NC0004961_Comments behalf of Catawba Riverkeeper_20150505

SOUTHERN ENVIRONMENTAL LAW CENTER
Telephone [phone] 601 WEST ROSEMARY STREET,SUITE 220 Facsimile 919-929-9421
CHAPEL HILL,NC 27516-2356
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Re: Draft NPDES Wastewater Permit—Riverbend Steam Station,#NC0004961
Dear Mr. Zimmerman:
On behalf of the Catawba Riverkeeper Foundation, Inc. (the "Foundation"), 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 Riverbend Steam Station("Riverbend") coal ash lagoons owned and operated by Duke
Energy Carolinas LLC ("Duke") into Mountain Island Lake ("the Lake") on the Catawba River.
As set forth below,the proposed permit violates the Clean Water Act("CWA") because,
among other things, it purports to allow uncontrolled leakage from this wastewater treatment
facility, rather than requiring the leaks to be stopped by removing the ash and wastewater from
the retired Riverbend site.
•
I. Introduction
Mountain Island Lake is the drinking water supply reservoir for almost one million
people in the Charlotte region. Duke's unlined coal ash lagoons loom 80 feet above the banks of
the Lake and contain 2.7 million tons of wet coal ash held back only by leaking earthen berms.
The lagoons leach coal ash pollutants into the groundwater and leak streams of contaminated
water that flow into the Lake.
The Foundation's sampling has revealed that the unpermitted streams of contaminated
water, referred to as"seeps,"flowing from the coal ash lagoons into the Lake are discharging
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numerous coal ash pollutants, including arsenic, cobalt, manganese, iron, boron, barium,
strontium, and zinc.
In at least five instances, arsenic has been found in the surface water of Mountain Island
Lake itself in excess of the state water quality standard, including one sample that was more than
twice the maximum contaminant level. In addition, the residues from the drinking water
treatment facility at Mountain Island Lake removed during the treatment process contain notably
high levels of arsenic. Zinc has also been found in Mountain Island Lake near Riverbend at
almost four times the water quality standard.
Moreover, Duke University scientists have documented significant coal ash pollution of
Mountain Island Lake. In a study that sampled shallow pore water from the lake bottom, the
Duke University scientists found arsenic concentrations of 240 parts per billion(ppb) in the
drinking water supply reservoir downstream from the Riverbend lagoons. That is 24 times the
maximum contaminant level of 10 ppb set by the state and the U.S. Environmental Protection
Agency ("EPA"). Laura Ruhl, Avner Vengosh, et al., The Impact of Coal Combustion Residue
Effluent on Water Resources:A North Carolina Example, Environmental Science & Technology
12,226, 12,231 (2012) (Attachment A).
The study also found that arsenic, manganese, and iron discharged from the Riverbend
coal ash lagoons can erupt from the lake bottom into the surface water during periods of low
dissolved oxygen in the summer months. Id. at 12,230. During such an event,the erupting
arsenic is converted from arsenate to a more toxic form, arsenite. Id.
On May 24, 2013, DENR filed a verified complaint with the Mecklenburg County
Superior Court in which DENR stated—under oath—that Duke's unpermitted discharges to
Mountain Island Lake violate state law and that"without . . . taking corrective action,"these
seeps and groundwater violations"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."
Verified Complaint& Motion for Injunctive Relief,State of North Carolina ex rel. N.C. DENR,
DWQ v. Duke Energy Carolinas, LLC,No. 13 CVS 9352 (Mecklenburg Co., May 24, 2013)
(Attachment B), at¶67. As a result, DENR asked the court to enter a permanent injunction
requiring Duke "to abate the violations of N.C. Gen. Stat. § 143-215.1,NPDES Permits and
groundwater standards" at Riverbend. Id. Prayer for Relief¶2.
Rather than following through on its sworn statements and publicly announced intention
to obtain injunctive relief and corrective action, DENR is now proposing to grant Duke amnesty
for the numerous leaks emerging from its coal ash wastewater treatment lagoons. This approach
is contrary to sound public policy and violates the Clean Water Act. DENR should require that
Duke adopt the best available technology to stop the leaks and discharges of polluted
wastewater: remove the coal ash and wastewater from the lagoons.
2

II. Permit Comments
A. The Proposed Permit Violates the CWA's Best Available Technology Requirements
Any NPDES permit issued by DENR for the Riverbend facility must incorporate the
Clean Water Act's requirement of best available technology to eliminate discharges if the facility
is capable of achieving such elimination. In this case, all the other utilities in the Carolinas are
already implementing a guaranteed approach to eliminating their discharges: removal of their
unlined coal ash to dry, lined landfill storage or recycling.
1. Removal of the Unlined Coal Ash Is the Best Available Technology for Eliminating
the Riverbend Discharges
Under the Clean Water Act, polluters must control their discharges of pollutants using the
best available technology economically achievable ("BAT"): "such effluent limitations shall
require the elimination of discharges of all pollutants if the Administrator finds . . . that such
elimination is technologically and economically achievable." 33 U.S.C. § 1311(b)(2)(A). There
can be no question that the Riverbend seeps contaminated with residual coal ash that has settled
out of the impoundment are, like any other waste stream, subject to TBELS and an independent
BAT analysis. The EPA requires 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).
In the absence of promulgated effluent limitation guidelines, the NPDES permit writer
must use best professional judgment("BPJ")to determine the BAT standard applicable to the
coal ash discharges at Riverbend. 33 U.S.C. § 1342(a)(1)(B); 40 C.F.R. § 125.3; 15A N.C.
Admin. Code 2H .0118. When applying BPJ, "[i]ndividual judgments []take the place of
uniform national guidelines, but the technology-based standard remains the same." Texas Oil&
Gas Ass'n V. U.S. E.P.A., 161 F.3d 923 (5th Cir. 1998). In other words, the DWR must operate
within strict limits when identifying BAT based on BPJ.
The first step in identifying BAT is identifying available technologies. At a minimum,
technological availability is "based on the performance of the single best-performing plant in an
industrial field." Chem. Mfrs. Ass'n 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 other words, if the technology is being applied by any
plant in the industry, it is achievable. 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").
But determination of technological availability is not limited to a single industrial field.
"Congress contemplated that EPA might use technology from other industries to establish the
[BAT]." 780 F.2d at 453. International facilities can also be used to define BAT. Am. Frozen
Food Inst. v. Train, 539 F.2d 107, 132 (D.C. Cir. 1976). EPA's NPDES Permit Writers' Manual
3

