including (1) the amount of ash and soil removed during the six-month
period; (2) the results of all monitoring, sampling and analysis of ash, soil and
groundwater at W.S. Lee; (3) the progress of dewatering of Lee Impoundments; (4) all
E

activities performed pursuant to this Agreement during the six-month period; and (5) the
destination and/or intended use of the Removed Ash and Soil.
(b) Alternatively, in lieu of providing the reports and information above
directly to counsel for the Conservation Groups, Duke Energy may choose to make any
of the reports and information in subparagraph (a), available on a website that is
accessible to the public. If Duke Energy chooses to comply with subparagraph (a) by this
alternative means of making any such report or information available via a publicly
accessible website, Duke Energy shall first notify counsel for the Conservation Groups
regarding which reports or information will be provided by this alternative means. If at
any time Duke Energy chooses to no longer make such report or information available on
a publicly accessible website, it shall then provide counsel for the Conservation Groups
such report or information pursuant to the means described in subparagraph (a).
(c) Reports and other materials required by this Agreement to be sent by Duke
Energy may be sent by Duke Energy to counsel for the Conservation Groups by e-mail.
All other notices may be delivered in person or sent by U.S. Mail or an overnight delivery
service. Any party may change the persons and/or addresses for notice by providing
notice to the representative(s) of the other party set out below.
For the Conservation Groups:
Frank S. Holleman III, Esq.
Southern Environmental Law Center
601 W. Rosemary Street, Suite 220
Chapel Hill, North Carolina 27516
[e-mail]
For Duke Energy Carolinas, LLC:
Garry S. Rice, Deputy General Counsel
Duke Energy Corporation
10

550 South Tryon Street
Mail Code DEC45A
Charlotte, NC 28202
[e-mail]
12. Governing Law. This Agreement shall be construed and interpreted in
accordance with the laws of the State of south Carolina.
13. Effective Date. This Agreement shall become effective immediately following
execution by all of the parties listed below.
Executed this I S day of AvA j i zas by;

Executed this day of by:
UPSTA FOREVERj�
By: � V V
Its: L�. 2 Gc.c� V C2 1
12

n
Executed this day of or`i by:
SAVE OUR SALUD
By.
Its• ergs; .j
13

'Y�� '.�, > ,�' s ' •;meq ,
ice
..
a�
Secondary Ash Pond►
rimary Ash Pond
or
All
Arbii
,
tructurd iI'l
Inactive Ash"Basin
tz
`� �„r _ J Ash Fill Area

(� DUKE
ENERGY.
September 23, 2014
Mr. Frank Holleman
Southern Environmental Law Center
601 West Rosemary Street, Suite 220
Chapel Hill, NC 27516-2356
Dear Mr. Holleman:
CONFIDENTIAL
David B. Fountain
Senior Vice President
Enterprise Legal Support
Duke Energy
411 Fayetteville Street, NC20
Raleigh, NO 27601
919-546-6164
This letter and agreement is to follow up on the conversations between Upstate Forever, Save
Our Saluda, and Duke Energy concerning the Primary and Secondary Ash Basins (Active
Basins), Inactive Ash Basin (referred to at times as the "51/59 Pond") and the Ash Fill Area
(referred to at times as the "former borrow area") at the WS Lee Steam Station.
As you are aware, Duke Energy has been conducting an analysis of the Active Basins as well
as the Inactive Ash Basin and Ash Fill Area. That analysis has been based on generally
accepted scientific and engineering principles as applied to the specific factors that affect the
WS Lee Steam Station. The Company has not yet completed that analysis; however, the
Company has completed enough of the analysis to reach the following conclusions:
• Sound engineering and scientific principles as applied to the WS Lee Steam Station
have led the Company to conclude that a "lined" solution Is appropriate for the Inactive
Ash Basin and Ash FII Area (shown on the attached map).
Specifically, for the Inactive Ash Basin and Ash Fill Area located directly south of the Inactive
Ash Basin, the ash will be placed in a storage area that will include a synthetic liner, leachate
control and monitoring, and a cover. Whether the storage will occur off-site or on-site remains
to be determined.
• The Company has not yet reached a conclusion as to the best scientific and engineering
solution to the management of the ash in the Active Basins.
While the Company's evaluation of the Active Basins is ongoing, the Company has concluded
that if the Active Basins are to remain in operation for a significant time, then structural
conditions will need to be addressed, including repairs to the secondary Impoundment dam.
Duke Energy is already developing remedial design plans for the upstream slope of the
Secondary Ash Basin Dam and will proceed with any other repairs needed to ensure continued
safe operating conditions until closure. The Company expects to have its analysis completed by
early November and will provide an update to you at that time (or earlier should the analysis be
completed at an earlier time).
�� a �� .clul.r•enerr� sum

Mr. Frank Holleman
September 23, 2014
Page 2
CONFIDENTIAL
• The ultimate closure decision on the Active Basin Dams will be part of a comprehensive
review of the site and will be designed for long-term groundwater protection.
I believe this letter sets forth accurately, in a summary fashion, the commitments that the
Company has previously made during the course of our conversations. I know you appreciate
that, because the analysis is still ongoing, the Company has not yet been able to reach final
decisions other than as to those issues noted above. However, I can assure you that just as
sound engineering and scientific principles dictated the conclusions noted above, they will
continue to dictate our final conclusions as well.
Therefore, we propose that Duke Energy Carolinas, LLC, Upstate Forever, and Save Our
Saluda agree as follows:
1. Duke Energy Carolinas, LLC agrees that the coal ash in the Inactive Ash Basin and
Ash FII Area located south of the inactive Ash Basin will be removed and placed in a
storage area that will include a synthetic liner, leachate control and monitoring, and
cover that comply with all applicable laws and regulations. Whether the storage will
occur off site or on site remains to be determined.
2. By November 10, 2014, Duke Energy Carolinas, LLC will inform Upstate Forever and
Save Our Saluda of its plans for the remaining coal ash storage sites at the W.S. Lee
Steam Station, including the Active Basins and the ash fill area to the south of the
Active Basins, its plans for the Active Basins' dams, and the approximate timetable
for removal and storage of coal ash.
3. Upstate Forever and Save Our Saluda agree not to take any legal action (including
sending Notices of Intent to Sue under federal statutes) until after
November 10, 2014.
4. All parties reserve their rights as to what other actions should be taken with respect
to the coal ash at the W.S. Lee Steam Station.
If the above terms are agreeable to your clients, please so indicate by signing below. This letter
represents Duke Energy Carolinas, LLC agreement to such terms.
Sincerely,
David B. Fountain
Senior Vice President, Enterprise Legal Support
On behalf of Duke Energy
Attachment

Mr. Frank Holleman
September 23, 2014
Page 3
Senior Attorney, Southern Environmental Law Center
On Behalf of Upstate Forever and Save Our Saluda
CONFIDENTIAL

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Attachment B
DHEC-Duke-W.S. Lee Steam Station
Consent Agreement
(September 2014)

THE STATE OF SOUTH CAROLINA
BEFORE THE DEPARTMENT OF HEALTH AND ENVIRONMENTAL CONTROL
IN RE: DUKE ENERGY CAROLINAS, LLC
W.S. LEE STEAM STATION
ANDERSON COUNTY
CONSENT AGREEMENT
14 -13- HW
This Consent Agreement is entered into between the South Carolina Department of Health
and Environmental Control (SCDHEC or the Department) and Duke Energy Carolinas, LLC (Duke
Energy) with respect to the investigation and remediation of two ash placement areas at the William
States (W.S.) Lee Steam Station located at 205 Lee Steam Road, Belton, South Carolina in Anderson
County (Tax Map Number 260-00-01-003-000). The Site shall include the "Inactive Ash Basin" and
the "Ash Fill Area," and all areas where ash, other coal combustion residuals, or their constituents,
including contaminants, (collectively Coal Combustion Residuals or CCR or ash) may have
potentially migrated from these ash placement areas, collectively referred to as the "Site."
Duke Energy is entering into this Consent Agreement to assess and address any release or
threat of release of Coal Combustion Residuals or other pollutants from the Site to the environment
and to provide for the final disposition of the Site. Duke Energy will take all necessary steps in
compliance with all environmental laws to prevent future releases from the Site. In the interest of
resolving the matters herein without delay, Duke Energy agrees to the entry of this Consent
Agreement without litigation and without the admission or adjudication of any issue of fact or law,
except for purposes of enforcing this agreement. Duke Energy agrees that this Consent Agreement
shall be deemed an admission of fact and law only as necessary for enforcement of this Consent
1

Agreement by the Department or in subsequent actions relating to this Site by the Department.
FINDINGS OF FACT
Based on information known by the Department, the following findings of fact are asserted
by the Department for purposes of this Consent Agreement:
1. Duke Energy owns and operates W.S. Lee Steam Station as a cycling station to supplement
supply when electricity demand is high. Three (3) coal-fired units, which became
operational in the 1950's, generate approximately 370 megawatts (MW) of electricity. Units
1 and 2 were introduced to service beginning in 1951 followed by Unit 3 in 1959. Two (2)
combustion turbines (CTs) were added in 2007 and generate an additional approximate 84
MWs. The CTs use diesel fuel or natural gas as their fuel source and serve as emergency
back-up power to Oconee Nuclear Station.
2. Prior to 1974, CCR was placed in the Inactive Ash Basin, which is an unregulated basin
located south of the power plant. Constructed in 1951 and expanded in 1959, the Inactive
Ash Basin was formed by an approximately 3,700 feet long rim dike that impounds
approximately 19 acres. The dike has, a maximum height of 60 feet above grade with a crest
elevation of 690 feet above sea level.
3. CCR is believed to have been used in the past as backfill into a borrow area identified as the
Ash Fill Area, which is located near the Inactive Ash Basin.
4. On May 1, 2014, Duke Energy initiated geotechnical characterization of the Inactive Ash
Basin.
5. On May 30, 2014, Duke Energy submitted a plan for the geotechnical characterization on the
Ash Fill Area.
2

A 6
CONCLUSIONS OF LAW
The Department has the authority to implement and enforce laws and related regulations
pursuant to the South Carolina Hazardous Waste Management Act, S.C. Code Ann. §44-56-10, et.
seq. (Rev. 2002 and Supp. 2013), the Pollution Control Act, S.C. Code Ann. §48-1-10 et seq. (Rev.
2008 and Supp. 2013) and the South Carolina Solid Waste Policy and Management Act, S.C. Code
Ann. §44-96-10, et. seq. (Rev. 2002 and Supp. 2013). These Acts authorize the Department to issue
orders; assess civil penalties; conduct studies, investigations, and research to abate, control and
prevent pollution; and to protect the health of persons or the environment.
NOW, THEREFORE IT IS AGREED, with the consent of Duke Energy and the
Department, and pursuant to the South Carolina Hazardous Waste Management Act, the Pollution
Control Act, and/or the Solid Waste Policy and Management Act, that Duke Energy shall:
1. Within ninety (90) days of receipt of this fully executed Consent Agreement, submit to the
Department for review and approval, an Ash Removal Plan for the Site. The Ash Removal
Plan shall include a time schedule for implementation of all major activities required by the
Plan. The Ash Removal Plan must include, but is not limited to, characterization of the ash,
provisions for the safe removal of the ash, management of storm water during the project,
and management alternatives for the ash by either beneficial reuse or disposition in a South
Carolina permitted Class 3 solid waste disposal facility or a facility meeting equivalent
standards outside of South Carolina. The Ash Removal Plan shall also include an evaluation
of the stability of the rim dike and any other slopes impounding the CCR placement areas
during ash removal activities. Any comments generated through the Department's review of
the Ash Removal Plan, must be addressed in writing by Duke Energy within fifteen (15) .
days of Duke Energy's receipt of said comments. Upon the Department's approval of the
Ash Removal Plan and the time schedule for implementation thereof, the Ash Removal Plan
3

and schedule shall be incorporated herein and become an enforceable part of this Consent
Agreement.
2. Submit, along with but under separate cover from the Ash Removal Plan, a Health and
Safety Plan (HASP) consistent with Occupational Safety and Health Administration
regulations. The HASP shall be submitted to the Department in the form of one (1)
electronic copy (.pdf format). Duke Energy agrees the HASP is submitted to the Department
for informational purposes only. The Department expressly denies any liability that may
result from Duke Energy's implementation of the HASP.
3. Begin implementation of the Ash Removal Plan described in paragraph 1 within fifteen (15)
days of Duke Energy's receipt of the Department's written approval of the Ash Removal
Plan.
4. Upon completion of the work approved in the Ash Removal Plan, submit an Ash Removal
Report to the Department. The Ash Removal Report shall summarize the activities taken
during implementation of the Ash Removal Plan and shall contain appropriate
documentation that ash has been removed from the Site in accordance with the Ash Removal
Plan.
5. Within thirty (30) days of approval of the Ash Removal Report, submit an Assessment Plan
to the Department. The Assessment Plan shall include, but is not limited to, the following: a
description of work needed for the delineation of the vertical and horizontal extent of any
contamination, including an assessment of surface water, groundwater, and soil underlying
the Site; an evaluation of risks to human health and the environment; and a schedule for
implementation.
6. Upon completion of the activities outlined in the approved Assessment Plan, submit to the
Department an Assessment Report summarizing the findings of the investigations performed
pursuant to the Assessment Plan. The Department shall review the Assessment Report to
4

determine completion of the field investigation and sufficiency of the documentation. If the
Department determines that additional field investigation is necessary, Duke Energy shall
conduct additional field investigation to complete such task. Alternatively, if the
Department determines the field investigation to be complete, but the conclusions in Duke
Energy's Assessment Report are not approved, Duke Energy shall submit a Revision to the
Assessment Report within thirty (30) days after receipt of the Department's disapproval.
The Revision shall address the Department's comments.
7. Within sixty (60) days of approval of the Assessment Report, submit to the Department a
Closure Plan which details the actions to be taken for the final disposition of the Site, and
evaluates the need for additional remediation of soils, surface water and groundwater. If
remedial actions are necessary, Duke Energy shall also submit to the Department for
approval a Remedial Plan, which includes a proposed remedy, justification for the proposed
remedy, the design of the proposed remedy and a schedule for implementation. The
schedule of implementation must extend through full completion of the remedy. The
Closure Plan and, if necessary, the Remedial Plan shall be based upon the results of the field
investigation, ash removal activities and the following seven (7) criteria:
a. Overall protection of human health and the environment;
b. Compliance with applicable or relevant and appropriate standards;
C. Long-term effectiveness and permanence;
d. Reduction of toxicity, mobility or volume;
e. Short-term effectiveness;
f. Implementability;
g. Costs.
8. Any comments generated through the Department's review of the Closure Plan and any
required Remedial Plan must be addressed in writing by Duke Energy within fifteen (15)
days of Duke Energy's receipt of said comments. This fifteen (15) day deadline may be
5

extended by mutual agreement of the parties if the comment resolution. requires extensive
revision, such as re-engineering. Upon Department approval of the Closure Plan, Remedial
Plan and the implementation schedule, the Closure Plan, Remedial Plan, and implementation
schedule shall be incorporated herein and become an enforceable part of this Consent
Agreement.
9. Begin to implement the Closure Plan and the Remedial Plan within forty-five (45) days of
the Department's approval of the Plans; and thereafter, take all necessary and reasonable
steps to ensure timely completion of the Plans.
10. Upon Duke Energy's successful completion of the terms of this Consent Agreement, submit
to the Department a written Final Report. The Final Report shall contain all necessary
documentation supporting Duke Energy's remediation of the Site and successful and
complete compliance with this Consent Agreement. Once the Department has approved the
Final Report, the Department will provide Duke Energy a written approval of completion
that provides a Covenant Not to Sue to Duke Energy for the response actions specifically
covered in this Consent Agreement, approved by the Department and completed in
accordance with the approved work plans and reports.
11. Notwithstanding any other provision of this Consent Agreement, including the Covenant Not
to Sue, the Department reserves the right to require Duke Energy to perform any additional
work at the Site or to reimburse the Department for additional work if Duke Energy declines
to undertake such work, if: (i) conditions at the Site, previously unknown to the Department,
are discovered after completion of the work approved by the Department pursuant to this
Consent Agreement and warrant further assessment or remediation to address a release or
threat of a release in order to protect human health or the environment, or (ii) information is
received, in whole or in part, after completion of the work approved by the Department
pursuant to this Consent Agreement, and these previously unknown conditions or this
6

information indicates that the completed work is not protective of human health and the
environment. In exigent circumstances, the Department reserves the right to perform the
additional work and Duke Energy will reimburse the Department for the work.
12. In consideration for the Department's Covenant Not to Sue, Duke Energy agrees not to
assert any claims or causes of action against the Department arising out of response activities
undertaken at the Site, or to seek any other costs, damages or attorney's fees from the
Department arising out of response activities undertaken at the Site except for those claims
or causes of action resulting from the intentional or grossly negligent acts or omissions of the
Department. However, Duke Energy reserves all available defenses, not inconsistent with
this Consent Agreement, to any claims or causes of action asserted against Duke Energy
arising out of response activities undertaken at the Site by the Department.
13. Submit to the Department a written monthly progress report within thirty (30) days of the
execution of this Consent Agreement and once every month thereafter until completion of
the work required under this Consent Agreement. The progress reports shall include the
following: (a) a description of the actions which Duke Energy has taken toward achieving
compliance with this Consent Agreement during the previous month; (b) results of sampling
and tests, in summary format received by Duke Energy during the reporting period; (c)
description of all actions which are scheduled for the next month to achieve compliance with
this Consent Agreement, and other information relating to the progress of the work as
deemed necessary or requested by the Department; and (d) information regarding the
percentage of work completed and any delays encountered or anticipated that may affect the
approved schedule for implementation of the terms of this Consent Agreement, and a
description of efforts made to mitigate delays or avoid anticipated delays.
14. Prepare all Plans and perform all activities under this Consent Agreement following
appropriate DHEC and EPA guidelines. All Plans and associated reports shall be prepared
7

in accordance with industry standards and endorsed by a Professional Engineer (P.E.) and/or
Professional Geologist (P.G.) duly -licensed in South Carolina. Unless otherwise requested,
one (1) paper copy and one (1) electronic copy (.pdf format) of each document prepared
under this Consent Agreement shall be submitted to the Department's Project Manager.
Unless otherwise directed in writing, all correspondence, work plans and reports should be
submitted to the Department's Project Manager at the following address:
Tim Hornosky
South Carolina Department of Health and Environmental Control
Bureau of Land and Waste Management
2600 Bull Street
Columbia, South Carolina 29201
[e-mail]
15. Reimburse the Department on a quarterly basis, for all past, present and future costs, direct
and indirect, incurred by the Department pursuant to this Consent Agreement and as
provided by law. Oversight Costs include, but are not limited to, the direct and indirect costs
of negotiating the terms of this Consent Agreement, reviewing plans and reports, supervising
corresponding work and activities, and costs associated with public participation. The
Department shall provide documentation of its Oversight Costs in sufficient detail so as to
show the personnel involved, amount of time spent on the project for each person, expenses,
and other specific costs. Payments are due to the Department within thirty (30) days of the
date of the Department's invoice; however, it is not a violation of this Consent Agreement if
late payment is cured within thirty (30) additional days.
16. Notify the Department in writing at least five (5) days before the scheduled deadline
if any event occurs which causes or may cause a delay in meeting any of the above -
scheduled dates for completion of any specified activity pursuant to this Consent Agreement.
Duke Energy shall describe in detail the anticipated length of the delay, the precise cause or
8