states that "BAT limitations may be based on effluent reductions attainable through changes in a
facility's processes and operations. . . . even when those technologies are not common industry
practice." Even pilot studies and laboratory studies can be used to establish BAT; the
technology need not be in commercial use to be considered available. See American Paper Inst.
v. Train, 543 F.2d 328, 353 (D.C. Cir. 1976).
In sum, BAT requires "a commitment of the maximum resources economically possible
to the ultimate goal of eliminating all polluting discharges." EPA v. National Crushed Stone
Ass'n, 449 U.S. 64, 74 (1980) (emphasis added).
An available and economically achievable technology to eliminate Duke Energy's
Riverbend coal ash discharges is being used today by all the other major utilities in the Carolinas
—and it eliminates the risk of a dam failure at the same time. This technology is excavation and
removal of the coal ash to dry, lined landfill storage or concrete recycling.
a. SCE&G
In South Carolina, on the same river currently being polluted by Duke's Riverbend
facility, 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. Attachment C. 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. Attachment D, at 26. SCE&G has also
stated publicly that its cleanup has had no effect on customer rates. Eric Connor, "Coal ash
cleanup: Someone will pay; will it be customers?" Greenville News (Apr. 28, 2014).
b. Santee Cooper
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.
Attachment E. 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 like
Riverbend had contaminated the groundwater and adjacent wetlands with arsenic and other
pollutants. Attachment F. Santee Cooper has removed over 100,000 tons from its Jefferies
Generating Station in Moncks Corner, SC. David Wren, "Coal ash removal at Santee Cooper's
power plants years ahead of schedule,"Post& Courier(Jan. 26, 2015). And it will begin
removing the coal ash from its Winyah Generating Station in Georgetown, SC, later this year.
Id. Santee Cooper also states that its actions to eliminate the unlined storage of coal ash will have
EPA,NPDES Permit Writers' Manual(Sept.2010)at p. 5-16,available at:
http://water.epa.gov/polwaste/npdes/basics/upload/pwm_2010.pdf.
4

no effect on its rates. Jim Pierobon, "Smart Utilities Know There Are Responsible Solutions for
Their Coal Ash Waste," The Energy Fix(Jan. 12, 2015).
c. Duke Energy—South Carolina
•
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 G. Duke will remove all the 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 H.
Duke Energy's other coal ash site in South Carolina is the H.B. Robinson facility on Lake
Robinson and Black Creek in Darlington County, SC. This site contains approximately 4.2
million tons of coal ash. It 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).
d. Duke Energy—North Carolina
Duke Energy has publicly committed to clean up all its unlined coal ash storage at
Riverbend, along with three other facilities in North Carolina. Tonya Maxwell, "Duke
announces coal ash removal plans across 4 NC sites," WCNC(Nov. 13,2014). Duke's public
commitment to clean up Riverbend and the other sites is proof positive that dewatering and ash
removal are achievable as BAT to stop the ongoing discharges of coal ash pollutants from the
Riverbend lagoons. Accordingly, ash removal should be required in the NPDES permit for
Riverbend in order to ensure the discharges are stopped and not subject to later corporate or
legislative changes.
In sum, excavation and dry, lined storage of coal ash formerly stored in unlined, leaking
lagoons is already standard practice among all the other major utilities in the Carolinas, and
Duke has committed to clean up six of its coal ash sites as well. Removal of the ash to dry, lined
storage is not only economically achievable but cost effective, according to the utilities putting it
into practice. 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.
Accordingly, DENR must incorporate into the NPDES permit provisions requiring the
dewatering and excavation of the unlined coal ash from these leaking impoundments at
Riverbend, in combination with a reasonable.schedule of compliance to achieve the CWA's goal
of eliminating the discharge of pollutants to public waters.
5

2. The N.C. Coal Ash Management Act Is Not a Substitute for Clean Water Act
Protections
As currently written,the N.C. Coal Ash Management Act would require Duke Energy
to remove the ash from the Riverbend lagoons. However, that state statutory requirement does
not eliminate the need for a Clean Water Action pollution elimination permit that requires the
Best Available Technology for treating—and eliminating—water pollution. Apart from any
requirements in the Coal Ash Management Act,this Clean Water Act permit must require the
cleanup of these primitive coal ash storage sites and the removal of the ash to safe, dry, lined
storage.
First, the Coal Ash Management Act may be amended or repealed by the N.C.
legislature at any time. Indeed, the State of North Carolina has argued before the N.C. Supreme
Court that the Coal Ash Management Act itself weakened existing North Carolina protections of
groundwater against coal ash pollution. The current existence of a state statutory requirement is
no guarantee that that requirement will exist throughout the term of this NPDES permit.
Second,the Clean Water Act's requirements apply independent of and separate from
any state statute. DENR 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. As explained in the preceding section, the Clean Water Act itself
requires the cleanup of these primitive and defective coal ash storage sites and removal of the ash
to safe, dry, lined storage away from the River.
Finally,the Coal Ash Management Act itself provides that it is in addition to any other
provisions of law. By its own terms,the existence of the Coal Ash Management Act does not
obviate the obligation of DENR to put in place a Clean Water Act permit that carries out the
requirements and purposes of the Clean Water Act, including the available and economically
achievable elimination of the discharges at Riverbend.
3. The Proposed Permit's Authorization of the Seeps Violates the BAT Requirements
The proposed permit would authorize Duke's wastewater treatment facility to simply
spring leaks and discharge "uncontrolled releases" directly into waters of the United States. As
discussed in more detail below, this blanket authorization of unknown quantities of point source
discharges is a fundamental violation of the CWA.
But in addition, this approach violates the CWA's requirement that polluters like Duke
Energy control their discharges using the best available technology. The proposed permit would
allow Duke Energy to avoid using key components of even its existing, minimal treatment
technology of settling out pollutants in the lagoons and skimming discharge water from the top
via risers connected to the permitted outfalls. This is an impermissible step backwards from
using available treatment technology, and accordingly it violates the CWA's BAT requirements.
6

4. The Draft Permit Acknowledges That Zero Discharge Is Attainable For Seeps But
Fails To Impose Corresponding TBELS Or Any Schedule Of Completion.
The fact sheet itself concedes a zero discharge technological solution available to Duke
Energy to address coal ash seeps, but DENR has failed to impose TBELs based on that
technology.
The Fact Sheet acknowledges, with respect to seeps at the Riverbend plant,that
"[r]eleases of this nature would typically be addressed through an enforcement action requiring
their elimination . . . ." The Fact Sheet further recognizes the availability of a zero discharge
solution—collection and"rerouting the discharge" and"discontinuing the discharge"are
available solutions for meeting technology-based effluent limits. Condition A(5)n.4.
Nonetheless, DENR requires no action from Duke Energy to complete those measures, deferring
instead to the eventual completion of a parallel state process under the Coal Ash Management
Act. But a deferred and unenforceable promise of future action under a separate state statute
does not satisfy the requirements of the federal Clean Water Act.
First, the state process under CAMA is not a substitute for compliance with North •
Carolina's duties under the Clean Water Act pursuant to its delegated program. Apart from any
requirements in the Coal Ash Management Act,this Clean Water Act permit must require the
cleanup of these primitive coal ash storage sites and the removal of the ash to safe,dry, lined
storage. DENR 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 Clean
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).
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 more. DENR must require compliance
with the discharge limits achievable by the implementation of the best available technology now.
EPA regulations unambiguously prohibit the use of compliance schedules to comply with
BAT requirements. EPA defines a compliance schedule as"a schedule of remedial measures, . .
. including an enforceable sequence of interim requirements (for example, actions, operations, or
milestone events) . . . ." 40 C.F.R. § 122.2. 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 statutory deadline under the CWA."40 C.F.R. §
122.47(a)(1)(emphasis added). The Clean Water Act requires dischargers of color pollution to
comply with BAT-based effluent limits by March 31, 1989. 33 U.S.C. §1311(b)(2)(A), (F).
Thus,"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
7

standards . . . have passed." EPA Permit Writers Manual, Section p. 9-8 (2010);see 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 had 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). 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.
B. The Proposed Permit Allows Uncontrolled Leaks from the 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.17)purports to authorize any leaking streams of
contaminated coal ash wastewater discharging from the Riverbend lagoons into Mountain Island
Lake 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.
1. 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, "Every 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
8

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 wastestreams because it
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" (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 Riverbend.
•
2. The Proposed Permit Attempts to Shield Duke from Further Legal
Violations
The seeps are prohibited under Duke Energy's current NPDES permit. As DENR itself
acknowledges in the Fact Sheet, "uncontrolled releases" of leaking wastewater should be the
subject of an enforcement action requiring their elimination. Indeed, DENR has filed such an
action in state Superior Court. Moreover,the United States Department of Justice has charged
Duke Energy with criminal violations of the Clean Water Act for exactly such unpermitted
discharges, including at Riverbend. Duke has indicated publicly it will plead guilty to all the
charges and pay $102 million as a result of its criminal violations of law.
Shockingly, DENR's proposed permit purports to legalize these previously illegal
discharges with the stroke of a pen, rather than requiring Duke to take any action to remedy the
violations. Even more shockingly, DENR is proposing to grant Duke amnesty for unknown
numbers of future violations of the CWA as well. This is nothing more than an attempt to shield
Duke Energy from having to comply with the laws it has been violating for years. DENR's
approach is aimed at protecting Duke, not the public, and is an affront to law-abiding North
Carolinians.
3. The Proposed Permit Violates the CWA by Purporting to Authorize a
Leaking Wastewater Treatment Facility
This blanket authorization of uncontrolled leaks is contrary to the permitting of this site
as a wastewater treatment facility. Duke Energy is allowed to discharge from this point source
on the basis that the coal ash lagoons are wastewater treatment facilities. 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 leaks. DENR would be permitting a wastewater treatment facility that is
fundamentally defective, because the system does not discharge treated water through its
designed treatment process and does not contain the pollutants removed by its designed
9

treatment system. By purporting to incorporate these unidentified leaks into the permit without
even knowing what pollutants they discharge or where they discharge, DENR would allow Duke
to continue operating a defective and dysfunctional wastewater treatment system that leaks
uncontrolled streams of contaminated wastewater, including new wastewater streams that DENR
would purport to incorporate into the permit without an application or permit modification, as the
CWA requires.
In this way,the proposed permit defeats the purpose of the waste treatment system
authorized by the permit. The lagoons treat the waste streams they receive by settling in the
lagoons. Water is discharged from the top of the lagoon via a riser system that leaves the more
polluted wastewater and settled pollutants in the lagoon. If the lagoons are allowed to leak from
their sides and bottom,this system is circumvented. The pollutants that have been settled and
stored in the lagoons cannot be allowed to pollute public waters, or else the entire purpose and
function of the waste treatment system would be undone.
For the same reasons,these existing and future leaks are in no sense an"outfall" and
cannot be permitted as a mythical "Outfall 010." This is not a legitimate permitted "outfall"but
a total fiction to allow discharges that violate the Clean Water Act.
DENR does not issue permits to sewage treatment plants that authorize them to spring
uncontrolled leaks. The proposed permits are a prime example of DENR giving Duke Energy
special treatment.
4. 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, the permit would allow Duke and
DENR to evade the Clean Water Act entirely for these new and undescribed outfalls and
discharges.
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, 40 U.S.C. § 122.63,none of which condone the
administrative addition of a new point source discharge,which must be permitted as an NPDES
outfall. 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
10

for the life of this permit. This scheme is inconsistent with the requirements of the Clean Water
Act.
The existing permit and all prior ones are the result of the full agency process,public
review,public comment, and the procedures required by the Clean Water Act and North Carolina
law. These illegal flows of polluted water into Mountain Island Lake, forbidden by the existing
permit, cannot be made legitimate by totally changing the permit to allow contaminated water to
pop out of this purported wastewater treatment facility and flow into the Lake. It is
inconceivable that a permitted wastewater treatment facility would be allowed to repeatedly open
up leaks and discharge polluted water from the supposed wastewater treatment lagoons into a
drinking water reservoir. This proposed option is not law enforcement or pollution elimination
at all, but instead an option for the law enforcement agency to try to find a way to make unlawful
and polluting activities "permitted" and avoid dealing with the risks to the public. This stratagem
should not be adopted by a state agency that has the responsibility of enforcing the law and
protecting the State's natural resources and the public interest.
Instead,this permit should require the implementation of the proven method of
eliminating seeps from these defective wastewater treatment systems—movement of the ash to
safe, dry lined storage and appropriate dewatering of the lagoons.
C. The Proposed Permit Violates the Clean Water Act's Anti-Backsliding Provisions
The proposed 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 that are 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. And 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.
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 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. § 122.44(1)(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, not just
effluent limits based on BPJ. 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
11

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, allow Duke Energy to avoid using even its
existing treatment technology in favor of"uncontrolled releases." Fact Sheet at 3. 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 mythical "outfall"; (3) allow uncontrolled and undesigned releases from a permitted
wastewater treatment facility; (4)allow a permitted wastewater treatment facility to leak and
spew polluted water from the facility into State waters and navigable waters; (5)allow a
permitted wastewater facility to operate in a way that circumvents and goes around its permitted
and designed treatment system and to leak and discharge polluted water; (6) allow the facility to
release discharges that are prohibited under its current permit; and(7) create a new meaning and
permitted category of"outfall"to allow uncontrolled,undesigned, and unpredicted leaks and
flows of polluted water.
For the same reasons,the proposed permit's attempt to authorize the seeps violates the
CWA's anti-backsliding provisions because it is inconsistent with the Removed Substances
provision of the current Riverbend NPDES permit, which provides an important limitation in the
permit to prevent the entrance of pollutants removed in the course of settling treatment from
entering State and navigable waters.
The State of North Carolina has included an important standard condition in its NPDES
permits for waste treatment systems like the Riverbend lagoons, known as the Removed
Substances provision. The Removed Substances provision of the current Riverbend NPDES
permit, Part II.C.6,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 any pollutant from such materials from entering waters of the State or
navigable waters of the United States."(emphasis added)
This is a common-sense provision to prevent pollutants removed by waste treatment
facilities from escaping out into the environment. 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 Riverbend 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 protect 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); 40 C.F.R. § 440.148(c) (Removed Substances provisions ensure that"measures
shall be taken to assure that pollutants materials removed from the process water and waste
streams will be retained in storage areas") (emphasis added).
12