causes of delay, if ascertainable, the measures taken or to be taken to prevent or minimize
the delay, and the timetable by which Duke Energy proposes that those measures will be
implemented. The Department shall provide written notice to Duke Energy as soon as
practicable that a specific extension of time, has been granted or that no extension has been
granted. An extension shall be granted for any scheduled activity delayed by an event of
force majeure which shall mean any event arising from causes beyond the control of Duke
Energy that causes a delay in or prevents the performance of any of the conditions under this
Consent Agreement including, but not limited to: a) acts of God, fire, war, insurrection,
civil disturbance, explosion; b) adverse weather conditions that could not be reasonably
anticipated causing unusual delay in transportation and/or field work activities; c) restraint
by court order or order of public authority; d) inability to obtain, after exercise of reasonable
diligence and timely submittal of all required applications, any necessary authorizations,
approvals, permits, or licenses due to action or inaction of any governmental agency or
authority; and e) delays caused by compliance with applicable statutes or regulations
governing contracting, procurement or acquisition procedures, despite the exercise of
reasonable diligence by Duke Energy. Events which are not force majeure include by
example, but are not limited to, unanticipated or increased costs of performance, changed
economic circumstances, normal precipitation events, or failure by Duke Energy to exercise
due diligence in obtaining governmental permits or performing any other requirement of this
Consent Agreement or any procedure necessary to provide performance pursuant to the
provisions of this Consent Agreement. Any extension shall be granted at the sole discretion
of the Department, incorporated by reference as an enforceable part of this Consent
Agreement, and, thereafter, be referred to as an attachment to the Consent Agreement.
17. Employees of the Department, their respective consultants and contractors will not be denied
access during normal business hours or at any time work under this Consent Agreement is
Z

being performed or during any environmental emergency or imminent threat situation, as
determined by the Department or as allowed by applicable law.
IT IS AGREED THAT this Consent Agreement shall be binding upon and inure to the
benefit of Duke Energy and its officers, directors, agents, receivers, trustees, heirs, executors,
administrators, successors, and assigns and to the benefit of the Department and any successor
agency of the State of South Carolina that may have responsibility for and jurisdiction over the
subject matter of this Consent Agreement. Duke Energy may not assign its rights or obligations
under this Consent Agreement without the prior written consent of the Department.
IT IS FURTHER AGREED that failure to meet any deadline or to perform the requirements
of this Consent Agreement without an approved extension of time and failure to timely cure as noted
below, may be deemed a violation of the Pollution Control Act, the South Carolina Hazardous Waste
Management Act and/or the Solid Waste Management and Policy Act, as amended. Upon
ascertaining any such violation, the Department shall notify Duke Energy in writing of any such
deemed violation and that appropriate action may be initiated by the Department in the appropriate
forum to obtain compliance with the provisions of this Consent Agreement and the aforesaid Acts.
Duke Energy shall have thirty (30) days to cure any deemed violations of this Consent Agreement.
Applicable penalties may begin to accrue after issuance of the Department's determination that the
alleged violation has not been cured during that thirty (30) day period.
(Signature Page Follows)
10

FOR THE SOUTH CAROLINA DEPARTMENT
OF HEALTH AND ENVIRONMENTAL CONTROL
Elizabeth -A'. Dieck
Director of Environmental Affairs
lam)rl
Daphne G. Awl, Chief
Bureau of Land and Waste Management
��
//-. Z—
Van Keisler, P.G., Director
Division of Compliance and Enforcement
Reviewed By:
Attorney
Office of General Counsel
WE CONSENT:
DUKE ENERGY CAROLINA, LLC
Date:�1' 1 `�
Date:?/9Ii4-,
Date: 7'; � 1r-,/�
Date:
Date:
qI-Siature)
John Elnitsky, Senior Vice President, Ash Basin Strategy
(Please clearly print name and title)

Attachment C
EPA Merrimack TBEL Determination
(September 23, 2011)

Determination of
Technology -Based
Effluent Limits for
the Flue Gas
Desulfurization
Wastewater at
Merrimack Station
in Bow, New
Hampshire
EPA - Region 1
9/23/2011

Table of Contents
1.0 BACKGROUND...............................................................................................................1
1.1 MERRIMACK STATION'S FGD SYSTEM................................................................................ 1
1.2 WASTEWATER FROM FGD SYSTEMS.................................................................................... 2
1.3 NPDES PERMITTING OF FGD WASTEWATER DISCHARGES ................................................ 3
1.4 NPDES PERMITTING PROCESS FOR FGD WASTEWATER DISCHARGES AT MERRIMACK
STATION.............................................................................................................................. 4,
2.0 LEGAL REQUIREMENTS AND CONTEXT..............................................................5
2.1 SETTING EFFLUENT DISCHARGE LIMITS............................................................................. 5
2.2 TECHNOLOGY-BASED DISCHARGE LIMITS.......................................................................... 6
2.3 SETTING TECHNOLOGY-BASED LIMITS ON A BPJ BASIS ..................................................... 7
2.4 THE BAT STANDARD........................................................................................................... 8
2.5 THE BCT STANDARD......................................................................................................... 13
3.0 TECHNOLOGICAL ALTERNATIVES EVALUATED............................................14
3.1
DISCHARGE TO A POTW....................................................................................................
14
3.2
EVAPORATION PONDS........................................................................................................
15
3.3
FLUE GAS INJECTION........................................................................................................
15
3.4
FIXATION...........................................................................................................................16
39
3.5
DEEP WELL INJECTION.....................................................................................................
16
3.6
FGD WWTS EFFLUENT REUSE/RECYCLE........................................................................
18
3.7
SETTLING PONDS..............................................................................................................
18
3.8
TREATMENT BY THE EXISTING WWTS..............................................................................
19
3.9
VAPOR -COMPRESSION EVAPORATION...............................................................................
20
3.10
PHYSICAUCHEMICAL TREATMENT....................................................................................
22
3.11
PHYSICAUCHEMICAL WITH ADDED BIOLOGICAL TREATMENT ..........................................
23
4.0 BAT FOR FGD WASTEWATER AT MERRIMACK STATION ............................. 27
5.0 BPJ-BASED BAT EFFLUENT LIMITS....................................................................30
5.1 INTRODUCTION..................................................................................................................
30
5.2 COMPLIANCE LOCATION....................................................................................................
34
5.3 POLLUTANTS OF CONCERN IN FGD WASTEWATER...........................................................
35
5.4 THE BAT FOR CONTROLLING MERRIMACK STATION'S FGD WASTEWATER .....................
37
5.5 EFFLUENT LIMITS...........................................................................:.................................
39
5.5.1 Arsenic....................................................................................................................
39
5.5.2 BOD........................................................................................................................
39
5.5.3 Boron.......................................................................................................................40
5.5.4 Cadmium................................................................................................................41
5.5.5 Chlorides.................................................................................................................41
5.5.6 Chromium...............................................................................................................42
5.5.7 Copper.....................................................................................................................42
5.5.8 Iron..........................................................................................................................
42
5.5.9 Lead........................................................................................................................
43
5.5.10 Manganese......................:.......................................................................................44
5.5.11 Mercury...................................................................................................................44
5.5.12 Nitrogen..................................................................................................................44
5.5.13 pH..........................................................................................................................46
5.5.14 Phosphorus.............................................................................................................46
5.5.15 Selenium................................................................................................................
47
5.5.16 Total Dissolved Solids...........................................................................................
47
5.5.17 Zinc.........................................................................................................................
47
5.6 SUMMARY OF EFFLUENT LIMITS.......................................................................................
48
5.7 SUFFICIENTLY SENSITIVE ANALYTICAL METHODS...........................................................
49

Determination of Technology -Based Effluent Limits for the Flue Gas
Desulfurization Wastewater at Merrimack Station in Bow, New Hampshire
The analysis presented in this document was developed by the Environmental
Protection Agency (EPA) — Region 1 in support of the reissuance of a National
Pollutant Discharge Elimination Systems (NPDES) _permit for Merrimack Station
(Permit No. NH0001465). EPA is the permitting authority in this case, since the
NPDES program has not been delegated to the state of New Hampshire.
1.0 Background
1.1 Merrimack Station's FGD System
Merrimack Station, owned and operated by Public Service of New Hampshire
(referred to hereafter as PSNH or the Permittee), consists of two coal fired,
steam electric, generating units. The coal combustion process generates a variety
of air pollutants that are emitted from the facility's smoke stacks. Currently, the
flue gas from each of these two units passes through air pollution control
equipment that includes selective catalytic reduction systems to reduce
nitrogen oxides emissions and two electrostatic precipitators to reduce
particulate matter emissions.
In 2006, the New Hampshire legislature enacted RSA 125-0:11-18, which
requires PSNH to install and operate a wet flue gas desulfurization (FGD)
system at Merrimack Station to reduce air emissions of mercury and other
pollutants.' RSA 125-0:11(1), (11) and (III); RSA 125-0:120; RSA 125-0:13(1)
and (II). The state law calls for the facility to, among other things, reduce
mercury emissions by at least 80 percent. RSA 125-0:11(1) and (III); 125-
0:13(1) and (II). But see also RSA 125-0:130, (VII) and (VIII); RSA 125-
0:17(11) (variances).
PSNH is required to have the FGD system fully operational by July 1, 2013,
"contingent upon obtaining all necessary permits and approvals from federal, state,
and local regulatory agencies and bodies." RSA 125-0:13(1) (emphasis added). But
see also RSA 125-0:17(1) (variances). With regard to such permits and approvals,
the statute requires PSNH to "make appropriate initial filings with the [New
Hampshire] department [of environmental services] ... within one year of the
effective date of this section, and with any other applicable regulatory agency or
body in a timely manner." RSA 125-0:13(1). The legislation also expresses the
state's desire to realize the air quality benefits of an FGD system at Merrimack
Station sooner than the July 2013 date to the extent practicable, and it creates
incentives to encourage Merrimack Station to better that date. RSA 125-0:11(IV);
RSA 125-0:13(111); RSA 125-0:16.
The New Hampshire statute expressly requires PSNH to install a "wet" FGD
1 Title X Public Health Chapter 125-0 Multiple Pollutant Reduction Program, sections 125-
0:11 through 18. See httn://www.gencourt.state.nh.us/rsa/html/x/125-o/125-o-mrg.htm
1 of 52 .

Determination of Technology -Based Effluent Limits for the Flue Gas
Desulfurization Wastewater at Merrimack Station in Bow, New Hampshire
system at Merrimack Station. According to the statute, the New Hampshire
Department of Environmental Services (NHDES) "determined that the best known
commercially available technology [for reducing the facility's air emissions] is a wet
Rue gas desulphurization (sic) system, hereafter `scrubber technology,' as it best
balances the procurement, installation, operation, and plant efficiency costs with
the projected reductions in mercury and other pollutants from the flue gas
streams of Merrimack Units 1 and 2." RSA 125-O:11(II).
While wet FGD scrubbers are one of the available means of reducing air
pollutant emissions from coal -burning power plants like Merrimack Station, the
contaminants removed from the flue gas become part of a wastewater stream
from the scrubbers. "In wet FGD scrubbers, the flue gas stream comes in
contact with a liquid stream containing a sorbent, which is used to effect the
mass transfer of pollutants from the flue gas to the liquid stream." EPA, Steam
Electric Power Generating Point Source Category: Detailed Study Report, EPA 821-
R-09-008, October 2009, p. 3-16 (hereinafter "EPA's 2009 Detailed Study Report").
In other words, the wet FGD system generates a wastewater purge stream
containing the pollutants removed from the flue gas, thus, exchanging air
pollution for water pollution.
PSNH is installing a limestone forced oxidation scrubber system and intends to
produce a saleable gypsum byproduct (e.g., wallboard). While this will reduce
the quantity of solid waste requiring disposal, the gypsum cake typically must
be rinsed to reduce the level of chlorides in the final product. This generates
additional wastewater requiring treatment prior to reuse or discharge.
1.2 Wastewater from FGD Systems
Coal combustion generates a host of air pollutants which enter the flue gas stream
and are emitted to the air unless an air emissions control system is put in place.
The wet FGD scrubber system works by contacting the flue gas stream with a liquid
slurry stream containing a sorbent (typically lime or limestone). The contact
between the streams allows for a mass transfer of contaminants from the flue gas
stream to the slurry stream.
Coal combustion generates acidic gases, such as sulfate, which become part of the
flue gas stream. Not only will the liquid slurry absorb sulfur dioxide and other
sulfur compounds from the flue gas, but it will also absorb other contaminants from
the flue gas, including particulates, chlorides, volatile metals - including arsenic (a
metalloid), mercury, selenium, boron, cadmium, and zinc — total dissolved solids
(TDS), nitrogen compounds and organics. Furthermore, the liquid slurry will also
readily absorb hydrochloric acid, which is formed as a result of chlorides in the coal.
The limestone in the slurry also contributes iron and aluminum (from clay
minerals) to the FGD wastewater. The chloride concentration and clay inert fines of
2 of 52

Determination of Technology -Based Effluent Limits for the Flue Gas
Desulfurization Wastewater at Merrimack Station in Bow, New Hampshire
the FGD slurry must be controlled through a routine wastewater purge to minimize
corrosion of the absorber vessel materials. Depending upon the pollutant, the type
of solids separation process and the solids dewatering process used, the pollutants
may partition to either the solid phase (i.e., FGD solids) or the aqueous phase.
Many of the pollutants found in FGD wastewater can cause serious environmental
harm and present potential human health risks. These pollutants can occur in
quantities (i.e., total mass released) and/or concentrations that cause or contribute
to in -stream excursions of EPA -recommended water quality criteria for the
protection of aquatic life and/or human health. In addition, some pollutants in the
FGD wastewater present a particular ecological threat due to their tendency to
persist in the environment and bioaccumulate in organisms. For example, arsenic,
mercury and selenium readily bioaccumulate in exposed biota.
1.3 NPDES Permitting of FGD Wastewater Discharges
Polluted wastewater from FGD scrubber systems cannot be discharged to
waters of the United States, such as the Merrimack River, unless in compliance
with the requirements of the federal Clean Water Act, 33 U.S.C. §§ 1251 et seq.
(CWA), and applicable state laws. More specifically, any such discharges must
comply with the requirements of a NPDES permit.
As will be discussed in detail below, discharges of wastewater from a FGD scrubber
system to a water of the United States must satisfy federal technology-based
treatment requirements as well as any more stringent state water quality -based
requirements that may apply. While EPA has promulgated National Effluent
Limitation Guidelines (NELGs) which set technology-based limits for the discharge
of certain pollutants by facilities in the Steam Electric Power Generating Point
Source Category, see 40 C.F.R. Part 423, these NELGs do not yet include best
available technology (BAT) limits for wastewater from FGD systems. In the
absence of national standards for FGD wastewater, technology-based limits are
developed by EPA (or state permitting authorities administering the NPDES permit
program) on a Best Professional Judgment (BPJ), case-by-case basis. See generally
40 C.F.R. § 125.3.
During October 2009, EPA completed a national study of wastewater discharges
from the steam electric power generating industry. See EPA's 2009 Detailed
Study Report. Based on this study, among other things, EPA decided to work
toward developing NELGs to address a variety of wastewater streams and
pollutants discharged by this industry but not yet addressed by the existing
NELGs. The wastewater from wet FGD scrubbers was identified as one of the
waste streams to be addressed by the new standards. EPA has indicated that it
currently expects to complete the rulemaking process and promulgate revised
NELGs by early 2014.
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Determination of Technology -Based Effluent Limits for the Flue Gas
Desulfurization Wastewater at Merrimack Station in Bow, New Hampshire
In a letter dated June 7, 2010, EPA's Office of Wastewater Management
provided EPA and state permitting authorities information about establishing
technology-based NPDES permit limits for discharges from FGD wastewater
treatment systems (WWTSs) at steam electric power plants between now and
the effective date of the revised NELGs. This letter underscores the CWA's
requirement that until NELG's for FGD WWTS discharges become effective,
technology-based effluent limits for such discharges will continue to be based
on BPJ.
1.4 NPDES Permitting Process for FGD Wastewater Discharges at
Merrimack Station
In response to the 2006 state legislation requiring use of a wet FGD scrubber
system at Merrimack Station, PSNH contracted with Siemens Water
Technologies (Siemens) to design and construct a WWTS for the FGD
wastewater. The company received additional engineering/design support from
URS Corporation. PSNH's plan ultimately called for the treated wastewater to
be discharged to the Merrimack River.
In 2009, PSNH began work on an antidegradation analysis, under the direction
of NHDES, to determine whether the new discharges would satisfy state water
quality standards. See Merrimack Station Fact Sheet, section 5.6.3.1 and NHDES
draft antidegradation review document. Based on the requirements of Env-Wq
1708, NHDES required PSNH to perform sampling and analysis of a number of
pollutants of concern. These analyses led to the development of certain water
quality -based effluent limits, as discussed in greater detail in the Fact Sheet. Id.
It was not until May 5, 2010, that PSNH submitted to EPA an addendum to its
previously filed NPDES permit application for Merrimack Station in order to
identify the company's plan for discharging treated FGD effluent to the Merrimack
River. New pollutant discharges to waters of the United States, such as PSNH's
proposed discharges of FGD wastewater to the Merrimack River, are prohibited
unless and until authorized by a new NPDES permit. Therefore, in response to
PSNH's new plan, EPA must determine both the technology-based and,
coordinating with NHDES, the water quality -based effluent limits that would apply
to the new discharge.
Unfortunately, the permit application addendum submitted by PSNH did not
provide all the information necessary to enable EPA to determine the applicable
technology-based and water quality -based requirements for the FGD wastewater.
Therefore, EPA began coordinating with NHDES on the water quality standards
analysis. Furthermore, EPA informally suggested to PSNH that it might wish to
submit its own evaluation of whether its proposed discharge would satisfy
4 of 52