In the context of the Riverbend permit, the removed substances provision is also the
implementation of a required permit component under the implementing regulations of the Clean
Water Act. The implementing regulations for the Clean Water Act 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 issued to
Duke Energy for the Riverbend plant, DENR did not set individual TBELs for seeps from the
ash basin but rather took the only responsible step, of treating zero liquid discharge 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 any discharge of removed substances to waters of the United States.
DENR itself has cited Duke Energy for violating the Removed Substances provision by
allowing pollutants to enter waters of the State and 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: "Failure 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)." Part
II.C.6 of the Dan River NPDES Permit contains the Removed Substances permit provision.
At Riverbend,the proposed permit purports to allow pollutants removed in the course of
treatment to enter waters of the State and United States via what DENR admits are "uncontrolled
releases"that may spring out of the lagoons and start discharging to public waters at any time.
As such,the proposed permit's approach to authorizing the seeps violates the existing permit's
Removed Substances Provision, and to the extent it is inconsistent with the Removed Substance
Provision, it violates the CWA's anti-backsliding requirements in this additional way.
D. The Effluent Limitations in the Proposed Permit Are Too Weak
In addition to the fundamental problems described above, DENR's proposed effluent
limits and monitoring of the seeps do not satisfy the technology-based treatment requirements of
the CWA. 33 U.S.C. §§ 1311, 1342(a)(1); 40 C.F.R. § 125 ("Technology-based treatment
requirements under section 301(b) of the Act represent the minimum level of control that must be
• imposed in a permit issued under section 402 of the Act" (emphasis added)). Where
promulgated effluent limitation guidelines are not available,the NPDES permit writer must use
best professional judgment("BPJ")to determine the best available technology applicable to the
discharge.2 "When issuing permits according to its BPJ, EPA is required to adhere to the
technology-based standards set out in § 1311(b) . . . States issuing permits pursuant to § 1342(b)
stand in the shoes of the agency, and thus must similarly pay heed to § 1311(b)'s technology-
based standards when exercising their BPJ." NRDC v. U.S. EPA, 859 F.2d 156, 183 (D.C. Cir.
1988) (citing NRDC v. Costle, 568 F.2d 1369, 1380-81 (D.C. Cir. 1977)).
2 Memorandum from the Director of Office of Wastewater Mgmt.,U.S.EPA,on NPDES permitting of Wastewater
Dischrages from Flue Gas Desulphurization and Coal Combustion Residuals Impoundments at Steam Electric
Power Plants(June 7,2010)(hereinafter,"the Hanlon Memo"),Attachment I.
13

In this case,the effluent limitations are deficient for a number of reasons. DENR must
add limits for more pollutants associated with coal ash, strengthen the current TBELs, require
more frequent monitoring, and take into account lack of flow in the receiving water body.
1. More TBELs Are Needed
First, the permit sets technology-based effluent limitations (TBELs) for only four
pollutants: arsenic, selenium,mercury, and nitrate/nitrite as N. This truncated list is inadequate
and leaves mercury as the sole proxy for the mobility of all heavy metals. Coal ash can contain
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.
•
Thus, relying on mercury as the only TBEL metal means significant contaminants in the
Riverbend 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. For example, zinc has been found in the seeps, and it has been found in the surface
water of Mountain Island Lake near Riverbend at almost four times the water quality standard.
Other coal ash metals of concern include thallium and vanadium. Accordingly, TBELs need to
be added for thallium, vanadium, cadmium, nickel, and zinc.
In addition, the Foundation's own sampling has revealed concentrations of cobalt up to
52 times the standard in the seeps, as well as strontium and boron, so these substances must be
included in the effluent limitations for the seeps. For the same reason,these substances should
be added to the substances required to be sampled from the groundwater monitoring wells and to
the effluent limits for the permitted Outfall 002 at Riverbend.
All the effluent limitations for the Outfall 002 discharge should also apply to the seeps
because the seeps come from the coal ash lagoons. Indeed,the need for technology-based
effluent limits for the seeps is greater because these seeps, by definition, avoid the existing
treatment technology of the riser structures connected to the permitted Outfall 002 pipe.
Similarly, limits for Total Nitrogen and Total Phosphorus should be added, rather than just
monitor and report.
EPA's Merrimack coal ash NPDES permit developed TBELs for many more pollutants
than DENR did for Riverbend'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 J. 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 the DENR permit.
14

2. The TBELs Proposed in the Draft Permit Are Too Weak
Several of these four"TBEL" effluent limitations are themselves too weak.
First, DENR does not appear to have performed an adequate analysis of available
treatment technologies, either at North Carolina coal ash facilities or elsewhere. Permit writers
must look to resources such as EPA guidance, reports and similar documents, and more
sophisticated permits from other states to appropriately set BAT and BPJ limits.3
For example, an EPA-issued TBEL determination for the Merrimack Station in Bow,NH
quotes EPA's Hanlon Memo stating that"[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." Accordingly, EPA determined it should impose these
technology treatment requirements as well. Attachment J. (Subsequently,the Merrimack
facility installed an even more sophisticated zero liquid discharge system, and EPA has now put
out new draft NPDES permits to reflect the facility's ability to eliminate these discharges of
pollutants.)
In the draft Riverbend permit, DENR states that it based its TBELs on the "95th
percentile of the effluent data" discharging over five years from Duke Energy's Allen, Marshall,
and Belews Creek facilities. Fact Sheet at 4-5. Significantly, Allen and Belews Creek were
among the facilities examined in the EPA Merrimack analysis. Attachment J at 32.
However,the TBELs contained in the draft NPDES permit for Riverbend are
significantly higher than the Merrimack limits, even though they are supposedly based on the
same facilities analyzed by EPA for Merrimack, including Allen and Belews Creek. Thus,
DENR appears not to have performed the same rigorous TBEL analysis that EPA did, nor does it
appear to have looked to more sophisticated effluent analyses and treatment technologies like the
Merrimack facility.
For example, the arsenic limit in these permits is higher than the Merrimack limit.
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
Merrimack,NH 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 J at 39. But in the Riverbend draft permit,the monthly average limit for arsenic is
set at 10.5 ug/L.
Moreover, Mountain Island Lake already has significant arsenic contamination from the
Riverbend coal ash lagoons. As described above in the Introduction, the surface water of
Mountain Island Lake has been shown to contain concentrations of arsenic well above the MCL
on at least five occasions,the downstream water treatment systems have to remove significant
3 Permit Writers Manual(1996)at 71-73.
15