Determination of Technology -Based Effluent Limits for the Flue Gas
Desulfurization Wastewater at Merrimack Station in Bow, New Hampshire
applicable technology-based requirements. In response, PSNH submitted a
document dated October 8, 2010, and entitled, "Public Service of New Hampshire,
Merrimack Station, Bow, New Hampshire, Response to Informal EPA Request for
Supplemental Information about Planned State -of -the -Art Flue Gas Desulfurization
("FGD") Wastewater Treatment System" (hereinafter "PSNH's October 2010
Report"). In response to this submission, EPA sent PSNH a letter with a number of
follow-up questions. The company responded with a letter dated December 3, 2010,
with the heading, "Public Service of New Hampshire, Merrimack Station, Bow, New
Hampshire, NPDES Permit No. NH0001465 Response to Information Request
about Planned State -of -the -Art Flue Gas Desulfurization Wastewater Treatment
System" (hereinafter "PSNH's December 2010 Report").
The information submitted (thus far) indicates that PSNH, at the recommendation
of Siemens, has selected a physical/chemical treatment system for the FGD purge
stream. Generally, a physical/chemical WWTS consists of chemical precipitation,
coagulation/flocculation, clarification, filtration and sludge dewatering. The new
WWTS at Merrimack Station will be supplemented with proprietary adsorbent
media (or "p"olishing step") for further removal of mercury from the effluent. As of
September 2011, construction of the FGD system and its WWTS is almost
complete. PSNH is currently performing pre -operational testing of the various
components of the FGD system.
PSNH designed, financed and, for the most part, constructed the Merrimack
Station FGD WWTS system without first discussing with EPA whether this
WWTS would satisfy technology-based and water quality -based standards. To
be sure, PSNH was not required by regulation either to consult with EPA or to
gain EPA approval before constructing a WWTS for the FGD scrubber system
at Merrimack Station. By the same token, however, EPA is not required to
determine that the new WWTS satisfies the applicable CWA requirements
because PSNH has already built it. Rather, EPA must set discharge limits
based on the applicable requirements of federal and state law and Merrimack
Station will have to meet them. EPA's determination of the appropriate effluent
limitations for the FGD wastewater is set forth below.
2.0 Legal Requirements and Context
2.1 Setting Effluent Discharge Limits
As the United States Supreme Court has explained:
[t]he Federal Water Pollution Control Act, commonly known as the
Clean Water Act, 86 Stat. 816, as amended, 33 U.S.C. § 1251 et seq., is
a comprehensive water quality statute designed to "restore and
maintain the chemical, physical, and biological integrity of the
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Nation's waters." § 1251(a). The Act also seeks to attain "water quality
which provides for the protection and propagation of fish, shellfish, and
wildlife." § 1251(a)(2).
PUD No. 1 of Jefferson County v. Washington Dept. of Ecology, 511 U.S. 700, 704
(1994). The CWA should be construed and interpreted with these overarching
statutory purposes in mind. To accomplish these purposes, the CWA prohibits point
source discharges of pollutants to waters of the United States unless authorized by
a NPDES permit (or a specific provision of the statute). The NPDES permit is the
mechanism used to implement NELGs, state water quality standards, and
monitoring and reporting requirements on a facility -specific basis. When
developing pollutant discharge limits for a NPDES permit, the CWA directs permit
writers to impose limits based on (a) specified levels of pollution reduction
technology (technology-based limits), and (b) any more stringent requirements
needed to satisfy state water quality standards (water quality -based limits).
2.2 Technology -Based Discharge Limits
The CWA requires all discharges of pollutants to meet, at a minimum, applicable
technology-based requirements. The statute creates several different narrative
technology standards, each of which applies to a different type of pollutant or class
of facility. EPA develops NELGs based on the application of these technology -
standards to entire industrial categories or sub -categories.
Although technology-based effluent limitations are based on the pollution reduction
capabilities of particular wastewater treatment technologies or operational
practices, the CWA does not dictate that the dischargers subject to the limitations
must use the particular technologies or practices identified by EPA. Rather,
dischargers are permitted to use any lawful means of meeting the limits. In this
way, the CWA allows facilities to develop different, and potentially innovative,
approaches to satisfying applicable technology-based requirements.2
As befits the "technology -forcing" scheme of the CWA, Congress provided for the
statute's technology-based requirements to become increasingly stringent over time.
Of relevance here, industrial dischargers were required by March 31, 1989, to
comply with effluent limits for toxic and non -conventional pollutants that reflect the
best available technology economically achievable (`BAT").3 See 33 U.S.C. §§
2 Water quality -based requirements are not based on particular technologies or practices.
Thus, they also leave room for different approaches to complying with permit limits.
3 In addition, CWA § 301(b)(1)(A) requires industrial dischargers, by July 1, 1977, to have
satisfied limits based on the application of the best practicable control technology currently available
(BPT). See 33 U.S.C. §1311(b)(1)(A). See also 40 C.F.R. § 125.3(a)(2)(i). Furthermore, CWA § 306,
33 U.S.C. § 1316, requires new sources to meet performance standards based on the best available
demonstrated control technology (BADT).
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1311(b)(2)(A) and (F); 40 C.F.R. § 125.3(a)(2)(iii) — (v). Of further relevance,
industrial dischargers are also required by the same date to meet limits for
conventional pollutants based on the best conventional pollutant control technology
("BCT"). See 33 U.S.C. §1311 (b)(2)(E); 40 C.F.R. § 125.3(a)(2)(ii). The BAT and
BCT standards are discussed in more detail below.
2.3 Setting Technology -Based Limits on a BPJ Basis
As mentioned above, EPA has developed NELGs for certain pollutants discharged
by facilities within the steam -electric power generating point source category — an
industrial category that includes Merrimack Station — but has not promulgated
BAT or BCT NELGs for FGD scrubber system wastewater. See 40 C.F.R. Part 423.
As a result, EPA (or a state permitting authority, as appropriate) must develop
technology-based limits for Merrimack Station's FGD wastewater on a case-by-case,
BPJ basis pursuant to CWA § 402(a)(1)(B), 33 U.S.C. § 1342(a)(1)(B), and 40 C.F.R.
§ 125.3(c)(2) and (3).
When developing technology-based limits using BPJ under CWA § 402(a)(1), the
permit writer considers a number of factors that are spelled out in the statute and
regulations. The BAT factors are set forth in CWA § 304(b)(2)(B) and 40 C.F.R. §
125.3(d)(3), while the BCT factors are set forth in CWA § 304(b)(4)(B) and 40 C.F.R.
§ 125.3(d)(2). The regulations reiterate the statutory factors, see 40 C.F.R. §
125.3(d),, and also specify that permit writers must consider the "appropriate
technology for the category of point sources of which the applicant is a member,
based on all available information," as well as "any unique factors relating to the
applicant." 40 C.F.R. § 125.3(c)(2).
As one court has explained, BPJ limits represent case -specific determinations of the
appropriate technology-based limits for a particular point source. Natural
Resources Defense Council v. U.S. Envtl. Prot. Agency, 859 F.2d 156, 199 (D.C. Cir.
1988). The court expounded as follows:
[i]n what EPA characterizes as a "mini -guideline" process, the permit
writer, after full consideration of the factors set forth in section 304(b),
33 U.S.C. § 1314(b), (which are the same factors used in establishing
effluent guidelines), establishes the permit conditions "necessary to
carry out the provisions of [the CWA]." § 1342(a)(1). These conditions
include the appropriate ... [technology-based] effluent limitations for
the particular point source.... [T]he resultant BPJ limitations are as
correct and as statutorily supported as permit limits based upon an
effluent limitations guideline.
Id. See also Texas Oil & Gas Assn v. U.S. Envtl. Prot. Agency, 161 F.3d 923, 929
(5th Cir. 1998) ("Individual judgments thus take the place of uniform national
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guidelines, but the technology-based standard remains the same"). EPA's "Permit
Writers' Manual" instructs permit writers that they can derive BPJ-based limits
after considering a variety of sources (e.g., other NPDES permits; effluent
guidelines development and planning information). See Permit Writers'Manual at
section 5.2.3.3 (September 2010).
2.4 The BAT Standard
The BAT standard is set forth in CWA § 301(b)(2)(A), 33 U.S.C. § 1311(b)(2)(A), and
applies to many of the pollutants in Merrimack Station's FGD wastewater, which
include both toxics (e.g., mercury, arsenic, selenium) and non -conventional
pollutants (e.g., nitrogen). See 33 U.S.C. § 1311(b)(2)(A) & (F); 40 C.F.R. §§
125.3(a)(2)(iii) — (v). See also 33 U.S.C. § 1314(b)(2). The BAT standard requires
achievement of:
effluent limitations ... which ... shall require application of the best
available technology economically achievable ..., which will result in
reasonable further progress toward the national goal of eliminating the
discharge of all pollutants, as determined in accordance with
regulations issued by the [EPA] Administrator pursuant to section
1314(b)(2) of this title, which such effluent limitations shall require the
elimination of discharges of all pollutants if the Administrator finds,
on the basis of information available to him ... that such elimination
is technologically and economically achievable ... as determined in
accordance with regulations issued by the [EPA] Administrator
pursuant to section 1314(b)(2) of this title ....
33 U.S.C. § 1311(b)(2)(A) (emphasis added). In other words, EPA must set effluent.
discharge limits corresponding to the use of the best pollution control technologies
that are technologically and economically achievable and will result in reasonable
progress toward eliminating discharges of the pollutant(s) in question. In a given
case, this might or might not result in limits prohibiting the discharge of certain
pollutants.
According to the CWA's legislative history, the starting point for identifying the
"best available technology" refers to the "single best performing plant in an
industrial field" in terms of its capacity to reduce pollutant discharges. Chemical
Manufacturers. Assn v. U.S. Envtl. Prot. Agency, 870 F.2d 177, 239 (5th Cir. 1989)
(citing Congressional Research Service, A Legislative History of the Water Pollution
Control Act Amendments of 1972 at 170 (1973) (hereinafter "1972 Legislative
History") at 170).4 Thus, EPA need not set BAT limits at levels that are being met
4 See also Texas Oil, 161 F.3d at 928, quoting Chemical Manufacturers., 870 F.2d at 226;
Kennecott v. U.S. Envtl. Prot. Agency, 780 F.2d 445, 448 (4th Cir. 1985) ("In setting BAT, EPA uses
not the average plant, but the optimally operating plant, the pilot plant which acts as a beacon to
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by most or all the dischargers in a particular point source category, as long as at
least one demonstrates that the limits are achievable. Id. at 239, 240. This
comports with Congressional intent that EPA "use the latest scientific research and
technology in setting effluent limits, pushing industries toward the goal of zero
discharge as quickly as possible." Kennecott, 780 F.2d 445, 448 (4th Cir. 1984),
citing 1972 Legislative History at 798. See also Natural Resources Defense Council,
863 F.2d at 1431 ("The BAT standard must establish effluent limitations that
utilize the latest technology."). While EPA must consider the degree of pollutant
reduction achieved by the available technological alternatives, the Agency is not
required to consider the extent of water quality improvement that will result from
such reduction.5
Available technologies may also include viable "transfer technologies" — that is, a
technology from another industry that could be transferred to the industry in
question — as well as technologies that have been shown to be viable in research
even if not yet implemented at a full-scale facility.6 When EPA bases BAT limits on
such "model" technologies, it is not required to "consider the temporal availability of
the model technology to individual plants," because the BAT factors do not include
consideration of an individual plant's lead time for obtaining and installing a
technology. See Chemical Manufacturers, 870 F.2d at 243; American Meat Inst. V.
U.S. Envtl. Prot. Agency, 526 F.2d 442, 451 (7th Cir. 1975).
show what is possible."); American Meat, 526 F.2d at 463 (BAT "should, at a minimum, be
established with reference to the best performer in any industrial category"). According to one court:
[t]he legislative history of the 1983 regulations indicates that regulations
establishing BATEA [i.e., best available technology economically achievable, or BAT] can be
based on statistics from a single plant. The House Report states:
It will be sufficient for the purposes of setting the level of control under
available technology, that there be one operating facility which demonstrates that
the level can be achieved or that there is sufficient information and data from a
relevant pilot plant or semi -works plant to provide the needed economic and
technical justification for such new source.
Ass'n of Pacific Fisheries v. U.S. Envtl. Prot. Agency, 615 F.2d 794, 816-17 (9th Cir. 1980) (quoting
1972 Legislative History at 170).
a See, e.g., American Petroleum, 858 F.2d at 265-66 ("Because the basic requirement for BAT
effluent limitations is only that they be technologically and economically achievable, the impact of a
particular discharge upon the receiving water is not an issue to be considered in setting technology-
based limitations.").
6 These determinations, arising out of the CWA's legislative history, have repeatedly been
upheld by the courts. E.g., American Petroleum Inst. v. U.S. Envtl. Prot. Agency, 858 F.2d 261, 264-
65 (5th Cir. 1988); Pacific Fisheries, 615 F.2d at 816-17; BASF Wyandotte Corp. v. Costle, 614 F.2d
21, 22 (1st Cir. 1980); American Iron, 526 F.2d at 1061; American Meat, 526 F.2d at 462.
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While EPA must articulate the reasons for its determination that the technology it
has identified as BAT is technologically achievable, courts have construed the CWA
not to require EPA to identify the precise technology or technologies a plant must
install to meet BAT limits. See Chemical Manufacturers., 870 F.2d at 241. The
Agency must, however, demonstrate at least that the technology used to estimate
BAT limits and costs is a "reasonable approximation of the type and cost of
technology that must be used to meet the limitations." Id. It may do this by several
methods, including by relying on a study that demonstrates the effectiveness of the
required technology. BP Exploration & Oil, Inc. v. U.S. Envtl. Prot. Agency, 66 F.3d
784, 794 (6th Cir. 1995) (upholding BAT limits because EPA relied on "empirical
data" presented in studies demonstrating that improved gas flotation is effective for
removing dissolved as well as dispersed oil from produced water). See also Assn of
Pacific Fisheries v. U.S. Envtl. Prot. Agency, 615 F.2d 794, 819 (9th Cir. 1980)
(regulations remanded because the BAT limit was based on a study that did not
demonstrate the effectiveness of the technology selected as BAT).
Beyond looking at the best performing pollution reduction technologies, the statute
also specifies the following factors that EPA must "take into account" in
determining the BAT:
... the age of equipment and facilities involved, the process employed,
the engineering aspects of the application of various types of control
techniques, process changes, the cost of achieving such effluent
reduction, non -water quality environmental impact (including energy
requirements), and such other factors as the Administrator deems
appropriate.
33 U.S.C. § 1314(b)(2)(B). See also 40 C.F.R. § 125.3(d)(3). As elucidated by the
case law, the statute sets up a loose framework for EPA's taking account of these
factors in setting BAT limits. As one court explained:
[i]n enacting the CWA, `Congress did not mandate any particular structure or
weight for the many consideration factors. Rather, it left EPA with discretion
to decide how to account for the consideration factors, and how much weight
to give each factor.'
BP Exploration, 66 F.3d at 796, citing Weyerhauser v. Costle, 590 F.2d 1011, 1045
(D.C. Cir. 1978) (citing Senator Muskie's remarks about CWA § 304(b)(1) during
debate). Comparison between the factors is not required, merely their
consideration. Weyerhauser, 590 F.2d at 1045 (explaining that CWA § 304(b)(2)
lists factors for EPA "consideration" in setting BAT limits, in contrast to §
304(b)(1)'s requirement that EPA compare "total cost versus effluent reduction
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benefits" in setting BPT limits).?
Ultimately, when setting BAT limits, EPA is governed by a standard of
reasonableness in its consideration of the required factors. BP Exploration, 66 F.3d
at 796, citing American Iron & Steel Inst. v. Envtl. Prot. Agency, 526 F.2d 1027,
1051 (3d Cir. 1975), modified in other part, 560 F.2d 589 (3d Cir. 1977), cert. denied,
435 U.S. 914 (1978). Each factor must be considered, but the Agency has
"considerable discretion in evaluating the relevant factors and determining the
weight to be accorded to each in reaching its ultimate BAT determination." Texas
Oil, 161 F.3d at 928, citing Natural Resources Defense Council, 863 F.2d at 1426.
See also Weyerhauser, 590 F.2d at 1045 (stating that in assessing BAT factors, "[s]o
long as EPA pays some attention to the congressionally specified factors, [CWA §
304(b)(2),] on its face lets EPA relate the various factors as it deems necessary").
One court succinctly summarized the standard for reviewing EPA's consideration of
the BAT factors in setting limits as follows: "[s]o long as the required technology
reduces the discharge of pollutants, our inquiry will be limited to whether the
Agency considered the cost of technology, along with other statutory factors, and
whether its conclusion is reasonable." Pacific Fisheries, 615 F.2d at 818. See also
Chemical Manufacturers, 870 F.2d at 250 n. 320 (citing 1972 Legislative History (in
determining BAT, "'[t]he Administrator will be bound by a test of
reasonableness."')).
The BAT Factors
As detailed above, the CWA requires EPA to consider a number of factors in
developing BAT limits. Certain of these factors relate to technological concerns
related to the industry and treatment technology in question. For example, EPA
takes into account (1) the engineering aspects of the application of various types of
control techniques, (2) the process or processes employed by the point source
category (or individual discharger) for which the BAT limits are being developed, (3)
process changes that might be necessitated by using new technology, and (4) the
extent to which the age of equipment and facilities involved might affect the
introduction of new technology, its cost and its performance.
EPA also considers the cost of implementing a treatment technology when
determining BAT. CWA §§ 301(b)(2) and 304(b)(2) require "EPA to set discharge
limits reflecting the amount of pollutant that would be discharged by a point source
employing the best available technology that the EPA determines to be economically
feasible...." Texas Oil, 161 F.3d at 928 (emphasis added). See also 33 U.S.C. §§
1311(b)(2) and 1314(b)(2) (when determining BAT, EPA must consider the "cost of
7 See also U.S. Envtl. Prot. Agency v. Nat'l Crushed Stone Assn, 449 U.S. 64, 74 (1980)
(noting that "[s]imilar directions [as those for setting BPT limits] are given the Administrator for
determining effluent reductions attainable from the BAT except that in assessing BAT total cost is
no longer to be considered in comparison to effluent reduction benefits").
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achieving such effluent reduction"); 40 C.F.R. § 125.3(d)(3) (same). The United
States Supreme Court has stated that treatment technology that satisfies the
CWA's BAT standard must "represent `a commitment of the maximum resources
economically possible to the ultimate goal of eliminating all polluting discharges."
EPA v. Nat'l Crushed Stone Assn, 449 U.S. 64, 74 (1980). See also BP Exploration,
66 F.3d at 790 ("BAT represents, at a minimum, the best economically achievable
performance in the industrial category or subcategory."), citing NRDC v. EPA, 863
F.2d 1420, 1426 (9th Cir. 1988).
The Act gives EPA "considerable discretion" in determining what is economically
achievable. Natural Resources Defense Council, 863 F.2d at 1426, citing American
Iron, 526 F.2d at 1052. It does not require a precise calculation of the costs of
complying with BAT limits.$ EPA "need make only a reasonable cost estimate in
setting BAT," meaning that it must "develop no more than a rough idea of the costs
the industry would incur." Id. See also Rybachek v. U.S. Envtl. Prot. Agency, 904
F.2d 1276, 1290-91 (9th Cir. 1990); Chemical Manufacturers., 870 F.2d at 237-38.
Moreover, CWA § 301(b)(2) does not specify any particular method of evaluating the
cost of compliance with BAT limits or state how those costs should be considered in
relation to the other BAT factors; it only directs EPA to consider whether the costs
associated with pollutant discharge reduction are "economically achievable."
Chemical Manufacturers., 870 F.2d at 250, citing 33 U.S.C. § 1311(b)(2)(A).
Similarly, CWA § 304(b)(2)(B) requires only that EPA "take into account" cost along
with the other BAT factors. See Pacific Fisheries, 615 F.2d at 818 (in setting BAT