quantities of arsenic in order to make the water drinkable, and Duke University scientists have
found extremely high concentrations of arsenic in the lake sediments, where it can erupt in a
more toxic form when the temperature and dissolved oxygen conditions are right. Attachment A,
at 12,230-31. Accordingly,the discharges of arsenic to this drinking water supply reservoir from
Riverbend must be more tightly controlled,with a monthly average of no more than 8 ug/L.
Similarly,EPA's Merrimack permit limit for selenium set the monthly average at 10
ug/L, versus 13.6 ug/L in the Riverbend permit; and the Merrimack permit set a daily maximum
of 19 ug/L, verus 25.5 ug/L in the Riverbend permit. Attachment J at 47.
For Mercury, EPA noted that it could have set the monthly average limit at 22 ng/L,
versus 47 ng/L for Riverbend, 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. Id. at 44. If this limit is achievable in New Hampshire, it should
be achievable in North Carolina as well.
3. The Permit Fails to Set Rigorous Technology-Based Standards For Many Pollutants
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 1 is determined by multiplying the highest baseline seep
concentration levels by 10." It is nonsensical to say that the best available pollution control
technology is to take what is already happening at this site and allow far more pollution on top of
that. There are numerous problems with this approach.
First,taking an unknown"baseline seep concentration" and multiplying it by 10 does not
constitute the imposition of a technology-based effluent limitation, the minimum standard
allowed under the Clean Water Act. Moreover, water quality based standards cannot be used to
justify weaker limits. Water quality based effluent limits may be imposed only where they are
"more stringent"than technology based limits. 33 U.S.C. § 1311(b)(1)(C) (emphasis added). To
comply with the CWA, DENR needs to require that Duke Energy actually treat its discharges,
including the seeps,using the best available technology. There is no evidence in the permit or its
Fact Sheet that DENR has done this.
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. However, as
discussed in the preceding paragraph, water quality based limits must be more stringent than
technology based limits, not less stringent. An agency cannot use dilution or water quality
standards to allow a polluter to evade technology based standards being applied elsewhere. And
even if DENR were correct that the seeps would not cause surface water quality violations—a
claim the Foundation disputes, especially given the documented surface water quality violations
at Riverbend—there is absolutely no rationale for DENR to then multiply the seep
concentrations by 10 to set the effluent limits.
•
16

Second, 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
these limits were arrived at 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.
Third, DENR's numbers are wrong for Riverbend. The Foundation has sampled the
seeps at Riverbend, and has detected far higher concentrations of a variety of coal ash pollutants
in the seeps than DENR's Table 1 would indicate. For example, seeps sampled by the
Foundation at Riverbend contained cobalt at 52 times North Carolina's Interim Maximum
Allowable Concentration, along with boron, strontium, and zinc, among other pollutants. Yet
there is no limit for cobalt,boron, strontium, or zinc imposed in the permit. This oversight needs
to be corrected. Moreover, DENR's approach would seem to indicate that arsenic is only present
in the seeps at one-tenth the listed"maximum allowable parameter concentration"amount,
which would translate to an arsenic concentration in the seeps of just 1.45 ppb. But a seep at
Riverbend sampled by the Foundation contained arsenic at over 20 ppb. This discrepancy does
not mean DENR should simply raise the arsenic limit even higher—far from it. Instead, it means
DENR has not adequately considered the amount of pollutants currently flowing into Mountain
Island Lake, and needs to impose robust technology-based effluent limitations, rather than
downplaying the significance of the seep pollution flowing into the drinking water reservoir.
Fourth, the effluent limits and RPA are flawed because it is not appropriate to assume
that the waste stream is being diluted by the full flow of the Catawba River. The discharges
from the ash ponds, including the seeps, enter small coves and creeks rather than the main stem
of the Catawba. It should be noted that these coves may be used for fishing and recreation.
Surface water quality samples at Riverbend should also be taken from the coves where the waste
first enters the water. In addition, at many points in the day, there is little or no water moving
through Mountain Island Lake. Sometimes,the power plants use so much water that the water
discharged from the power plant moves upstream to the intake and concentrations are increased
rather than diluted. This problem will get worse as water use increases in the future.
4. More Monitoring Is Needed
•
The seeps need to be monitored more frequently. 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 for several reasons. 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 Mountain Island Lake.
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. For all these reasons, monitoring every two
weeks should be required until the lagoons are dewatered and removal begins.
17

•
E. Permitting the Seeps Is An Unsafe Approach
There is nothing about leaking streams of contaminated wastewater discharging to public
drinking water reservoirs like Mountain Island Lake that is necessary for dam safety. Yet in its
press release announcing the draft NPDES permit, DENR's Secretary said that"some" seeps
"are necessary to ensure the integrity of the dams." Tellingly, the draft NPDES permit and its
Fact Sheet make no such claims, and in fact DENR has acknowledged in other contexts that the
opposite is true. Seeps can weaken an embankment and cause it to fail.
In 2010, DENR stated in a dam safety Notice of Inspection:
"Two of the more common types of earth dam failures are caused or influenced
by excessive seepage. Excessive seepage can produce progressive internal
erosion of soil from the downstream slope of the dam or foundation toward the
upstream side to form an open conduit or `pipe.' Seepage pressures decrease the
strength characteristics of the embankment soil. The resulting reduction in
embankment stability can produce a slide failure of the downstream slope."
(emphasis added).
The 2010 DENR notice was issued regarding the Mayo Lake Dam in Roxboro, a High Hazard
dam. The Riverbend dam is also rated High Hazard, but the risks from a seepage-induced dam
failure are even greater here because the Riverbend lagoons contain coal ash and toxic pollutants,
and would spill directly into Mountain Island Lake,the drinking water supply reservoir for
nearly one million people in the Charlotte area.
In sum, the proposed permit's approach to the seeps places the drinking water supply for
nearly one million people at risk. The permit should require Duke Energy to stop the seeps by
dewatering the lagoons and removing their contents to dry, lined storage. Only this approach
will guarantee the safety of the public, the State's waters, and Mountain Island Lake.
F. The Proposed Permit Violates North Carolina's Groundwater Rules
1. DENR Must Impose Conditions To Prevent Further Groundwater Contamination
Because of the groundwater contamination at and beyond the compliance boundary at
Riverbend,the state groundwater rules prohibit DENR from issuing the proposed NPDES permit
for the Riverbend coal ash lagoons.
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). The draft permit states on its face that it
is issued under the authority of"North Carolina General State 143-215.1." The Riverbend coal
ash lagoons are disposal systems for purposes of the 2L groundwater rules, with compliance
boundaries set by the rules. 15A N.C.A.C. 2L .0107. Because DENR issues this permit under
18