limits, "the EPA must `take into account ... the cost of achieving such effluent
reduction,' along with various other factors"), citing CWA § 304(b)(2)(B).
In the context of considering cost, EPA may also consider the' relative "cost-
effectiveness" of the available technology options. The term "cost-effectiveness" is
used in multiple ways. From one perspective, the most cost-effective option is the
least expensive way of getting to the same (or nearly the same) performance goal.
From another perspective, cost-effectiveness refers to a comparative assessment of
the cost per unit of performance by different options. In its discretion, EPA might
decide that either or both of these approaches to cost-effectiveness analysis would
be useful in determining the BAT in a particular case. Alternatively, EPA might
reasonably decide that neither was useful. For example, the former approach would
not be helpful in a case in which only one technology even comes close to reaching a
particular performance goal. Moreover, the latter approach would not be helpful
where a meaningful cost -per -unit -of -performance metric cannot be developed, or
B In BP Exploration, the court stated that, "[a]ccording to EPA, the CWA not only gives the
agency broad discretion in determining BAT, the Act merely requires the agency to consider whether
the cost of the technology is reasonable. EPA is correct that the CWA does not require a precise
calculation of BAT costs." 66 F.3d at 803, citing Natural Resources Defense Council, 863 F.2d at
1426.
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where there are wide disparities in the performance of alternative technologies and
those with lower costs -per -unit -of -performance fail to reach some threshold of
necessary performance. The courts, including the United States Supreme Court,
have consistently read the statute and its legislative history to indicate that while
Congress intended EPA to consider cost in setting BAT limits, it did not require the
Agency to perform some type of cost -benefit balancing.9
Finally, in determining the BAT, EPA also considers the non -water quality
environmental effects (and energy effects) of using the technologies in question. See
33 U.S.C. § 1314(b)(2)(B); 40 C.F.R. § 125.3(d)(3). Again, the CWA gives EPA broad
discretion in deciding how to evaluate these non -water quality effects and weigh
them against the other BAT factors. Rybachek, 904 F.2d at 1297, citing
Weyerhauser, 590 F.2d at 1049-53. In addition, the statute authorizes EPA to
consider any other factors that it deems appropriate. 33 U.S.C. § 1314(b)(2)(B).
2.5 The BCT Standard
Discharges of conventional pollutants by existing sources are subject to effluent
limitations based on the "best conventional pollutant control technology" (BCT). 33
U.S.C. §§ 1311(b)(2)(E) and 1314(b)(4)(A); 40 C.F.R. § 125.3(a)(2)(ii). See also 33
U.S.C. § 1314(a)(4) and 40 C.F.R. § 401.16 (conventional pollutants include
biochemical oxygen demand (BOD), total suspended solids (TSS) (nonfilterable), pH,
fecal coliform and oil and grease). BCT is the next step above BPT for conventional
pollutants. As a result, effluent limitations based on BCT may not be less stringent
than limitations based on BPT would be. In other words, BPT effluent limitation
guidelines set the "floor" for BCT effluent limitations.
EPA is discussing the BCT standard here because of the possibility that Merrimack
Station's FGD wastewater could include elevated BOD levels and non -neutral pH.
These are conventional pollutants subject to the BCT standard. As explained above,
any BCT limits for these pollutants would need to be determined based on a BPJ
basis because EPA has not promulgated BCT NELGs for FGD wastewater. The
factors to be considered in setting BCT limits are specified in the Clean Water Act
and EPA regulations. See 33 U.S.C. § 1314(b)(4)(B); 40 C.F.R. § 125.3(d)(2).
9 E.g., Nat'l Crushed Stone, 449 U.S. at 71 ("Similar directions [to those for assessing BPT
under CWA § 304(b)(1)(B)] are given the Administrator for determining effluent reductions
attainable from the BAT except that in assessing BAT total cost is no longer to be considered in
comparison to effluent reduction benefits.") (footnote omitted); Texas Oil, 161 F.3d at 936 n.9
(petitioners asked court "to reverse years of precedent and to hold that the clear language of the
CWA (specifically, 33 U.S.C. § 1314(b)(2)(B)) requires the EPA to perform a cost -benefit analysis in
determining BAT. We find nothing in the language or history of the CWA that compels such a
result"); Reynolds Metals, 760 F.2d at 565. Reynolds Metals Co. v. U.S. Environmental Protection
Agency, 760 F.2d 549, 565 (4th Cir. 1985) (in setting BAT limits, "no balancing is required — only
that costs be considered along with the other factors discussed previously"), citing Nat'l Assn Metal
Finishers v. U.S. Environmental Protection Agency, 719 F.2d 624, 662-63 (3rd Cir. 1983).
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EPA has determined, however, that based on current facts, developing BCT limits
for Merrimack Station's Draft Permit would be inappropriate at this time. This
decision is discussed further in section 3.5.
3.0 Technological Alternatives Evaluated
PSNH's October 2010 and December 2010 Reports explain why the various FGD
wastewater treatment technologies discussed below, except physical/chemical
treatment, were not chosen for Merrimack Station. EPA describes PSNH's reasons
for rejecting each of these technologies and comments on the company's
explanations. The technologies analyzed include:
Discharge to a POTW
Evaporation ponds
Flue gas injection
Fixation
Deep well injection
FGD WWTS effluent reuse/recycle
Settling ponds
Treatment by the existing WWTS
Vapor -compression evaporation
Physical/chemical treatment
Physical/chemical with added biological stage
3.1 Discharge to a POTW
PSNH evaluated discharging Merrimack Station's FGD wastewater to a local
publicly owned treatment works (POTW) as a treatment alterative. Specifically,
PSNH evaluated "[d]ischarging the FGD Wastewater to the POTW closest to
Merrimack Station - the Hall Street Wastewater Treatment Facility in Concord,
New Hampshire — [but the company concluded that it would be] ... technically
infeasible because there currently is no physical connection between the Station
and the POTW by which to convey the FGD Wastewater ... [and] the-POTW is not
designed to manage wastewater with the pollutant characterization of the FGD
Wastewater." PSNH's October 2010 Report, p. 8.
In EPA's view, it would be unreasonable in this case to require PSNH to install a
connection of over five miles to a POTW that might not be capable of treating the
FGD system wastewater. Therefore, EPA concurs with PSNH that this option does
not represent a long-term BAT option for Merrimack Station.
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3.2 Evaporation Ponds
PSNH also evaluated evaporation ponds as a treatment alterative for the FGD
wastewater from Merrimack Station but reached the following conclusions:
[u]sing evaporation ponds at Merrimack Station to treat the FGD
Wastewater is technically infeasible because the New Hampshire climate is
not sufficiently warm and dry year-round to enable evaporation ponds at
the Station to achieve an evaporation rate that would be equal to or
greater than the flow of FGD Wastewater .... If PSNH were to rely solely
on evaporation ponds to remove FGD -related pollutants from the FGD
Wastewater, it would only be able to operate the FGD WWTS - and thus
the FGD System - during the summer months.
Id. at 9. EPA concurs with PSNH that use of evaporation ponds, a technology
predominantly used in the south and southwest, would be impracticable in New
Hampshire's climate. Therefore, EPA does not consider this technology to be a
possible BAT at Merrimack Station.
3.3 Flue Gas Injection
PSNH also evaluated the use of flue gas injection as a treatment alternative for
the FGD wastewater from Merrimack Station, explaining that "[t]his treatment
technology option would involve injecting part or all of the FGD [w]astewater into
the Station's flue gas upstream of the electrostatic precipitators ("ESPs") and
relying on the hot flue gas to evaporate the liquid component of the FGD
[w]astewater and the ESPs to capture the remaining metals and chlorides." Id.
at 9-10. PSNH rejected this option, however, explaining as follows:
PSNH is not aware of any flue gas injection system currently in operation
at any power plant in the U.S. to treat FGD wastewater. Further, after
evaluating this option for use at Merrimack Station, PSNH has concluded
that the lack of such systems is due to the numerous technical, operation
and maintenance ("O&M") and potential worker safety issues they could
,pose. First, there is a reasonable risk that the highly corrosive dissolved
chlorides remaining after the evaporation of the injected FGD wastewater's
liquid component would not be fully captured by the ESPs, with the result
that over time, they would concentrate in the FGD system's scrubber and
other components, posing a serious risk of equipment corrosion and FGD
system failure. This in turn would give rise to burdensome long-term O&M
issues and costs that, while potentially manageable in theory, could in fact
render operation of the flue gas injection system impracticable. In
addition, metals that commingle and become concentrated with fly ash in
the boilers and elsewhere could pose a potential health risk to employees.
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Id. at 10. EPA agrees with PSNH that this technology has not been demonstrated
to be available for treating FGD wastewater and that remaining technical issues
would need to be resolved before EPA could consider determining it to be the BAT
at Merrimack Station.
3.4 Fixation
PSNH also evaluated the use of "fixation" as a treatment alternative for the FGD
wastewater from Merrimack Station. PSNH explained this technology as follows:
Fixation would involve the mixing of lime, fly ash and FGD Wastewater with
the gypsum solids separated from the purged slurry to form a concrete -like.
substrate. Through the pozzolanic reactions that result, dissolved solids,
metals and chlorides in the FGD Wastewater would be bound up in the
concrete -like substrate, which would be disposed of by landfilling.
However, fixation generally is not used to manage the gypsum solids by-
product generated by forced -oxidation FGD systems like the Station's FGD
System, which are designed and operated to "recycle" these solids into
wallboard -quality gypsum. Rather, fixation historically has been used to
manage the unusable calcium sulfite by-product generated by inhibited
oxidation FGD systems and the calcium sulfite/calcium sulfate by-product
generated by natural oxidation FGD systems.
Id. Under state law, PSNH is required to install a wet flue gas desulfurization
system at Merrimack Station. Further, PSNH concluded that a limestone forced
oxidation system is the best technology match for the wet scrubber to be installed at
Merrimack Station. PSNH has further commented that fixation "was historically
used at plants with natural or inhibited oxidation FGD systems, both of which
produce an unusable calcium sulfide byproduct that requires management and
disposal." PSNH's December 2010 Report, p. 6. Although the fixation process is
viable for the type of FGD system at Merrimack Station (i.e., the FGD gypsum
solids could be combined with the FGD wastewater, lime and fly ash to create the
pozzolanic solids), the process would render the gypsum solids unmarketable. EPA
concurs that fixation does not represent BAT for this facility.
3.5 Deep Well Injection
PSNH evaluated and rejected deep well injection as a treatment alterative for the
FGD wastewater from Merrimack Station. The company explained its decision as
follows-
[d]eep well injection is not a viable treatment alternative for the FGD
Wastewater for several reasons. First, PSNH does not currently have any
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deep wells at any of its facilities. Second, there would be significant local
opposition - from the Town of Bow, residents in the area around
Merrimack Station, and interested environmental groups - to its
installation of a deep well at Merrimack Station due to potentially
adverse drinking water aquifer impacts. Third, we believe it would be
difficult to the point of impossible to obtain the necessary state permits,
especially in light of the New Hampshire legislature's focus on
groundwater quality management and use over the past few years.
Id. at 5. While PSNH's reasoning does not persuade EPA that deep well injection
would be infeasible, EPA does for other reasons conclude that this technology is not
the BAT for controlling FGD wastewater discharges at Merrimack Station at this
time.
Although PSNH correctly points out that Merrimack Station does not currently
have a deep injection well, it appears that it would be technologically feasible to
install deep well injection equipment at the site. PSNH's additional reasons for
rejecting this technology seem largely based on speculation about political reactions
to the technology, rather than its technical merits. The question should not turn on
speculation about whether local residents, environmental groups or New
Hampshire legislators might tend to be opposed to the technology due to the
importance of protecting local drinking water aquifers. EPA shares the state and
local priority for protecting groundwater quality, but the question should be
whether the technology will be environmentally protective and capable of meeting
applicable groundwater quality standards. Furthermore, proper use of deep well
injection would not be expected to impact local water supplies as, in general, a
correctly designed injection well "extends from the surface to below the base of the
deepest potable water aquifer, and is cemented along its full length." Herbert,
Earle A., "The Regulation of Deep -Well Injection: A Changing Environment
Beneath the Surface," Pace Environmental Law Review, Volume 14, Issue 1, Fall
1996, Article 16, 9-1-1996, p. 174.10
Still, it is unclear whether deep well injection is an available technology for
potential use at Merrimack Station. This is because "[u]nderground injection uses
porous rock strata, which is commonly found in oil producing states" (Id. at 178),
but EPA is unaware of data indicating whether or not suitable hydrogeologic
conditions exist at Merrimack Station. For this reason, EPA has decided that it
cannot currently find deep well injection to be the BAT at Merrimack Station. At
the same time, PSNH has not provided sufficient technical information to rule out
the possibility that deep well injection could in the future be determined to be the
BAT at Merrimack Station. As a result, EPA may revisit this option going forward
10 Also at htti):Hdigitalcommons.pace.edu/pelr/voll4/issl/16/ or
http://digitalcommons.p ace. edu/cgi/viewcontent.cgi?article=1375&contexts elr&seiredir= l#s
earch="http://+digitalcommons.pace.edu/pelr/vol14/iss1/16", p.6.
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depending on the available information.
3.6 FGD WWTS Effluent Reuse/Recycle
On October 29, 2010, EPA sent PSNH an information request letter under CWA
§308(a), in which the Agency specifically requested that PSNH, "[p]lease explain
why the wastewater generated from the proposed Merrimack Station FGD WWTS
is not being proposed for reuse and or recycle within the Station (e.g., for coal dust
suppression or scrubber make-up water)." EPA, "Information Request for NPDES
Permit Re -issuance, NPDES Permit No: NH0001465," October 29, 2010, p. 4. The
purpose of EPA's request was to garner information to help the Agency decide if
recycling some or all of the FGD WWTS effluent might be part of the BAT for
Merrimack Station.
PSNH responded that it was indeed planning to recycle some of the treated effluent
from the FGD WWTS to the FGD system. The FGD wet scrubber system's make-up
water needs are projected to be approximately 750 gpm (1.08 MGD), while the
volume of the FGD WWTS effluent discharge is projected to be substantially less, at
35-50 gpm (0.07 MGD). PSNH plans to discharge the treated FGD wastewater from
the FGD WWTS to the slag settling pond, which also receives various other
wastewaters from the facility, and then to withdraw water from the slag settling
pond for the FGD wet scrubber system's make-up water. Since the FGD WWTS
effluent is to be commingled with the slag settling pond water, PSNH concludes
that some of the FGD wastewater should be considered to be recycled back to the
FGD scrubber system. However, in light of the piping layout shown in the
company's site diagram and the volume of the various flows entering and exiting
the pond, EPA believes that a de minimis amount, if any, of the treated FGD
effluent is actually likely to be recycled back to the scrubber from the slag settling
pond. Therefore, such recycling/reuse of the FGD wastewater will not be considered
part of the BAT for Merrimack Station, at this time.
Aside from stating that some of the FGD effluent would be recycled for scrubber
makeup water, PSNH's submissions to EPA fail to address whether or not some or
all of the remaining FGD WWTS effluent could also be reused within some aspect of
plant operations (e.g., for coal dust suppression). Therefore, PSNH has not provided
sufficient technical information to rule out the possibility that additional
recycle/reuse could be achievable at Merrimack Station. As a result, EPA may
revisit this option in the future depending on the available information.
3.7 Settling Ponds
PSNH evaluated the use of settling ponds as a treatment alterative for the FGD
wastewater from Merrimack Station as follows:
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The use of on-site settling ponds dedicated solely to treating the FGD
Wastewater is technically infeasible at Merrimack Station because there is
not enough usable open space at .the Station to construct a settling pond
system of adequate dimensions to achieve proper treatment. To be effective, a
settling pond must retain wastewater for a sufficient period of time to allow
particulates to fall out of suspension before the wastewater is discharged....
In addition, settling ponds are designed to remove suspended particulates
from wastewater by means of simple gravity separation, and do not include
the process control features that are intrinsic to modern clarifiers, allowing
operator control over treatment factors such as settling rate, removal and
recirculation.
PSNH's October 2010 Report, p. 8-9. EPA does not necessarily agree that
Merrimack Station does not have sufficient area to construct settling ponds. There
are areas, such as those on the northern boundary of the Merrimack Station
property, or on PSNH owned property across River Road, which might provide
sufficient space to build settling ponds.
Treatment by physical/chemical treatment followed by biological treatment,
however, is more effective than settling ponds. EPA has explained that its
- evaluation of the industry indicates that "settling ponds are the most commonly
used treatment system for managing FGD wastewater ... [and] can be effective at
removing suspended solids and those metals present in the particulate phase from
FGD wastewater; however, they are not effective at removing dissolved metals."
EPA's 2009 Detailed Study Report, p. xii- xiii. As a result, EPA does not consider
settling ponds to be the BAT for FGD wastewater at Merrimack Station.
3.8 Treatment by the Existing WWTS
PSNH evaluated the use of Merrimack Station's existing wastewater treatment
system (WWTS) as an alternative for treating the FGD wastewater. PSNH's
analysis stated as follows:
Merrimack Station has an existing on-site WWTS that it uses to treat the
wastewater streams from its current operations before discharging them, via
the Station's treatment pond ... This WWTS consists primarily of three
large, rectangular concrete settling basins with chemical feed systems and
basic mixing capability (using compressed air) ... [The existing WWTS] would
not provide optimal treatment, especially compared to the significant -
reductions in FGD -related pollutant concentrations that the FGD WWTS is
projected to achieve. The existing WWTS' limitations as a treatment system
for the FGD Wastewater stem directly from the fact that the characteristics
of the FGD Wastewater and the Station's other wastewaters, and thus
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their respective treatment requirements, are appreciably different.... [the]
purpose of the Station's existing WWTS is to remove suspended solids from
large batches of Station wastewater. However, the FGD -related pollutants in
the FGD Wastewater will be present primarily as dissolved solids ... [and
the FGD WWTS influent] will have higher concentrations of dissolved
metals and chlorides than any of the Station's other wastewaters and will be
supersaturated with dissolved gypsum, which the Station's other
wastewaters are not. For this reason, effective treatment of the FGD
Wastewater will require certain conditioning steps ..... to precipitate and
flocculate the dissolved metals and gypsum prior to clarification. These
conditioning steps are most favorably performed as they will be in the FGD
WWTS: in a continuous, not a batch, process using reaction tanks.
PSNH's October 2010 Report, p. 7-8. EPA agrees that Merrimack Station's existing
WWTS, currently used for metal cleaning and low volume wastes, would require
redesign/rebuilding to enable it to treat the FGD wastewater. Therefore, EPA
rejects use of the existing WWTS as a potential BAT for treating FGD wastewater
at Merrimack Station.
3.9 Vapor -Compression Evaporation
EPA has reported that "evaporators in combination with a final drying process can
significantly reduce the quantity of wastewater discharged from certain process
operations at various types of industrial plants, including power plants, oil
refineries, and chemical plants." EPA's 2009 Detailed Study Report, p. 4-33. In
some cases, plants have been able to achieve "zero liquid discharge" with this
technology. Id.
In its submissions to date, PSNH evaluated the use of vapor -compression
evaporation at Merrimack Station as follows:
[p]ower plants have used vapor -compression evaporator systems - typically
consisting of brine concentrators in combination with forced -circulation
crystallizers - to treat cooling tower blowdown since the 1970s. Nonetheless,
FGD wastewater chemistry and cooling tower blowdown chemistry are very
different, with the result that the power industry's design and operational
experience with treating cooling tower blowdown using evaporation systems
is not directly transferable to the use of evaporation systems to treat FGD
wastewater. In fact, there are currently no power plants in the United States
that are operating vapor -compression evaporator (i.e., brine concentrator and
crystallizer) systems to treat FGD wastewater....
In treating FGD wastewater with a vapor -compression evaporator system,
there is a high potential for scaling and corrosion. In fact, using a crystallizer
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Determination of Technology -Based Effluent Limits for the Flue Gas
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to treat FGD wastewater requires pretreatment, upstream of the brine
concentrator, to "soften" the wastewater by removing calcium chloride and
magnesium chloride salts that could result in a very high scaling potential
within the brine concentrator and crystallizer. This softening process
consumes large quantities of lime and soda ash and produces large quantities
of sludge that must be dewatered, usually by filter press, for landfill disposal.
... Until recently, RCC Ionics was the only supplier that had installed a
vapor -compression evaporator system using a brine concentrator and
crystallizer for FGD wastewater treatment in the United States; however,
none of the five units that it has installed are currently operational.
Aquatech had designed and manufactured vapor -compression evaporator
system components for the Dallman Power Station in Springfield, Illinois,
but this system was never installed. At present, another Aquatech vapor -
compression evaporator system is currently in start-up in the United States,
at Kansas City Power & Light's Iatan Station in Weston, Missouri; however,
to date there has been no published information regarding its start-up or
operation. Aquatech has also installed five vapor -compression evaporator
systems at ENEL power plants in Italy, but not all of these systems are in
operation, and performance data has not been published....
PSNH's October 2010 Report, p. 10-11. EPA agrees with PSNH that the operation
of vapor -compression evaporation requires proper control of wastewater chemistry
and process operations and may require pretreatment steps tailored to the specific
facility operation."
EPA has reported that "one U.S. coal-fired plant and six coal-fired power plants in
Italy are treating FGD wastewater with vapor -compression evaporator systems."
EPA's 2009 Detailed Study Report, p. 4-33. This information suggests that this
technology may be available for use at Merrimack Station. In fact, EPA has
recently received information that PSNH is currently evaluating the potential use
of this technology for Merrimack Station. PSNH has not, however, submitted an
amended permit application proposing to use vapor compression evaporation, or
providing information concerning the suitability of the technology for use at
Merrimack Station.
li For example, the design currently operating on FGD wastewater requires pretreatment of
the wastewater in a clarifier/softener for TSS and hardness reduction followed by concentration in a
brine concentrator and a crystallizer. One equipment vendor has developed an alternative design
that would avoid the need for pre -softening. Shaw, William A., Low Temperature Crystallization
Process is the Key to ZLD Without Chemical Conditioning, Paper Number IWC -10-39 presented at
The International Water Conference®, 71st Annual Meeting, October 24-28, 2010. One such system
is currently being installed to treat coal gasification wastewater and such systems have been used
for years in other industries, but no systems of this alternative design are currently used to treat
FGD wastewater.
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In light of all of the above, EPA has concluded that it cannot based on current
information determine this technology to be the BAT for treating FGD wastewater
at Merrimack Station. It simply is not clear at the present time whether or not this
technology is feasible for application at Merrimack Station. EPA is continuing to
review information characterizing operational factors and pollutant removal efficacy
for vapor compression evaporation and depending on the results of further
evaluation of this technology, EPA could potentially find it to be part of the BAT for
Merrimack Station for the final NPDES permit.
EPA has also considered the BAT factors in evaluating the possibility of using vapor
compression evaporation technology at Merrimack Station. Specifically, EPA has
considered engineering and process concerns related to the potential use of vapor
compression technology, and whether it might necessitate any changes in
Merrimack Station's primary production process or other pollution control
processes. While effective vapor compression evaporation will require control of
water chemistry and may necessitate pretreatment of the wastewater, EPA finds
that use of vapor compression evaporation would not interfere with, or require
changes to, the facility's other pollution control processes or its primary process for
generating electricity. EPA also concludes that vapor compression evaporation
technology can be utilized together with physical/chemical treatment. Moreover,
EPA finds that the age of Merrimack Station would neither preclude nor create
special problems -with using vapor compression evaporation technology. With
regard to the potential non -water environmental effects of using vapor compression
evaporation, EPA notes that energy demands of this type of treatment technology
may not be insignificant. In addition, vapor compression evaporation treatment
would produce a solid waste that would require proper management.
Finally, EPA has also considered the cost of the technology and finds that it would
add significant cost. Specifically, EPA has estimated that utilizing
physical/chemical treatment together with vapor compression evaporation at
Merrimack Station would cost approximately $4,162,000 per year (based on capital
costs of approximately $27,949,000, and annual operating and maintenance costs of
approximately $1,524,000). See 9/13/11 (07:56 AND Email from Ronald Jordan, EPA
Headquarters, to Sharon DeMeo, EPA Region 1, "Estimated costs & pollutant
reductions for treatment options at Merrimack Station."
3.10 Physical/Chemical Treatment
Physical/chemical treatment (i.e., chemical precipitation) is a common
treatment method used to remove metal compounds from wastewater. With
this treatment technology, "chemicals are added to the wastewater in a series
of reaction tanks to convert soluble metals to insoluble metal hydroxide or
metal sulfide compounds, which precipitate from solution and are removed
along with other suspended solids." See Memorandum from James A. Hanlon
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of EPA's Office of Water to EPA Water Division Directors, dated June 7, 2010
(hereafter "EPA's June 7, 2010 Guidance Memorandum"), AttachmentA, p. 3-4.
For example, an alkali, such as hydrated lime, may be added to adjust the pH
of the wastewater to the point where the metals precipitate out as metal
hydroxides. Coagulants and flocculants are also often added to facilitate the
settling and removal of the newly -formed solids.
Plants striving to maximize removals of mercury and other metals will also
often include sulfide addition (e.g., organosulfide) as part of the process.
Adding sulfide chemicals in addition to the alkali can provide even greater
reductions of heavy metals due to the very low solubility of metal sulfide
compounds, relative to metal hydroxides.
Sulfide precipitation has been widely used in Europe and is being
installed at multiple locations in the United States. Approximately
thirty U.S. power plants include physical/chemical treatment as part of
the FGD wastewater treatment system; about half of these plants
employ both hydroxide and sulfide precipitation in the process. This
technology is capable of achieving low effluent concentrations of various
metals and the sulfide addition is particularly important for removing
mercury....
EPA's June 7, 2010 Guidance Memorandum, Attachment A, p. 4.
In an effort to control its air pollutant emissions as required by New Hampshire
state law, Merrimack Station recently completed the installation of a limestone
forced -oxidation, wet flue gas desulfurization (FGD) scrubber system, as described
in section 1.0 above. Moreover, conscious of the need to treat the wastewater
generated from the FGD system prior to discharge to the Merrimack River, PSNH
decided to install, and is currently in the process of completing the construction of, a
physical/chemical treatment system. The treatment system at Merrimack Station
consists of the following operations in sequence: equalization; reaction tank #1
(includes the addition of hydrated lime for pH adjustment, recycled sludge and
organosulfide); reaction tank #2 where ferric chloride will be added; polymer
addition; clarification; gravity filtration; and a series of proprietary filter cartridges
containing adsorbent media targeted specifically for the removal of mercury i.e.,
"polishing step".
3.11 Physical/Chemical with added Biological Treatment
While physical/chemical treatment can be very effective for removing some metals,
it is ineffective for removing certain forms of selenium and nitrogen compounds, and
certain other metals that can contribute to high concentrations of TDS in FGD
wastewater (e.g., calcium, magnesium, sodium). "Seven power plants in the U.S.
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are operating or constructing treatment systems that follow physical/chemical
treatment with a biological treatment stage to supplement the metals removals
with substantial additional reductions of nitrogen compounds and/or selenium." Id.
Like mercury and other contaminants found in FGD wastewater that originate from
the process of coal combustion, selenium is a toxic pollutant that can pose serious
risk to aquatic ecosystems (see Table 5.1, supra). Nitrogen compounds, in turn, can
contribute to a variety of water quality problems (see Table 5. 1, supra).
As EPA has explained:
... biological wastewater treatment systems use microorganisms to
consume biodegradable soluble organic contaminants and bind much of
the less soluble fractions into floc. Pollutants may be reduced
aerobically, anaerobically, and/or by using anoxic zones. Based on the
information EPA collected during the detailed study, two main types of
biological treatment systems are currently used (or planned) to treat
FGD wastewater: aerobic systems to remove BOD5 and
anoxic/anaerobic systems to remove metals and nutrients. These
systems can use fixed film or suspended growth bioreactors, and
operate as conventional flow-through or as sequencing batch reactors
(SBRs).
EPA's 2009 Detailed Study Report, p. 4-30. Of the seven power plants mentioned in
EPA's June 7, 2010 Guidance Memorandum, three plants operate physical/chemical
treatment along with a fixed -film anoxic/anaerobic bioreactor optimized to remove
selenium from the wastewater.12 "Selenate, the selenium form most commonly
found in forced oxidation FGD wastewaters and the specie that is more difficult to
treat using chemical processes, is found [to] be readily remediated using anaerobic
biological reactors as is selenite." EPRI, Treatment Technology Summary for
Critical Pollutants of Concern in Power Plant Wastewaters, January 2007, p. 4-2.
The bioreactor reduces selenate and selenite to elemental selenium, which is then
captured by the biomass and retained in treatment system residuals. The
conditions in the bioreactor are also conducive to forming metal sulfide complexes to
facilitate the additional removal of mercury, arsenic, and other metals.
Consideration of PSNH's Reasons for Rejecting Biological Treatment
PSNH provided several reasons why it did not propose biological treatment
12 There are two additional power plants (not included in those mentioned above) that
operate fined -film anoxic/anaerobic bioreactors to remove selenium from their wastewater. These
two plants precede the bioreactors with settling ponds instead of physical/chemical treatment. The
other four plants mentioned in EPA's June 7, 2010 Guidance Memorandum operate sequencing
batch reactors (SBR) that are operated to optimize removal of ammonia and other nitrogen
compounds; the effectiveness of these SBRs at removing selenium compounds has not been
demonstrated.
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technology for selenium removal at Merrimack Station, but EPA does not find these
reasons to be persuasive. First, PSNH states that its consultant URS's anti -
degradation analysis to determine compliance with New Hampshire water quality
standards concluded that the FGD wastewater would contribute "an insignificant
loading of selenium to the Merrimack River, in part due to the anticipated
performance of the FGD WWTS' physical -chemical treatment...." EPA's
determination of technology-based effluent limits under the BAT standard is not,
however, governed by a determination of the selenium discharge limits needed to
satisfy state water quality standards. -Selenium is a toxic pollutant subject to the
BAT technology standard under the CWA. Dischargers must comply with federal
technology-based standards at a minimum, as well as any more stringent state
water quality requirements that may apply.
Second, PSNH states that selenium in FGD wastewater is primarily present in the
elemental form, which is easily removed in the treatment process. The company
also states that "... analyses during recent FGD scrubber startups have shown that
the largest percentage of the selenium present in FGD wastewater is present in the
elemental form and as selenite." PSNH's December 2010 Report, p. 7. PSNH
provides no references in support of these statements, however. Moreover, as
indicated above, EPA's research has found (a) that "FGD wastewater entering a
treatment system contains significant concentrations of several pollutants in the
dissolved phase, including ... selenium," EPA's 2009 Detailed Study Report, p. 4-31,
and (b) that "[m]odern forced -oxidation FGD system wastewater contains selenium,
predominately in the selenate form ..., [and that although] selenite can be
somewhat removed by iron co -precipitation, selenate is soluble and is not removed
in the [physical/chemical] treatment processes mentioned earlier." Power -Gen
Worldwide, "FGD Wastewater Treatment Still Has a Ways to Go" (Jan 1, 2008).
If selenium will be present in the FGD wastewater in the elemental form and easily
removed in Merrimack Station's WWTS, as PSNH suggests, then one would expect
much lower levels of selenium in the effluent than projected by PSNH. PSNH
reports that the FGD wastewater at Merrimack Station could be treated to achieve
a level of 9,000 ug/L. Yet, this level of selenium is within the range of levels seen
prior to treatment. See EPA's 2009 Detailed Study Report, p. 4-25, Table 4-6: FGD
Scrubber Purge Self -Monitoring Data.
Finally, PSNH opines that the four biological treatment systems for selenium that
it is aware of "have not been in service for a sufficiently long time to establish them
as proven technology." PSNH's December 2010 Report, p. 7. In that report, PSNH
suggests that five years of operations are required in order to establish that a
treatment technology is proven. EPA does not concur with PSNH's use of its
proposed five -year -of -operation criterion to rule out biological treatment for
selenium removal as unproven. With that said, anoxic/anaerobic technology has
been around longer than five years, albeit for other wastes or in pilot scale for FGD
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wastewater. As previously mentioned, available technologies may also include
viable "transfer technologies" — that is, a technology from another industry that
could be transferred to the industry in question — as well as technologies that have
been shown to be viable in research even if not yet implemented at a full-scale
facility.
Furthermore, as discussed above, EPA's research indicates that a number of power
plants have coupled biological treatment with physical/chemical treatment to
enhance selenium removal. For example, a two -unit 1,120 MW coal-fired
generating facility in the eastern United States installed physical/chemical
treatment coupled with anoxic/anaerobic biological treatment to reduce the
concentration of selenium in its effluent. According to one analysis, "[t]he entire
system has exceeded expectations and is meeting the discharge requirements." M.
Riffe et. al., "Wastewater Treatment for FGD Purge Streams," presented at MEGA
Symposium 2008.i3 On a broader level, a 2006 article in Power -Gen Worldwide
stated the following:
[m]uch of the coal mined and used in the eastern United States is high
in selenium. This requires many power producers to include selenium
removal as part of their FGD wastewater treatment systems to protect
the environment. Recommended water quality criteria for selenium
can be below 0.020 parts per million (ppm)..."
Power -Gen Worldwide, "Using Biology to Treat Selenium" (Nov. 1, 2006). As quoted
above, EPA has also found that "some coal-fired power plants are moving towards
using anoxic/anaerobic biological systems to achieve better reductions of certain
pollutants (e.g., selenium, mercury, nitrates) than has been possible with other
treatment processes used at power plants." EPA's 2009 Detailed Study Report, p. 4-
31. In addition, EPA explained that while "... chemical precipitation is an effective
means for removing many metals from the FGD wastewater ... [, b]iological
treatment, specifically fixed -film anoxic/anaerobic bioreactors when paired with a
chemical precipitation pretreatment stage, is very effective at removing additional
pollutants such as selenium and nitrogen compounds (e.g., nitrates, nitrites)." Id. at
4-50. Thus, EPA regards biological treatment — more particularly, biological
treatment coupled with physical/chemical treatment — to be an adequately proven
technology to be a candidate for being designated as the BAT for treating
Merrimack Station's FGD wastewater.
13 The authors of this paper, which included two employees of Siemens Water Technology
Corp., report that "[a]bout eight biological systems have been installed or planned for installation
since 2004." EPA acknowledges that not all of these systems were installed specifically for selenium
removal, since biological treatment can also be used to reduce COD/BOD and ammonia or other
nitrogen compounds. Nevertheless, these installations demonstrate the viability of biological
technology for treating a variety of pollutants in FGD wastewater, and currently there are five
biological systems that are specifically optimized for removing selenium from FGD wastewater.
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4.0 BAT for FGD Wastewater at Merrimack Station
EPA is not aware of, and PSNH has not identified, any reason that
physical/chemical treatment or biological treatment would be precluded from being
the BAT (or part of the BAT) for the FGD wastewater in this case. In evaluating
these treatment methods, EPA has considered the BAT factors on a site-specific
basis for Merrimack Station. This consideration is discussed below.
(i) Age of the equipment and facilities involved
In determining the BAT for Merrimack Station, EPA accounted for the age of
equipment and the facilities involved. As mentioned previously, PSNH is already in
the process of completing construction of a physical/chemical treatment system to
treat the wastewater generated from the Station's new FGD scrubber system.
Moreover, there is nothing about the age of the equipment and facilities involved
that would preclude the addition of biological treatment technology. In other words,
Merrimack Station's new physical/chemical treatment system could be retrofitted
with additional new biological treatment technology, albeit at some expense.
Therefore, the age of the facility by itself poses no bar to compliance.
(ii) Process employed and process changes
In determining the BAT for Merrimack Station, EPA considered the process
employed at the facility. Merrimack Station is a 520 MW, fossil fuel -burning,
steam -electric power plant with the primary purpose of generating electrical energy.
Adding physical/chemical treatment and biological treatment for the FGD
wastewater will not interfere with the Permittee's primary process for generating
electricity. In addition, biological treatment would not interfere with the
physical/chemical treatment process; it would complement it. Biological treatment
typically consists of a bioreactor tank(s)/chamber(s), nutrient storage, a possible
heat exchanger, a solids removal device, pumps and associated equipment. To add
biological treatment to the FGD wastewater treatment system, Merrimack Station
would need to install additional treatment tanks and process equipment and
connect it with the physical/chemical treatment system.
(iii) Engineering aspects of the application of various types of
control techniques
As discussed above, physical/chemical treatment is frequently used to treat FGD
wastewater and PSNH has chosen it for Merrimack Station. In addition, biological
technology optimized for treating nitrates and selenium in FGD wastewater, while
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also removing other pollutants, is used at five existing coal fired steam -electric
power plants around the country. 14 According to EPA's research:
[s]even power plants in the U.S. are operating or constructing treatment
systems that follow physical/chemical treatment with a biological treatment
stage to supplement the metals removals with substantial additional
reductions of nitrogen compounds and/or selenium. Three of these systems