authority delegated by the Environmental Management Commission,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 Riverbend. Indeed,
DENR has ordered Duke Energy to undertake assessment activities and filed an enforcement
case in Superior Court seeking injunctive relief to abate groundwater contamination at the site.
DENR's own complaint cites 59 exceedences of the groundwater standards at the Riverbend
compliance boundary between 2011 and 2013 alone. Between June 2013 and February 2015
(the most recent data available on DENR's website), groundwater monitoring data reveal at least
88 additional exceedences of the groundwater standards at Riverbend.
The groundwater violations at and beyond the compliance boundary will only continue,
in violation of the state groundwater rules, 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. A requirement for final closure of the Riverbend coal ash
impoundments and removal of the ash to dry, lined storage is the only assured solution to stop
ongoing violations of quality standards at the compliance boundary. Accordingly, the permit
should require removal of the ash to safe, dry lined storage.
2. DENR Must Define Proper Compliance and Review Boundaries and Require
Groundwater Monitoring Pursuant to the Groundwater Rule.
The groundwater rules direct 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 Riverbend facility. This is a critical omission.
Some maps issued by DENR for Riverbend have drawn the compliance boundary for the
facility so that it extends underneath Mountain Island Lake. But DENR cannot draw a
compliance boundary past the property boundary of Duke Energy. 15 NCAC 02L .0107(a), (b).
Because Mountain Island Lake 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 Mountain Island Lake 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.
In its 2014 application for renewal and reissuance of its NPDES permit, Duke Energy admits its
property line runs along the shoreline and does not extend into Mountain Island Lake. May 2014
Application, EPA Form 1, Figure 1, available at:
http://its.enr.state.nc.us/Weblink8/0/doc/250811/Page1.aspx. That should be the end of the
19

matter. Compliance boundaries cannot extend beyond a facility's property line. 15A N.C.A.C.
2L.0107(a). However, even if Duke Energy were to try to take the position that it owns title to
the lakebed of the Mountain Island Lake, Duke Energy cannot claim, and as a matter of federal
law DENR cannot issue, authorization to treat a water of the United States as a waste disposal
site.
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"RS" designation under the Groundwater Rule; and all lands carrying the RS
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). Accordingly,
DENR must require and make public all the results of groundwater monitoring within the
compliance boundary, including at current monitoring wells MW-9, MW-10, and MW-13.
Conclusion
The proposed permit violates the Clean Water Act and state laws, for the many reasons
set forth above. Authorizing Duke Energy's coal ash lagoons to spring leaks is contrary to the
requirements and purpose of the Clean Water Act, it is unsafe, and it unfairly gives special
treatment to Duke Energy at the expense of North Carolina's public waters. It is also exactly the
wrong approach when numerous families who live around coal ash lagoons throughout North
Carolina are currently being notified that their drinking water is contaminated and unsafe to
drink. Duke Energy and the other utilities in the Carolinas have already demonstrated they can
clean up coal ash lagoons and eliminate their polluted wastewater discharges; the Riverbend
permit should require no less.
20

Thank you for your consideration of these comments.
Sincerely,
Frank S. Holleman III
Senior Attorney �1
Nic olas S. Torrey
Staff Attorney
CC:
Gina McCarthy,EPA Administrator
Heather McTeer Toney, Regional Administrator, Region 4
21

Attachment A
The Impact of Coal Combustion Residue Effluent on Water
Resources: A North Carolina Example
(September 30, 2012)

•
Article
g pubs acs org/est
1111.1.111t11.1
The Impact of Coal Combustion Residue Effluent on Water
Resources: A North Carolina Example
Laura Ruhl,t'$ Avner Vengosh,*'t Gary S. Dwyer,t Heileen Hsu-Kim,* Grace Schwartz,*
Autumn Romanski,# and S. Daniel Smith#
'Division of Earth and Ocean Sciences, Nicholas School of the Environment, Duke University, Durham, North Carolina 27708,
United States
Department of Earth Science, University of Arkansas at Little Rock, Little Rock,Arkansas 72204, United States
Civil and Environmental Engineering,Pratt School of Engineering,Duke University,Durham,North Carolina 27708,United States
Surface Water Protection Section, Division of Water Quality, North Carolina Department of Environment and Natural Resources,
Raleigh, North Carolina 27609, United States
0 Supporting Information
ABSTRACT: The combustion of coal to generate electricity Coal Ash Ponds Distribution in the United States
produces about 130 million tons of coal combustion residues f -
(CCRs) each year in the United States; yet their environmental
Ire' ��F�'-�
implications are not well constrained. This study systematically i • •, .
documents the quality of effluents discharged from CCR settling •
'j
ponds or cooling water at ten sites and the impact on associated 1' •�. r
waterways in North Carolina, compared to a reference lake.We 1111Wil:
•�
measured the concentrations of major and trace elements in overfog
i
300 samples from CCR effluents, surface water from lakes and , er `� '
rivers at different downstream and upstream points, and pore
�..
water extracted from lake sediments. The data show that CCR • — . SW.
effluents contain high levels of contaminants that in several cases
• Coal Ash Ponds.n•1048 •,�
exceed the U.S.EPA guidelines for drinking water and ecological Rive s
effects. This investigation demonstrates the quality of receiving "x" A I y ter.•
waters in North Carolina depends on (1) the ratio between �� ��'250 '~ 750 1,000
effluent flux and freshwater resource volumes and(2)recycling of
trace elements through adsorption on suspended particles and release to deep surface water or pore water in bottom sediments
during periods of thermal water stratification and anoxic conditions. The impact of CCRs is long-term, which influences
contaminant accumulation and the health of aquatic life in water associated with coal-fired power plants.
• INTRODUCTION state regulatory bodies lack consistent monitoring and limit
Numerous studies have shown that effluents generated from requirements that are relevant to composition of CCR effluents.
Water in coal-fired power plants is used in steam production
leaching of coal combustion residues (CCRs) typically have
high concentrations of toxic elements."2 Yet,the overall impact and cooling as well as the transport of Co Rs from the plant to
of disposed CCR wastes on the quality of water resources in the holding ponds. In spite of some losses, the residual effluent
U.S.is largely unexplored, except in a few specific case-studies, water is discharged to the environment and is permitted
such as CCR spills 3'4 In the U.S., approximately six hundred through the National Pollution Discharge Elimination System
power plantss generate 130 million tons of CCRs annually,6 of (NPDES)Program.The NPDES Program as established by the
which 56% is stored in surface impoundments and landfills, Clean Water Act requires the control and permitting of point
while the remaining are reused for concrete, cement, and source discharges of wastewater!' Although the NPDES
construction industries. CCRs, encompassing fly ash, bottom regulations for CCR effluents disposal vary between states, in
ash,and flue gas desulfurization (FGD)material,represent one most cases they consist of only limited factors. For example,
the largest industrial waste streams in the U.S. and are not NC regulations follow the federal guiding permit limits for
classified as hazardous waste.8 Despite the large volume of CCR effluent discharge that indude only total suspended solids and .
effluents generated annually and their disposal into hundreds of -
surface water bodies, the environmental risks associated with Received: August 14,2012
these disposal practices are not well-known.Moreover,because Revised: September 23,2012
of the lack of CCR waste data,9 the effluents that are discharged Accepted: September 30,2012
from coal fired power plants and permitted by the national and Published: September 30, 2012
Nor ACS Publications a 2012 American Chemical Society 12226 dx.dol.org/10.1021/es303263xl Environ.Sci.Technol.2012,46,12226-12233