use a fixed film anoxic/anaerobic bioreactor optimized to remove selenium
from the wastewater. ... Two other power plants (in addition to the seven
biological treatment systems) operate treatment systems that incorporate
similar biological treatment stages, but with the biological stage preceded by
settling ponds instead of a physical/chemical treatment stage. Although the
primary treatment provided by such settling ponds at these plants is less
effective at removing metals than physical/chemical treatment, these plants
nonetheless further demonstrate the availability of the biological treatment
system and its effectiveness at removing selenium and nitrates.
EPA's June 7, 2010 Guidance Memorandum, Attachment A, p. 4. EPA also reported
that "some coal-fired power plants are moving towards using anoxic/anaerobic
biological systems to achieve better reductions of certain pollutants (e.g., selenium,
mercury, nitrates) than has been possible with other treatment processes used at
power plants." EPA's 2009 Detailed Study Report, p. 4-31.
(iv) Cost of achieving effluent reductions
PSNH chose to install, and has largely completed installation of, a
physical/chemical treatment system at Merrimack Station. This demonstrates that
the cost of this system was not prohibitive. While PSNH did not provide EPA with
its predicted (or actual) costs for its physical/chemical FGD WWTS, EPA estimates
the annualized costs for such a system (not including the polishing step for added
mercury removal)15 to be approximately $889,000 (based on approximately
$4,869,000 in capital costs and approximately $430,000 in yearly operating and
14 Five power plants operate biological systems optimized to remove selenium; three plants
do so in conjunction with physical/chemical treatment and two do so in conjunction with a settling
pond (nitrates are also removed in the process of biologically removing selenium). Four other power
plants operate biological systems (i.e., sequencing batch reactors) that are optimized to remove
ammonia and other nitrogen compounds; the effectiveness of these SBRs at removing selenium has
not been quantified. In part, these two different types of biological systems optimize removal of their
target pollutants (i.e., selenium versus ammonia and other nitrogen compounds) by controlling the
oxidation/reduction potential (ORP) within zones or stages of the bioreactors. Nitrogen compounds
and selenium are removed at different ORPs. Thus the manner in which a bioreactor is operated
will influence which pollutants it removes and the degree to which they are removed. In addition,
removing ammonia biologically requires including an oxidation step within the bioreactor.
15 PSNH did not provide estimated or actual costs for the polishing step and EPA does not
presently have sufficient information to generate a reasonable estimate of these costs.
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maintenance costs). See 9/13/11 (07:56 An Email from Ronald Jordan, EPA
Headquarters, to Sharon DeMeo, EPA Region 1, "Estimated costs & pollutant
reductions for treatment options at Merrimack Station." In addition, EPA
estimates that the additional annualized costs of adding biological treatment at
Merrimack Station would be approximately $765,000 (based on additional costs of
approximately $4,954,000 in capital costs and approximately $297,000 in yearly
operating and maintenance costs). Id. EPA also found additional information
supporting the reasonableness of these cost estimates. 16 Thus, EPA estimates that
the total FGD WWTS, including biological treatment would be approximately
$1,654,000 (based on approximately $9,823,000 in capital costs and approximately
$727,000 in yearly operating and maintenance costs). Id. EPA notes that data
collected from power plants currently operating fixed -film anoxic/anaerobic
biological treatment systems show that operating costs are relatively small because
electrical consumption is low and relatively little treatment sludge is generated in
comparison to physical -chemical treatment.17 Costs on this order of magnitude can
reasonably be borne by PSNH. PSNH has been a profitable company and should be
able to afford to install biological treatment equipment if it is determined to be part
of the BAT for Merrimack Station. For comparison, PSNH Merrimack has reported
the total cost of the FGD system, including wastewater treatment, at $430 million.
The additional cost for adding biological treatment would represent a small fraction
of this total.18
16 One biological system currently in operation is sized to handle approximately 30 times the
flow of Merrimack's FGD wastewater treatment system (70,000 gpd) and cost approximately $35
million, including construction of a settling pond and related equipment, such as piping and feed
pumps. Another biological system designed to handle wastewater flows almost 5 times greater than
Merrimack cost approximately $20 million (including construction of a settling pond and related
equipment), while another system 10 times larger than Merrimack Station's treatment system cost
less than $27 million (for the bioreactor stage and other facility improvements not related to the
bioreactor). Industry responses to the U.S. Environmental Protection Agency "Questionnaire for the
Steam Electric Power Generating Effluent Guidelines." (confidential business information (CBI))
Also See Sonstegard, J. et al, "ABMet: Setting the Standard for Selenium Removal." Presented at the
International Water Conference, October 2010.
17 Published values in the literature for operating and maintenance costs are on the order of
$0.35 to $0.46 per 1,000 gallons of water treated (excluding labor). Three plants, with FGD
wastewater flow rates ranging from 0.25 to 2 MGD, have reported annual O&M costs of $152,000 to
$400,000 (including labor, and in some cases also including costs for activities not associated with
the biological treatment system). Industry responses to the U.S. Environmental Protection Agency
"Questionnaire for the Steam Electric Power Generating Effluent Guidelines." (CBI) Also see
Sonstegard, J. et al, "ABMet: Setting the Standard for Selenium Removal." Presented at the
International Water Conference, October 2010.
18 EPA has also considered information suggesting that physical/chemical treatment coupled
with biological treatment is likely to be more cost-effective than physical/chemical treatment alone in
terms of cost per pound of pollutant discharge reduced. Id. (data in table indicates a cost per pound
of pollutant discharge reduced of $52.60 (based on annualized costs of $889,000/16,900 lbs. of
pollutant discharge removed per year) for physical/chemical treatment alone, and of $2.59 (based on
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(v) Non -water quality environmental impacts (including
energy requirements)
Finally, EPA considered the secondary, non -water quality environmental impacts
and energy effects associated with the physical/chemical treatment together with
biological treatment, including air emissions, noise, and visual effects at Merrimack
Station. To EPA's current knowledge, there is nothing about either
physical/chemical treatment or biological treatment that is likely to generate any
significant adverse non -water quality environmental effects at Merrimack Station.
Physical/chemical treatment is estimated to generate 1,976 tons of solids per year,
and require 339,017 kW -hr of electricity. See 9/16/11 (09:57 AM) Email from Ronald
Jordan, EPA Headquarters, to Sharon DeMeo, EPA Region 1, "Non -water quality
environmental impacts for FGD wastewater treatment options." "The technology
option of chemical precipitation in conjunction with biological treatment is
estimated to generate a total of 1,986 tons of solids per year (0.5 percent more than
the chemical precipitation technology), and require 354,085 kW -hr of electricity (4.4
percent increase relative to chemical precipitation)." Id.
There will be some indirect air emissions associated with the energy needed to
operate the treatment system. The incremental increases in energy demand and air
emissions will be insignificant relative to Merrimack Station's existing energy
production and air emissions.
5.0 BPJ-Based BAT Effluent Limits
5.1 Introduction
As previously discussed, for pollutants not addressed by the NELGs for a particular
class or category of industrial dischargers, permitting authorities develop
technology-based effluent limits for NPDES permits on the basis of BPJ. In the text
above, EPA evaluated technological alternatives and determined that
physical/chemical treatment, coupled with biological treatment, constitutes the BAT
for limiting the discharge of certain FGD wastewater pollutants at Merrimack
Station.ls
Yet, specifying treatment technology does not by itself determine the precise
discharge limits that should be included in the permit for pollutants in the FGD
annualized costs of $1,654,000/639,900 lbs. of pollutant discharge removed per year) for
physical/chemical and biological treatment).
is As explained farther below, EPA has determined based on current facts that it should not
develop BCT limits at this time (see discussion of BOD and pH, below). Also see section 5.4 below.
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wastewater. For example, EPA's research into facilities using physical/chemical
and biological treatment reveals that different facilities display a range of
concentrations for various pollutants in the untreated FGD wastewater.
The variation in pollutant concentrations at each facility likely results from the
interaction of a number of different factors. These may include variables such as
the quality of the coal burned at the facility, the type and amount of air pollutants
generated in the combustion process, the efficiency with which the scrubbers
remove pollutants from the flue gas and transfer it to the wastewater stream, and
the degree to which the physical/chemical and biological treatment systems can
remove pollutants from the wastewater. The latter factor may, in turn, be affected
by the design and operation of the wastewater treatment system (e.g., the types and
dosages of chemicals used for precipitation and coagulation; equalization capacity
and residence time in the reaction tanks and clarifiers; and operational conditions
such as pH set -points in the reaction tanks, sludge recycle frequency/rates, and
clarifier sludge levels).
EPA's task in setting BAT limits is to set the most stringent pollutant discharge
limits that are technologically and economically available (or feasible), and are not
otherwise rejected in light of considering the "BAT factors." Neither Merrimack
Station's wet FGD scrubber system nor its proposed FGD WWTS is yet operational.
As a result, EPA does not have actual data for characterizing the untreated FGD
purge from Merrimack Station operations. Nevertheless, EPA has reviewed the
available data for a number of FGD systems collected during EPA's detailed study
of the industry (described in EPA's 2009 Detailed Study Report) and during EPA's
current rulemaking to revise the effluent guidelines. These data include samples of
untreated and treated wastewater collected during EPA sampling episodes and self-
monitoring data collected by power plants. In determining effluent limits for
Merrimack Station, EPA used the best available information to specify permit
limits that, consistent with the BAT standard, are appropriately stringent but not
infeasible.
For the new Merrimack Station NPDES permit, EPA developed BAT -based effluent
limits to address wastewater discharges from the FGD WWTS after consulting
multiple sources, including EPA's 2009 Detailed Study Report20 and EPA's June 7,
2010 Guidance Memorandum. EPA's 2009 Detailed Study Report summarizes
information recently collected by the Agency to inform a determination of whether
to revise the current Steam Electric Power Generating NELGs promulgated at 40
C.F.R..Part 423. EPA's June 7, 2010, Guidance Memorandum offers assistance to
20 As part of the data collection activities presented in EPA's 2009 Detailed Study Report,
EPA compiled sampling self-monitoring data from a number of power plants. As described below,
EPA considered this data, along with other information, in its BPJ determination of BAT -based
permit limits for certain pollutants for Merrimack Station.
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NPDES permitting authorities working to establish, on a BPJ basis, BAT -based
effluent limits for wastewater discharges from FGD systems at steam electric power
generating facilities prior to revisions to the NELGs.
In addition, EPA relied on an August 11, 2011, report by EPA's Office of.Water,
Engineering and Analysis Division, titled "Determination of Effluent Limits for
Flue Gas Desulfurization (FGD) Wastewater at PSNH Merrimack Station Based on
Performance of Physical -Chemical Treatment Followed by Biological Treatment"
(hereafter "EPA's 2011 Effluent Limits Report"). This report "presents the results
of statistical analyses performed on treatment system performance data to calculate
effluent limitations for inclusion in Merrimack Station's NPDES permit." August
11, 2011 Memorandum from EPA's Office of Water to EPA Region 1 accompanying
EPA's 2011 Effluent Limits Report. Based on the sufficiency of available data,
effluent limits were determined for the following parameters: arsenic, chromium,
copper, mercury, selenium, and zinc. These limits were based on statistical
analyses of self-monitoring data collected by plant staff at Duke Energy's Allen and
Belews Creek Stations to evaluate FGD treatment system operations, as well as
certain data collected during a study of the Belews Creek treatment system
conducted by the Electric Power Research Institute (EPRI) (hereafter "Duke Energy
data"). This data reflects performance over several years at these two Duke Energy
plants. In EPA's view, this data is the best available reflection of what is possible
with the use of physical/chemical and biological treatment for FGD wastewater.
Duke Energy's Allen Station and Belews Creek Station are similar to Merrimack
Station in that they are coal-fired power plants that burn bituminous coal to
generate electricity and "operate limestone forced oxidation wet flue gas
desulfurization (FGD) systems to reduce sulfur dioxide (SO2) emissions, producing
a commercial -grade gypsum byproduct." EPA's 2011 Effluent Limits Report, p. 3.
In addition, PSNH has installed a similar physical/chemical FGD treatment system
at Merrimack Station to those at the Duke Energy stations, consisting of one -stage
chemical precipitation/iron co -precipitation. Allen and Belews Creek treatment
systems, however, also include an anoxic/anerobic biological treatment stage,
designed to optimize the removal of selenium.21 "The bioreactor portion of the
treatment train consists of bioreactor cells containing activated carbon media and
microbes which reduce selenium to its elemental form and precipitate other metals
as sulfide complexes. The microbes also reduce the concentration of nitrogen
present in the wastewater." Id.
The data presented in EPA's 2011 Effluent Limits Report was collected over several
years of operation, with samples collected at various intervals during the following
periods: March 2009 to May 2011 for Allen Station; and February 2008 to May 2011
21 As mentioned above, see section 3.10, EPA also recognizes that PSNH's proposed
treatment system also includes a "polishing step" intended to further reduce mercury levels. See also
sections 5.4 and 5.5.11, below.
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for Belews Creek. See EPA's 2011 Effluent Limits Report, p. 6-7 for specifics.
Furthermore, the data used to determine effluent limits were generated using
sufficiently sensitive analytical methods. EPA believes that this data set is
appropriate to use in developing BPJ-based BAT limits for Merrimack Station
because it represents long-term performance that reflects variability in the systems.
Appropriate analytical and statistical methods were applied to the data to derive
daily maximum and monthly average effluent limits for this Draft Permit.
The Duke Energy data was thoroughly reviewed and certain values were excluded
prior to calculating limits. EPA excluded or corrected data: (1) associated with the
treatment system commissioning period; (2) collected during treatment system
upsets; (3) not representative of a typical well -operated treatment system; (4)
generated using insufficiently sensitive analytical methods; and (5) determined to
be extreme values or "outliers". In addition, EPA corrected certain data errors (e.g.,
data entry errors) to differentiate from the excluded data. EPA's 2011 Effluent
Limits Report provides more information about the data points excluded.
A modified delta -lognormal distribution was selected to model the pollutant data
sets for each plant, except for chromium, and to calculate long-term averages, daily
variability factors and monthly variability factors. The long-term averages and
variability factors for each pollutant from both plants were then combined (i.e.,
median of long-term averages and mean of each variability factor). Generally, daily
maximum and monthly average limits were determined by taking the product of the
combined long-term average and the combined daily or monthly variability factor.
EPA's 2011 Effluent Limits Report provides more information about the effluent
limits determinations.
In addition to the sources described above, EPA also considered information
presented by the permittee. Specifically, in PSNH's, December 3, 2010 Report, in
response an EPA's information request under CWA §308(a), PSNH identified the
concentrations of pollutants that it predicted would be present in the discharge from
the new Merrimack Station FGD wastewater treatment system. Yet, EPA
generally considers the multi-year data from actual operations at the Duke Energy
plants to provide a superior basis for setting permit limits than the facility's ,
projections given that (1) EPA is determining limits reflecting the BAT, not merely
the limits that reflect the performance of Merrimack Station's WWTS, (2) PSNH's
projected values do not reflect actual operations, and (3) Merrimack Station may
have an incentive to understate, rather than overstate, the pollutant removal
capabilities of its proposed treatment technologies in order to receive less stringent
permit limits. That said, for certain pollutants not limited using the Duke Energy
data, EPA did rely more directly upon the company's projections.
Based on the above considerations, EPA's approach to setting permit limits for
specific pollutants in the wastewater from Merrimack Station's FGD WWTS is
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described below.
(1) For arsenic, chromium, copper, mercury, selenium, and zinc, EPA
calculated limits based on analysis of the Duke Energy data, as presented in
EPA's 2011 Effluent Limits Report.
(2) With regard to the remaining pollutants that might be present in the FGD
wastewater, EPA determined for some that it would be appropriate to base
limits on the levels that PSNH projected could be achieved by its new FGD
WWTS, while for others EPA determined that it would not be appropriate to
develop a BPJ-based BAT or, as appropriate, BCT limit at this time.22
The new NPDES permit will also require effluent monitoring to produce actual
discharge data to support an assessment of whether permit limits should be made
more or less stringent in the future.
5.2 Compliance Location
EPA has developed effluent limits for Merrimack Station's FGD WWTS to be
applied at internal outfall 003C. This location is appropriate for technology-based
limits because the FGD WWTS effluent will be diluted by, and include interferences
from, other waste streams prior to discharge to the Merrimack River. See 40 C.F.R.
§§ 122.45(h) and 125.3(f). These aspects would make monitoring and analysis
impracticable downstream from this location.
According to PSNH, Merrimack Station's FGD wastewater will be directed to the
slag settling pond (internal outfall 003A) that currently receives the following waste
streams: slag (bottom ash) transport wastewater, overflow from slag tanks and
storm water from miscellaneous yard drains, boiler blow -down, treated chemical
metal cleaning effluent through internal outfall 003B, and other miscellaneous and
low volume wastes such as flow from demineralizer regeneration, chemical drains,
equipment and floor drains, miscellaneous tank maintenance drains, the yard
service building floor drain sump, as well as wastewater consisting of pipe trench
storm water, and ash landfill leachate. The FGD wastewater flow will be an
average 0.07 MGD compared to the flow into the pond from the other sources, which
is approximately 5.3 MGD (average) to 13 MGD (maximum). The magnitude of the
dilution, along with the commingling of sources that contain similar pollutants,
would make it difficult or impracticable to measure compliance of the FGD
wastewater with technology-based limits at the pond sampling location (outfall
003A). Therefore, to ensure the effective control of the pollutants in Merrimack
22 Generally, EPA believes that the application of the wastewater treatment to achieve compliance
with the BAT limits specified in the Draft Permit will also inevitably result in the removal of other
pollutants not limited in the permit.
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Station's FGD WWTS effluent, the new Draft Permit imposes the effluent limits,
and requires compliance monitoring, at internal outfall 003C, prior to the FGD
wastewater being mixed with other waste streams.
5.3 Pollutants of Concern in FGD Wastewater
EPA began the process of establishing BPJ-based BAT limits by considering those
constituents identified in EPA's 2009 Detailed Study Report, at p. 6-3, as "the most
frequently cited pollutants in coal combustion wastewater associated with
environmental impacts." This list also includes many of the pollutants that were
evaluated under the NHDES anti -degradation review.
In addition, as part of the next permit reissuance proceeding, EPA expects to assess
whether permit limits should be added for additional specific pollutants or whether
limits for certain pollutants could be dropped. EPA expects that this assessment
will be based on a review of effluent data collected at the facility and any relevant
new NELGs that may have been promulgated and supporting information that may
have been developed. Table 5-1,, reproduced from the EPA's 2009 Detailed Study
Report, discusses the potential for environmental harm from each pollutant
compound "depending on the mass pollutant load; wastewater concentration, and
how organisms are exposed to them in the environment." EPA's 2009 Detailed
Study Report, p. 6-3.
Table 5-1 Selected Coal, Combustion Wastewater Pollutants
Compound
Potential Environmental Concern
Frequently observed in high concentrations in coal combustion wastewater;
Arsenic
causes poisoning of the liver in fish and developmental abnormalities; is
associated with an increased risk of cancer in humans in the liver and bladder.
Can cause fish kills because of a lack of available oxygen; increases the toxicity of
BOD
other pollutants, such as mercury. Has been associated with FGD wastewaters
that use organic acids for enhanced SO2 removal in the scrubber.
Frequently observed in high concentrations in coal combustion wastewater;
Boron
leachate into groundwater has exceeded state drinking water standards; human
exposure to high concentrations can cause nausea, vomiting, and diarrhea. Can
be toxic to vegetation.
Elevated levels are characteristic of coal combustion wastewater -impacted
Cadmium
systems; organisms with elevated levels have exhibited tissue damage and organ
abnormalities.
Sometimes observed at high concentrations in coal combustion wastewater
Chlorides
(dependent on FGD system practices); elevated levels observed in fish with liver
and blood abnormalities.
Elevated levels have been observed in groundwater receiving coal combustion
Chromium
-)wastewater leachate; invertebrates with elevated levels require more energy to
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support their metabolism and therefore exhibit diminished growth.
Coal combustion wastewater can contain high levels; invertebrates with elevated
Copper
levels require more energy to support their metabolism and therefore exhibit
diminished growth.
Leachate from impoundments has caused, elevated concentrations in nearby
Iron
surface water; biota with elevated levels have exhibited sublethal effects
including metabolic changes and abnormalities of the liver and kidneys.
Concentrations in coal combustion wastewater are elevated initially, but lead
settles out quickly; leachate has caused groundwater to exceed state drinking
water standards. Human exposure to high concentrations of lead in drinking
Lead
water can cause serious damage to the brain, kidneys, nervous system, and red
blood cells. Manganese Coal combustion wastewater leachate has caused elevated
concentrations in nearby groundwater and surface water; biota with elevated
levels have exhibited sublethal effects including metabolic changes and
abnormalities of the liver and kidneys.
Biota with elevated levels have exhibited sublethal effects including metabolic
changes and abnormalities of the liver and kidneys; can convert into
Mercury
methylmercury, increasing the potential for bioaccumulation; human exposure at
levels above the MCL for relatively short periods of time can result in kidney
damage.
Nitrogen
Frequently observed at elevated levels in coal combustion wastewater;
may cause eutrophication of aquatic environments.
Acidic conditions are often observed in coal combustion wastewater; acidic
p H
conditions may cause other coal combustion wastewater constituents to dissolve,
increasing the fate and transport potential of pollutants and increasing the
potential for bioaccumulation in aquatic organisms.
Phosphorus
Frequently observed at elevated levels in coal combustion wastewater; may cause
eutro hication of aquatic environments.
Frequently observed at high concentrations in coal combustion wastewater;
readily bioaccumulates; elevated concentrations have caused fish kills and
numerous sublethal effects (e.g., increased metabolic rates, decreased growth
Selenium
rates, reproductive failure) to aquatic and terrestrial organisms. Short term
exposure at levels above the MCL can cause hair and fingernail changes; damage
to the peripheral nervous system; fatigue and irritability in humans. Long term
exposure can result in damage to the kidney, liver, and nervous and circulatory
systems.
Total dissolved
High levels are frequently observed in coal combustion wastewater; elevated
solids
levels can be a stress on aquatic organisms with potential toxic effects; elevated
levels can have impacts on agriculture & wetlands.
Frequently observed at elevated concentrations in coal combustion wastewater;
Zinc
biota with elevated levels have exhibited sublethal effects such as requiring more
energy to support their metabolism and therefore exhibiting diminished growth,
and abnormalities of the liver and kidneys.
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5.4 The BAT for Controlling Merrimack Station's FGD Wastewater
PSNH has installed a wet FGD system utilizing a limestone forced oxidation
scrubber (LSFO). Most plants that utilize this type of scrubber system produce a
commercial -grade gypsum by-product and a wastewater stream. Such wastewater
streams require treatment for the removal of solids and pollutants prior to
discharge. As explained previously:
[t]he FGD system works by contacting the flue gas stream with a
slurry stream containing a sorbent. The contact between the streams
allows for a mass transfer of sulfur dioxide as it is absorbed into the
slurry stream. Other pollutants in the flue gas (e.g., metals, nitrogen
compounds, chloride) are also transferred to the scrubber slurry and
leave the FGD system via the scrubber blowdown (i.e., the slurry
stream exiting the FGD scrubber that is not immediately recycled back
to the spray/tray levels).
See EPA's 2009 Detailed Study Report, p. 4-15. PSNH plans to purge the scrubber
slurry from the FGD on a regular, periodic (i.e., not continuously) basis tomaintain
suitable scrubber chemistry (70,000 gpd average).23 Hydroclones (a centrifugal
device) will be used to separate the solid gypsum from the liquid component of the
scrubber slurry. This liquid component will be directed to the FGD WWTS and will
contain chlorides, heavy metals, dissolved gypsum and other inert suspended solids.
As previously described, PSNH is installing a physical/chemical precipitation
treatment system to remove pollutants from the wastewater prior to discharging
the effluent to the Merrimack River. EPA reviewed physical/chemical treatment
(i.e., chemical precipitation) as a technology and compared the systems described in
EPA's 2009 Detailed Study Report and EPA's June 7, 2010 Guidance Memorandum
with the system being installed at Merrimack Station. All of these systems have a
series of reaction tanks in which precipitation and coagulation take place and in
which insoluble metal hydroxides and metal sulfides are formed. This is,followed by
solids settling and physical removal. This treatment method is used at
approximately 30 power plants in the U.S. See EPA's June 7, 2010 Guidance
Memorandum, Attachment A, p. 4. Approximately half of these plants — as well as
Merrimack Station's FGD WWTS — also add sulfide precipitation to the treatment
process for more efficient removal of mercury and other metals.
In addition to physical/chemical treatment, three plants in the U.S. incorporate a
biological treatment stage, added after chemical precipitation and solids removal,
23 PSNH has indicated that the scrubber purge rate may need to be increased, depending on
actual operating characteristics of the scrubber system. According to PSNH, the discharge flow may
increase to 100,000 gpd. Such an increase would not, however, affect the technology-based and
water quality -based permitting evaluations.
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specifically for reducing levels of dissolved selenium. Two additional U.S. plants
operate biological treatment for removing selenium, but these plants use settling
ponds instead of physical/chemical treatment prior to the biological treatment step.
There are another four plants that incorporate a biological treatment stage
following chemical precipitation and solids removal, but the biological stage at these
four plants is a sequencing batch reactor that is operated at ORP levels that
optimize the removal of nitrogen compounds instead of selenium. See EPA's June 7,
2010 Guidance Memorandum, Attachment A, p. 4.
The evidence reviewed by EPA indicates that physical/chemical treatment with
biological treatment will remove selenium, additional dissolved metals and other
pollutants from the FGD wastewater, beyond the level of removal achieved by
physical/chemical treatment alone, and that adding a biological treatment stage is
an available, cost-effective technological option.24 In addition, EPA's evaluation
concluded that additional removals of mercury could be attained through the use of
the proprietary adsorbent media (or "polishing step"), which PSNH is installing on
the "backside" of the new physical/chemical treatment system. Therefore, EPA has
determined that the combination of physical/chemical treatment with biological
treatment and the polishing step (for removal of mercury) are components of BAT
for the control of FGD wastewater at Merrimack Station. EPA's determination that
these technologies are components of BAT for the facility is also supported by EPA's
above-described consideration of the BAT factors specified in the statute and
regulations. Therefore, statistical analysis was performed on the data from the
effluent of the physical/chemical and biological treatment systems at Belews Creek
and Allen Stations to calculate limits for certain pollutants in the Merrimack
Station Draft Permit, as described in this document. With regard to mercury, as
also discussed below, the Draft Permit limit is based on use of the polishing medium
in the physical/chemical treatment system.
Finally, for chlorides and total dissolved solids (TDS), EPA has determined that the
BAT for Merrimack Station's FGD wastewater is not based on treatment/removal of
these compounds. Instead, the BAT for these constituents is based on the operating
characteristics of the FGD scrubber. As described below, the chloride and TDS
levels in the discharge will be determined by the FGD scrubber purge rate, which is
an operational set -point that will be established by the plant. A scrubber's set -point
is determined largely by the maximum amount of chlorides (one component of TDS)
allowable in the FGD system without causing corrosion of the equipment. Thus, it
is based on the most vulnerable materials of construction.
24 In fact, in 2003, at "The 19th Annual International Conference on Soils, Sediments and
Water", representatives from Applied Biosciences Corporation reported that "Applied Biosciences
has developed the ABMetTM microbial bioprocess for the removal of metals and inorganics from
industrial and other waters.... and has demonstrated removal of As, Se, Cu, Ni, Zn, Hg, Cd, Cr, Te,
NO3, CN, and NH3." See htti):Hscholarworks.umass.edu/soils conf abstracts/2Conference Co -Direct.
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While EPA has based these BAT technology-based effluent limits on either an
available treatment train consisting of 1) physical/chemical treatment, 2) the PSNH
polishing step, and 3) biological treatment, or the operational conditions of the
scrubber', PSNH may meet these limits using any means legally available.
5.5 Effluent Limits
5.5.1 Arsenic
Although PSNH projects that Merrimack Station's physical/chemical treatment
system will be able to achieve a level of 20 ug/L for total arsenic, EPA has
determined that physical/chemical treatment (with or without the biological
treatment stage) can achieve lower arsenic levels. Therefore, the new Draft Permit
includes BAT limits of 15 ug/L (daily maximum) and 8 ug/ L (monthly average) for
total arsenic at internal outfall 003C. These limits are primarily based on the
analysis in EPA's 2011 Effluent Limits Report.
5.5.2 SOD
Although EPA's October 29, 2010, information request directed PSNH to identify
what it regarded to be an achievable BOD concentration limit for its FGD
wastewater, the company failed to identify an attainable level.
In EPA's 2009 Detailed Study Report, p. 5, the Agency explained that:
[b]iochemical oxygen demand (BOD) is a measure of the quantity of
oxygen used by microorganisms (e.g., aerobic bacteria) in the oxidation
of organic matter. The primary source of BOD in coal combustion
wastewater is the addition of organic acid buffers to the FGD
scrubbers.
Organic acids are added to some FGD scrubbers to improve the SO2 removal
efficiency of the systems. Merrimack Station does not, however, plan to add organic
acid buffers to its newly installed FGD system, obviating any concern about high
BOD levels in the wastewater. In addition, there is presently little data available
concerning BOD levels in FGD wastewater from which to determine effluent limits.
See Duke Energy data and EPA's 2009 Detailed Study Report.
In light of the above considerations, EPA has determined that including a BPJ-
based BCT limit for BOD is not appropriate at this time. However, the Draft
Permit requires the permittee to sample and report BOD5 levels in the FGD effluent
to support consideration of whether or not BOD limits might be needed in the
future.
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Determination of Technology -Based Effluent Limits for the Flue Gas
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The Draft Permit requires weekly sampling. After weekly sampling data has been
collected for at least six months, after an initial startup period of six months, the
permittee may request a reduction in monitoring for BOD at this location. The
permittee may submit a written request to EPA seeking a review of the BOD test
results. EPA will review the test results and other pertinent information to make a
determination of whether a reduction in testing is justified. The frequency of BOD
testing may be reduced to no less than one test per year. The permittee is required
to continue testing at the frequency specified in the permit until the permit is either
formally modified or until the permittee receives a certified letter from the EPA
indicating a change in the permit conditions.
As part of the next permit reissuance proceeding, EPA plans to reassess whether a
BOD permit limit should be added to the permit based on consideration of any new
NELGs that may have been promulgated and a review of monitoring data and any
other relevant new information. As always, new information could also potentially
support future permit modifications during the term of the new permit.
5.5.3 Boron
Although EPA's October 29, 2010 information request directed PSNH to identify
what it regarded to be an achievable boron concentration limit for its FGD
wastewater, the company did not identify an attainable level.
EPA's research indicates that FGD wastewaters contain a wide range of total boron
levels. This highly variable range is seen in the power plant self-monitoring data
submitted to EPA and presented in EPA's 2009 Detailed Study Report25, as well as
in the Allen Station and Belews Creek data that was recently submitted to EPA
upon request. It is presently unclear whether and at what level boron may be found
in Merrimack Station's FGD wastewater.
Boron is one of several pollutants that are almost exclusively present in the dissolved
phase. In addition, boron is not easily removed by physical/chemical treatment with
or without the biological treatment stage. See EPA's 2009 Detailed Study Report p.
4-18. Also see EPA's June 7, 2010 Guidance Memorandum, Attachment A, p.4.
Therefore, EPA has determined that it cannot reasonably set a BPJ-based BAT limit
for boron at this time.' Consequently, the Draft Permit requires the permittee to
sample and report boron levels in the FGD waste stream but does not propose a
technology-based effluent limit.
As part of the next permit reissuance proceeding, EPA currently plans to assess
25 A range of 17,000 to 474,000 ug/L of total boron was reported for two plants utilizing
physical/chemical treatment, and from 7,820 to 666,000 ug/L of total boron for two plants that use
biological treatment. EPA's 2009 Detailed Study Report, pp. 4-65 and 4-67.
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whether a boron permit limit should be added based on consideration of any new
NELGs that may have been promulgated and a review of monitoring data and any
other relevant new information. As always, new information could also potentially
support future permit modifications during the term of the new permit.
5.5.4 Cadmium
PSNH projects that Merrimack Station's physical/chemical treatment system will
be able to achieve a level of 50 ug/L• for total cadmium. Although there is evidence
that some plants have discharged FGD wastewater with lower cadmium levels,26
there is insufficient information at this time upon which to prescribe a cadmium
limit lower than that proposed by PSNH.27 Therefore, EPA is basing the Draft
Permit limit on PSNH's projected level of 50 ug/L. As part of the next permit
reissuance proceeding, EPA expects to assess whether this cadmium permit limit
should be adjusted based on consideration of any new NELGs that may have been
promulgated and a review of monitoring data and any other relevant new
information. As always, new information could also potentially support future
permit modifications during the term of the new permit.
5.5.5 Chlorides
EPA has found no evidence to suggest that physical/chemical treatment with or
without the biological treatment stage is effective in removing chlorides. The
chloride level in the discharge will be determined by the FGD scrubber purge rate,
which is an operational set -point that will be established by the plant. A scrubber's
set -point is determined largely by the maximum amount of chlorides allowable for
preventing corrosion of the equipment, thus it is based on the most vulnerable
materials of construction. PSNH proposed that the FGD WWTS at Merrimack
Station would discharge up to 18,000 mg/L chlorides.28 Therefore, this value is
chosen as the BAT -based Draft Permit limit for Merrimack Station. As part of the
26 Self-monitoring cadmium data from three plants utilizing physical/chemical treatment
ranged from 0.07 — 21.9 ug/L (18 samples) and from one plant using biological treatment ranged
from ND (0.5) — 3.57 ug/L (37 samples). EPA's 2009 Detailed Study Report, pp. 4-65 and 4-67. An
anoxic/anaerobic biological treatment system can reduce metals such as selenium, arsenic, cadmium,
and mercury, by forming metal sulfides within the system. Id. at 4-32. See also Duke Energy data
from Allen and Belews Creek Stations.
27 An anoxic/anaerobic biological treatment system can reduce metals such as selenium,
arsenic, cadmium, and mercury, by forming metal sulfides within the system. EPA's 2009 Detailed
Study Report, p.4-32. EPA's 2009 Detailed Study Report shows that self-monitoring cadmium data
from three plants utilizing physical/chemical treatment ranged from 0.07 — 21.9 ug/L (18 samples)
and from one plant using biological treatment ranged from ND (0.5) — 3.57 ug/L (37 samples). See
also Duke Energy data from Allen and Belews Creek Stations.
28 Self-monitoring chloride data from two plants utilizing physical/chemical treatment
ranged from 4,700 — 20,500 mg/L (21 samples). EPA's 2009 Detailed Study Report, p. 66.
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Determination of Technology -Based Effluent Limits for the Flue Gas
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next permit reissuance, EPA plans to assess whether this chloride permit limit
should be adjusted based on consideration of any new NELGs that may have been
promulgated and a review of monitoring data and any other relevant new
information. As always, new information could also potentially support future
permit modifications during the term of the new permit.
5.5.6 Chromium
PSNH did not report an achievable concentration of total chromium as requested by
EPA's October 29, 2010, information request. However, PSNH did report projected
levels of 50 ug/L and 100 ug/L for trivalent and hexavalent chromium, respectively.
Chromium is more likely found in the particulate, rather than the dissolved, phase
in scrubber blowdown. Therefore, it is more easily removed in the treatment
process. In the Draft Permit, EPA is proposing a daily maximum limit of 10 ug/L
for total chromium at internal outfall 003C based primarily on the analysis
presented in EPA's 2011 Effluent Limits Report. Based on data restrictions for
chromium from the Duke Energy plants, no monthly average limit was calculated.
See EPA's 2011 Effluent Limits Report. EPA expects to reconsider whether a
monthly average limit should be added to the permit during the next permit
reissuance proceeding based on consideration of any new NELGs that may have
been promulgated and a review of monitoring data and any other relevant new
information. As always, new information could also potentially support future
permit modifications during the term of the new permit.
5.5.7 Copper
PSNH projects that Merrimack Station's physical/chemical treatment system will
be able to achieve a level of 50 ug/L for total copper. EPA has determined, however,
that physical/chemical treatment with or without the biological treatment stage can
achieve lower copper levels. In particular, EPA is proposing in the Draft Permit a
daily maximum limit of 16 ug/L and a monthly average limit of 8 ug/L for total
copper at internal outfall 003C based primarily on the analysis presented in EPA's
2011 Effluent Limits Report.
5.5.8 Iron
Although PSNH projects that Merrimack Station's treatment system will be able to
achieve a discharge concentration of 100 ug/L for iron, EPA has determined on a
BPJ basis that BAT limits for iron are not appropriate at this time. Ferric chloride
will be added in the FGD physical/chemical treatment process at Merrimack Station
to co -precipitate a variety of heavy metals in the wastestream and further promote