Environmental Science &Technology A ti,-I,
Belews Plant at s '
Belews Lake Dan River Plant r •� 1 -
' on the Dan River Roxboro Plant - - _
I at Hyco Lake p: - ' 4 ti
P.c' .../ ( 2.,
1,'! l •
N l r I
Asheville Plant at lake Julian '` - 1 I - ""r J
and the French Broad River i' 1 f Mayo Plant at
.. / .r .•s Mayo lake
rt. • r is
'� r / 1
....-;-;....._•,_ .-- /lir
ax
1.
. lk' AMC
ig41111" ) ._, ,\-- -- 1,1!".. ), :7 - (1, • -' ..r.i
. -
ce
..... . . .
. ,
• ....„,... ,,,,:.,..,: ,‘,A , '''.' • . ' •.-. '. . ''. • ' • I ' ....' , •"-'‘ / _.
Riverbend Plant '' . a:' . r Reference Lake
Marshall Plant ea ;'4 at Mountain Allen Plant at «....., r. Buck Plant at Jordan Lake
at Lake Norman Island Lake Lake Wylie High Rock Lake
Figure 1.Map of coal-fired power plants and CCR disposal sites to waterways in North Carolina that were investigated in this study.Also included is
a reference lake (Jordan Lake).
Table 1. Background Information on the Investigated Coal-Fired Electrical Power Plants, CCR Effluent Discharge through
NPDES Outfalls, and Associated Waterways in North Carolina"
ay.once-
through
coal-fired power size town ay.ash pond discharge cooling H2O scrubber effluent
plant site owner (MW) location flow(MGD) flow(MGD) water body basin system sampling
Roxboro Steam Progress 2558 Semora 11 1007 Hyco Lake Roanoke Wet FGD indirect
Station Energy System
Mayo Stream Progress 745 Roxboro 7 unkown Mayo Reservior Roanoke Wet FGD indirect
Station Energy System
Allen Steam Duke 1140 Belmont 15 5 Calawba River/Lake Calawba Wet FGD indirect
Station Wylie System
Marshall Steam Duke 2090 Terrell 8 1463 Calawba River/Lake Calawba Wet FGD indirect
Station Norman System
Belews Greek Duke 2240 Wallnut 9 1256 Dan River/Belews Roanoke Wet FGD
Steam Station Cove Lake System
Asheville Steam Progress 376 Arden 3 251 French Broad River/ French Wet FGD direct
Station Energy Lake Julian Broad System
Riverbend Steam Duke 454 Mount 4 375 Calawba River/ML Catawba None direct
Station Holly Island Lake
Buck Steam Duke 369 Salisbury 4 258 High Rock Lake Yadkin- None indirect
Station PeeDee
Dan River Steam Duke 276 Eden 1 201 Dan River Roanoke None direct
Station
Reference Lake No Power N/A Apex N/A N/A B.Everell Jordan Cape Fear None N/A
Plant Lake
'The size(in megawatts)of the plants as well as the amount of water discharged(in million gallons per day)in each plant are reported.Also listed is
the reference site,Jordan Lake.
oil and grease12 but do not include other constituent limits that In recent years, air regulations have become more stringent
could be relevant to CCR effluents,unless written in specifically (e.g., Interstate Clean Air Rule and Clean Air Act), requiring
by the permitting body. the capture of potential atmospheric pollutants, like sulfur
12227 dx.dol.org/10.1021/es303263x I Environ,Sci.Technol.2012,46,12226-12233