the coagulation of suspended solids. Generally, EPA does not set effluent limits for
parameters that are associated with wastewater treatment chemicals, assuming
that system and site controls demonstrate good operation of the treatment
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technology.29
Consequently, the Draft Permit requires the permittee to sample and report iron
levels in the FGD waste stream but does not propose a technology-based effluent
limit. As part of the next permit reissuance proceeding, EPA expects to reassess
whether an iron limit would be appropriate based on consideration of any new
NELGs that may have been promulgated and a review of monitoring data and any
other relevant new information. As always, new information could also potentially
support future permit modifications during the term of the new permit.
5.5.9 Lead
Lead can be effectively removed by physical/chemical treatment, such as the system
installed at Merrimack Station, and PSNH predicts that the FGD WWTS installed
at Merrimack Station will be able to achieve a total lead discharge concentration of
100 ug/L. This value is within the range of self-monitoring lead data collected in
response to EPA's 2009 Detailed Study Report.30 EPA is basing the Draft Permit
limit on PSNH's projected value of 100 ug/L because the Agency does not have
sufficient data from which to calculate an alternative BAT -based lead limit for
Merrimack's FGD WWTS at this time. As part of the next permit reissuance
proceeding, EPA expects to assess whether this permit limit for lead should be
adjusted based on consideration of any new NELGs that may have been
promulgated and a review of monitoring data and any other relevant new
information. As always, new information could also potentially support future
permit modifications during the term of the new permit.
29 For example, the Development Document for the December 2000 Centralized Waste
Treatment Final Rule, page 7-1, states that "EPA excluded all pollutants which may serve as
treatment chemicals: aluminum, boron, calcium, chloride, fluoride, iron, magnesium, manganese,
phosphorus, potassium, sodium, and sulfur. EPA eliminated these pollutants because regulation of
these pollutants could interfere with their beneficial use as wastewater treatment additives."
(htti)://water.el)a.gov/scitech/wastetech/guide/treatment/upload/2000 10 19 guide cwt fina develop
ch7. d Similarly, the Development Document for the October 2002 Iron and Steel Manufacturing
Point Source Category Final Rule, page 12-1, states that "EPA excluded all pollutants that may
serve as treatment chemicals: aluminum, boron, fluoride, iron, magnesium, manganese, and sulfate
(several other pollutants are commonly used as treatment chemicals but were already excluded as
POCs). EPA eliminated these pollutants because regulation of these pollutants could interfere with
their beneficial use as wastewater treatment additives."
(http://water.epa.gov/scitech/wastetech/guide/ironsteel/u-oload/2003 05 27 guide ironsteel reg tdd s
ectionsl2-17.pdf)
30 Self-monitoring data for lead from four plants using physical/chemical treatment ranged
from ND (0.07) to 11 ug/L (47 samples). In addition, one plant using biological treatment reported
lead ranging from ND(1.9) to 291 ug/L (37samples). EPA's 2009 Detailed Study Report, pp 4-65 and
4-67.
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Determination of Technology -Based Effluent Limits for the Flue Gas
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5.5.10 Manganese
PSNH projects that Merrimack Station's treatment system can achieve a
manganese level of 3000 ug/L. This is within the wide range of values that EPA
collected during the development of EPA's 2009 Detailed Study Report (see pages 4-
65 and 4-67).
Although manganese is one of several pollutants entering treatment systems almost
entirely in the dissolved phase (see EPA's 2009 Detailed Study Report, pp. 4-18 and
4-26), there is some evidence suggesting that physical/chemical treatment can
achieve some removal of manganese from FGD system wastewater. See FGD Flue
Gas (FGD) Wastewater Characterization and Management: 2007 Update, 1014073,
Final Report, March 2008 (EPRI Project Manager P. Chu). At the same time,
however, EPA presently has only a very limited data pool for manganese in FGD
system wastewater. As a result, the Agency has determined based on BPJ that the
BAT limit for manganese is the level projected by PSNH and this level has been
included as a limit in the Draft Permit.
As part of the next permit reissuance proceeding, EPA expects to assess whether
this permit limit for manganese should be adjusted based on consideration of any
new NELGs that may have been promulgated and a review of monitoring data and
any other relevant new information. As always, new information could also
potentially support future permit modifications during the term of the new permit.
5.5.11 Mercury
Mercury is one of several metals that may potentially be removed more effectively
by biological treatment than physical/chemical treatment alone. Based on the
analysis presented in EPA's 2011 Effluent Limits Report, EPA would prescribe BAT
limits for total mercury discharges from Merrimack Station's FGD WWTS of 0.055
ug/L (daily maximum) and 0.022 ug/L (monthly average). Merrimack Station
projects even better performance, however, from its physical/chemical treatment
system with the addition of the previously mentioned "polishing step." This
polishing step involves the use of two sets of proprietary adsorbent media targeted
specifically for mercury. In particular, PSNH projects that its proposed treatment
system can achieve a limit of 0.014 ug/L. Therefore, EPA has included a technology-
based limit of 0.014 ug/L (daily maximum) in the Draft Permit to control the
discharge of mercury in the effluent from Merrimack Station's FGD WWTS based
on the company's newly installed physical/chemical treatment system with the
added polishing step.
5.5.12 Nitrogen
While biological treatment systems can remove both selenium and nitrogen
compounds, the treatment systems currently operating have not been optimized for
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the removal of both types of contaminants. Instead, these treatment systems have
been optimized for the removal of one or the other.
Seven power plants in the U.S. are operating or constructing treatment
systems that follow physical/chemical treatment with a biological treatment
stage.... Three of these systems use a fixed film anoxic/anaerobic bioreactor
optimized to remove selenium from the wastewater.... Four power plants
operate the treatment system with the biological stage optimized for nitrogen
removal by using a sequencing batch reactor to nitrify and denitrify the
wastewater and produce very low concentrations of both ammonia and
nitrates.
EPA's June 7, 2010 Guidance Memorandum, Attachment A, p. 4. Although
biological treatment systems remove nitrates in the process of removing selenium,31
it is unclear to what extent, if any, biological treatment affects ammonia -nitrogen
and other nitrogen compounds, unless a process such as nitrification is added.
In determining the BAT for Merrimack Station, EPA has decided that the
biological treatment system should be optimized for selenium removal due to the
toxicity and bioaccumulation potential of that contaminant. (EPA discusses the
Draft Permit's selenium limits further below.) Although PSNH predicts that the
newly installed FGD WWTS — without biological treatment — can achieve discharge
levels of <350 mg/L of ammonia -nitrogen (NH3-N) and <350 mg/L for
nitrates/nitrites (NONNO2-N), EPA cannot reasonably set a total nitrogen limit at
this time because the level of total nitrogen likely to remain in Merrimack Station's
FGD WWTS effluent after biological treatment that has been optimized for
selenium removal is uncertain. The added biological treatment stage will likely
remove some nitrogen, but EPA is unable to quantify likely discharge levels at this
time.
The Draft Permit does require the permittee to sample and report nitrogen levels in
the FGD wastewater stream. As part of the next permit reissuance, EPA plans to
assess whether a nitrogen permit limit should be added based on consideration of
any new NELGs that may have been promulgated and a review of monitoring data
and any other relevant new information. As always, new information could also
potentially support future permit modifications during the term of the new permit.
31 Both Allen and Belews Creek Stations employ anoxic/anaerobic biological treatment of
their FGD wastewater, optimized for the removal of selenium compounds. EPA's 2011 Effluent
Limits Report, page 4, indicates that for each plant, "[t]he bioreactor portion of the treatment train
consists of bioreactor cells containing activated carbon media and microbes which reduce selenium to
its elemental form and precipitate other metals as sulfide complexes. The microbes also reduce the
concentration of nitrogen present in the wastewater." See also Duke Energy data.
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5.5.13 pH
As previously discussed, Merrimack's FGD wastewater will be directed to the slag
settling pond that currently receives numerous waste streams including bottom ash
transport water, metal cleaning effluent, low volume wastes, and stormwater. The
FGD wastewater flow (70,000 gpd) will be diluted by the other waste streams in the
pond (5.3 MGD (average) to -13 MGD (maximum)). EPA has determined that
monitoring for pH is not necessary at internal outfall 003C. EPA's March 21, 1986,
Memorandum from Charles Kaplan, EPA, to Regional Permit Branch Chiefs and
State Directors, explains that using dilution to accomplish the neutralization of pH
is preferable to adding chemicals when commingling low volume waste with once
through cooling water. EPA is using this same approach in this case and has
determined that including a BPJ-based, BCT limit for pH is not necessary or
appropriate at this time. See Merrimack Station Fact Sheet for the explanation of
the water quality -based pH limit at outfall 003A (slag settling pond).
5.5.14 Phosphorus
PSNH did not project a particular concentration of phosphorus that could be
achieved by Merrimack Station's new FGD WWTS, as was requested by EPA's
October 29, 2010 information request.
Similar to iron,, phosphorus may be added (or used) in the FGD wastewater
treatment process. Anoxic/anaerobic biological treatment systems remove selenium
and other compounds using suspended growth or fixed film reactors comprised of a
bed of activated carbon (or other supporting medium) on which microorganisms (i.e.,
site-specific bacteria cultures) live. A common food source used consists of a
molasses -based nutrient mixture that contains carbon, nitrogen, and phosphorus.32
As discussed above, EPA generally does not set technology-based effluent limits for
parameters that are associated with wastewater treatment chemicals. See footnote
29 of this document. Therefore, EPA has determined, using BPJ, that BAT limits
for phosphorus are not appropriate at this time. Consequently, the Draft Permit
requires the permittee to sample and report phosphorus levels in the FGD waste
stream but does not propose technology-based effluent limits. EPA expects to
reconsider whether a phosphorus limit would be appropriate during the next permit
reissuance proceeding based on consideration of any new NELGs that may have
been promulgated and a review of monitoring data and any other relevant new
information. As always, new information could also potentially support future
permit modifications during the term of the new permit.
32 United States Patent, Sep. 7, 2010, No. 7,790,034 B2, Apparatus and Method for Treating
FGD Blowdown or Similar Liquids, p. 11. This patent, assigned to Zenon Technology Partnership
indicates that the wastewater flow through the system "may already contain sufficient phosphorus
and so there may be no need for phosphorus in the nutrient solution."
(http://data.il)thoughts.com/l)ublication/09102010/TJS7790034)
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5.5.15 Selenium
PSNH reported that FGD wastewater at Merrimack Station could be treated to
achieve 9,000 ug/L total selenium using physical/chemical processes. However,
EPA has determined that physical/chemical treatment with an added biological
treatment stage results in much lower selenium levels. "Biological treatment,
specifically fixed -film anoxic/anaerobic bioreactors when paired with a chemical
precipitation pretreatment stage, is very effective at removing additional pollutants
such as selenium and nitrogen compounds (e.g., nitrate, nitrites)." EPA's 2009
Detailed Study Report, p. 4-50. EPA is'proposing a daily maximum limit of 19 ug/L
and a monthly average limit of 10 ug/L for total selenium at internal outfall 003C
based primarily on the analysis presented in EPA's 2011 Effluent Limits Report.
5.5.16 Total Dissolved Solids
PSNH projects that the FGD WWTS at Merrimack Station will be able to achieve a
level of total dissolved solids (TDS) of 35,000 mg/L, which is well above the, range of
data reported in EPA's 2009 Detailed Study Report.33 At the same time, however,
EPA finds no current evidence toysuggest that physical/chemical treatment (with or
without the biological treatment stage) effectively removes TDS.34 The chlorides
level in the, discharge will be determined by how the FGD scrubber purge is
managed and represents a substantial component of the TDS. Thus, the controlling
factors for the TDS effluent concentration are similar to those described for
chlorides. Therefore, the BAT limit is based on how the company manages its
scrubber and not on the actual treatment system for the blowdown. The Draft
Permit limit in this case is PSNH's projected value of 35,000 mg/L. In addition, as
part of the next permit reissuance proceeding, EPA plans to assess whether this
TDS permit limit should be adjusted based on consideration of any new NELGs that
may have been promulgated and a review of monitoring data and any other relevant
new information. As always, new information could also potentially support future
permit modifications during the term of the new permit.
5.5.17 Zinc
PSNH projects that Merrimack Station's physical/chemical treatment system can,
achieve a level of 100 ug/L. However, other plants evaluated by EPA show that
lower limits can consistently be achieved using this technology. EPA is proposing a
daily maximum limit of 15 ug/L and monthly average limit of 12 ug/L for total zinc
33 Self-monitoring data from one plant (16 samples) using physical/chemical treatment
ranged from 12,000 — 23,000 mg/L. In addition, the range from two plants (52 samples) with
biological treatment is 2,500 — 23,000 mg/L. EPA's 2009 Detailed Study Report, pp. 4-66 and 4-67.
34 EPA reported that "...the figures [2008 monitoring data from Belews Creek and Roxboro
stations] show that TDS is not significantly removed by the settling pond, the chemical precipitation
system, or the biological treatment system." EPA's 2009 Detailed Study Report, p. 4-51.
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Determination of Technology -Based Effluent Limits for the Flue Gas
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at internal outfall 003C based primarily on the analysis presented in EPA's 2011
Effluent Limits Report.
5.6 Summary of Effluent Limits
The following table summarizes the Draft Permit limits for outfall location 003C —
FGD WWTS and the rationale for each of the BPJ-based BAT limits:
Table 5-2 Draft Permit Limits for Outfall 003C
Compound/ Units
Maximum
Monthly
BAT Limit
Daily Limit
Average Limit
Based On
Flow
Report
Report
---
Arsenic (ug/L)
15
8
EPA calculations
Boron (ug/L)
Report
Report
no BAT numerical effluent
limit at this time
Cadmium (ug/L)
50
Report
PSNH projected value
Chromium (ug/L)
10
Report
EPA calculations
Copper (ug/L)
16
8
EPA calculations
Iron (ug/L)
---
Report
no BAT numerical effluent
limit at this time
Lead (ug/L)
100
Report
PSNH projected value
Manganese (ug/L)
3,000
Report
PSNH projected value
PSNH projected value
Mercury (ug/L)
0.014
Report
(physical/chemical w/
polishing step)
Selenium (ug/L)
19
10
EPA calculations
Zinc (ug/L)
15
12
EPA calculations
BOD,(mg/L)
Report
Report
no BCT numerical effluent
limit at this time
Chlorides (mg/L)
18,000
Report
PSNH projected value
Nitrogen (mg[L)
Report
Report
no BAT numerical effluent
limit at this time
pH
---
---
water quality -based range
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5.7 Sufficiently Sensitive Analytical Methods
To prevent undetected exceedances of these permit limits, EPA's Draft Permit
requires sufficiently sensitive analytical methods to be used for compliance
monitoring purposes. EPA recommends that "for purposes of permit applications
and compliance monitoring, a method is `sufficiently sensitive' when (1) the method
quantitation level is at or below the level of the applicable water quality criterion
for the pollutant, or (2) the method quantitation level is above the applicable water
quality criterion, but the amount of pollutant in a facility's discharge is high enough
that the method detects and quantifies the level of pollutant in the discharge."
EPA's June 7, 2010 Guidance Memorandum, Attachment A, p. 6. Therefore, the
Merrimack Draft Permit includes a provision for outfall location 003C that the
permittee is required to use EPA approved methods that are sufficiently sensitive to
measure each FGD pollutant at concentrations low enough to determine
compliance.
Furthermore, as currently indicated on EPA's Steam Electric Power Generating
website page:
[w]astewater from flue gas desulfurization (FGD) systems can contain
constituents that may interfere with certain laboratory analyses, due to high
concentrations of total dissolved solids (TDS) or the presence of elements
known to cause matrix interferences. EPA has observed that, during
inductively coupled plasma — mass spectrometry (ICP -MS) analysis of FGD
wastewater, certain elements commonly present in the wastewater may
cause polyatomic interferences that bias the detection and/or quantitation of
certain elements of interest. These potential interferences may become
significant when measuring trace elements, such as arsenic and selenium, at
concentrations in the low parts -per -billion range.
As part of a recent sampling effort for the steam electric power generating
effluent guidelines rulemaking, EPA developed a standard operating
procedure (SOP) that was used in conjunction with EPA Method 200.8 to
conduct ICP -MS analyses of FGD wastewater. The SOP describes critical
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at outfall 003A
Phosphorus (mg/L)
---
Report
no BAT numerical effluent
limit at this time
TDS (mg/L)
35,000
Report
PSNH projected value
5.7 Sufficiently Sensitive Analytical Methods
To prevent undetected exceedances of these permit limits, EPA's Draft Permit
requires sufficiently sensitive analytical methods to be used for compliance
monitoring purposes. EPA recommends that "for purposes of permit applications
and compliance monitoring, a method is `sufficiently sensitive' when (1) the method
quantitation level is at or below the level of the applicable water quality criterion
for the pollutant, or (2) the method quantitation level is above the applicable water
quality criterion, but the amount of pollutant in a facility's discharge is high enough
that the method detects and quantifies the level of pollutant in the discharge."
EPA's June 7, 2010 Guidance Memorandum, Attachment A, p. 6. Therefore, the
Merrimack Draft Permit includes a provision for outfall location 003C that the
permittee is required to use EPA approved methods that are sufficiently sensitive to
measure each FGD pollutant at concentrations low enough to determine
compliance.
Furthermore, as currently indicated on EPA's Steam Electric Power Generating
website page:
[w]astewater from flue gas desulfurization (FGD) systems can contain
constituents that may interfere with certain laboratory analyses, due to high
concentrations of total dissolved solids (TDS) or the presence of elements
known to cause matrix interferences. EPA has observed that, during
inductively coupled plasma — mass spectrometry (ICP -MS) analysis of FGD
wastewater, certain elements commonly present in the wastewater may
cause polyatomic interferences that bias the detection and/or quantitation of
certain elements of interest. These potential interferences may become
significant when measuring trace elements, such as arsenic and selenium, at
concentrations in the low parts -per -billion range.
As part of a recent sampling effort for the steam electric power generating
effluent guidelines rulemaking, EPA developed a standard operating
procedure (SOP) that was used in conjunction with EPA Method 200.8 to
conduct ICP -MS analyses of FGD wastewater. The SOP describes critical
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Determination of Technology -Based Effluent Limits for the Flue Gas
Desulfurization Wastewater at Merrimack Station in Bow, New Hampshire
technical and quality assurance procedures that were implemented to
mitigate anticipated interferences and generate reliable data for FGD
wastewater. EPA regulations at 40 CFR 136.6 already allow the analytical
community flexibility to modify approved methods to lower the costs of
measurements, overcome matrix interferences, or otherwise improve the
analysis. The draft SOP developed for FGD wastewater takes a proactive
approach toward looking for and taking steps to mitigate matrix
interferences, including using specialized interference check solutions (i.e., a
synthetic FGD wastewater matrix).
http://water.epa.gov/Scitech/wastetech/guide/steam index.cfm. EPA's draft "FGD ICP/MS
Standard Operating Procedure: Inductively Coupled Plasma/Mass Spectrometry for
Trace Element Analysis in Flue Gas Desulfurization Wastewaters," dated May 2011
is available at this website page or directly at
http://water.gpa.gov/scitech/wastetech/guide/upload/steam draft sop.pdf. PSNH is
encouraged to make this document available to its contract laboratory as an
alternative approach to mitigate matrix interferences during the analysis of
Merrimack Station's FGD wastewater.
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