a
Environmental Science & Technology Article •
oxides (SOx). The FGD process effectively removes many of Fisher Scientific Inc.) direct current plasma optical emission
the volatile elements associated with the SQ. Most coal-fired spectrometry(DCP-OES).Both instruments were calibrated to
power plants in the U.S.do not have FGD scrubbers,but those the National Institute of Standards and Technology 1643e
with FGD capabilities produced 58% of the electricity standard, which was used at varying concentrations before,
generated from coal in the U.S. in 2010.13 Of those with after,and throughout sample runs.Internal standards of In,Th,
FGD scrubbers, most (up to 88% in 2010) use a wet FGD and Bi were spiked into all samples prior to measurement on
disposal system.' This process results in cleaner air emissions, the ICP-MS. The detection limit of the ICP-MS •of each
but the trade-off is significant enrichments of contaminants in element was determined by dividing three times the standard
solid wastes and wastewater discharged from power plants. deviation of repeated blank measurements by the slope of the
Several studies have shown that groundwater near these CCR external standard.The resulting values were then averaged(n=
disposal facilities was contaminated by CCR leachates,14 and 4) and are reported for trace elements measured on the ICP-
wildlife poisoning and environmental damages from CCR MS in Supporting Information Table S2. Analytical precision
impoundments.'S Yet,the long-term impact of CCR effluents is was calculated as the relative percent difference (RPD) of the
poorly studied in surface water surrounding coal-fired power results of duplicate sample measurements and is also reported
plants. in Supporting Information Table S2.
This study aims to investigate the impact of CCR disposal on
surface water surrounding coal-fired power plants in North • RESULTS AND DISCUSSION
Carolina.We systematically document the quality of discharged Quality of Discharged Effluent. This study documented
effluents from ten CCR effluent and cooling water discharge elevated contaminant concentrations in CCR effluents dis-
sites and the impact on associated waterways (lakes,rivers),in charged from coal-fired power plants into receiving waters in
addition to a reference (control) lake (Figure 1; Table 1).We NC (Figures 2 and 3; Supporting Information Table S2). For
measured the concentrations of major and trace elements in 76
CCR effluent samples, 129 surface water samples from lakes t0oo
and rivers from different downstream and upstream (back- ;^shOnly
ground) sites, and 98 pore water samples extracted from the +f-Go
lake sediments. The study is based on an investigation of ioo
monthly sampling over one year at two lakes(Hyco and Mayo)
and a single sampling for ten other waterways (Table 1,Figure
1) to
■ METHODS
1
During August 2010 to February 2012,a total of thirty-six field
trips were made to the research sites in North Carolina(Figure
1,Supporting Information Table Si)with over 300 surface and 0 '
pore water samples were collected. Samples were collected Ca Mg Cl SO4 Sr Mn u B Al V Cr Ni As Se Rb Mo Sb TI Pb
monthly from Hyco and Mayo Lakes from August 2010 Figure 2.Mean values of enrichment factors of dissolved constituents
through August 2011. The other investigated water resources in CCR effluents disposed from plants with an FGD system(red)and
were Lake Norman, Mountain Island Lake, Lake Wylie, High without an FGD system (blue). The enrichment factors were •
Rock Lake,Belews Lake, Dan River,French Broad River, Lake calculated by the ratio of different elements concentrations in directly
Julian, and Jordan Lake as a reference lake (Figure 1). These sampled CCR effluents to the concentrations in the upstream water
bodies of water were sampled during the summer of 2011,with that feeds each plant.
the exception of Mountain Island Lake, which was sampled
both during the summers of 2010 and 2011. Water sampling example, during the Summer 2011 sampling,the Asheville and
procedure strictly followed USGS protocols.16 Water samples Riverbend Plant outfalls contained arsenic concentrations
were taken at various depths with a Wildco Beta water sampler above the EPA drinking water standard of 10 pg/L with
(for trace metals) to capture variations in the water column concentrations reaching 44.5 pg/L and 92 pg/L, respectively.
induced by the epilimnion and hypolimnion during lake water Mayo NPDES discharge yearlong average selenium concen-
stratification. Cations and trace metals were measured in both tration (5.6 ± 5.4 pg/L) exceeded the 5 pg/L EPA Chronic
dissolved and total forms.After filtration of samples in the field Criterion Concentration (CCC) for aquatic life. Several of the
(0.45 pm syringe filters), trace elements were measured by individual monthly sampling events at the Mayo NPDES outfall
inductively coupled plasma mass spectrometry (ICP-MS), showed Se concentrations almost 4 times the CCC limit, as
major elements by direct current plasma optical emission high as 19 pg/L(Figure 3).The summer sampling event at the
spectrometry (DCP-OES), and anions by ion chromatography Asheville Plant revealed selenium concentrations over 17 times
(IC) at Duke University. Pore water was extracted from lake the CCC (87.2 pg/L). The NPDES outfall for the Asheville
bottom sediments obtained using a Wildco box core (up to 25 plant also exceeded other human and aquatic life benchmarks,
cm depth), then vacuum filtration or centrifugation to extract including antimony above the EPA's MCL (6 pg/L) at 10.9
the pore water. InoTanic arsenic species were measured using pg/L, cadmium exceeded the fresh water aquatic life (EPA
the Bednar method, 7 in which the uncharged arsenic species CCC) standard (0.25 pg/L) at 0.8 pg/L, and thallium
As111 was separated from pore water through an anion exchange concentrations were greater than the 2 pg/L EPA MCL at
resin cartridge and preserved in the field.Trace elements were 2.9 pg/L.The outfalls were sampled directly from the outfall in
measured with a VG PlasmaQuad-3 (Thermo Fisher Scientific some sites,but in others from the water near the outfall,where
Inc.)inductively coupled plasma mass spectrometry(ICP-MS) direct sampling was not accessible (Table 1).Thus,the data at
and major elements with an ARL SpectraSpan 7 (Thermo some of the outfall sites (Roxboro,Mayo,Marshall, and Allen)
12228 dx.doi.org/10.1021/es303263x I Environ.Sci.Technol.2012,46,12226-12233

Environmental Science & Technology Article
•
1'00 - y 700- -
3000
2300 • i'0`' '
2000 2.co. -
0
Is00i soo. ;
d) i1000 '! • I 1• 200 .
'00 • • • • 100-• • • '
+ • • •
DR FBR HL 1L LN LW ML MIL Bl LJ DR FBR HL JL LN LW MI MIL BL LJ
90 • 90
. •
70
so
w • ■
a^0 $
b ? •
¢w z IS
a to • — —EPAMA.CL •
m
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• s
o.......—_-__.• -•�- '• • •.�.___ l .�., -• . 0-•-0-
DR FOR HL JL LN LW ML MIL BL LI ° DR FBR HL 1L LN LW ML MIL BL U
Figure 3.Concentration ranges of selected contaminants in CCR effluents from coal plants in NC.Red symbols correspond to plants with combined
coal ash and FGD systems,blue symbols for only coal ash(without FGD),green for the reference lake(Jordan Lake),and black for cooling water
separated from CCR effluents.The EPA drinking water(MCL)and ecological(CCC)benchmarks are referenced.Sites indude the Dan River(DR),
French Broad River(FBR),Hyco Lake(HL),Jordan Lake(JL),Lake Norman(LN),Lake Wylie(LW),Mayo Lake(ML),Mtn.Island Lake(MIL),
Belews Lake(BL),and Lake Julian (LJ) that are shown in Figure 1. •
underestimate the full extent of the CCR waste stream waters that feed them, and the FGD effluents had larger
contaminant level of the discharge.In spite of efforts to reduce enrichments in many ions compared to the ash discharge only
the levels of contaminants discharged through the NPDES outfalls (Figure 2).
outfall by using settling ponds, clarifier,bioreactor, or wetland Annual fluxes of dissolved trace elements through CCR-
at some sites1'18 our data clearly show high contaminant levels effluent discharge into NC waterways show large variations
that suggest the need for enhanced removal/wastewater (Supporting Information Table S4). The magnitude of the
treatment. arsenic flux from CCR effluents exceeded the natural flux of the
Many of the outfalls sampled consisted of wastewater from associated water system in some cases (Roxboro, Ashville,
the FGD process that was subsequently diluted with the ash Mayo) and was lower in others (Dan River,Allen,Riverbend).
pond water (or other process water), and at some locations, The anthropogenic fluxes exceed the natural fluxes even in sites
also mixed with the cooling water(e.g.,Roxboro plant at Hyco where the CCR discharge flow rate consisted of less than a
Lake; Supporting Information Table S3) prior to discharge at percent of the natural water flow. The flux measurements
the outfall. Therefore for plants with an FGD system, the reported in this study were also compared to the Toxic Release
effluent concentrations represent some dilution of the original Inventory (TRI)21 and show both consistent and inconsistent
FGD wastewaters.19'2° The data show that outfalls sampled results (Supporting Information Table S4). The overall CCR
from coal fired power plants with an FGD system(n=69)had fluxes of contaminants into NC waterways, such as B,As, and
significantly higher concentrations of major ions (Ca, Mg,and Se were 278, 0.7, and 0.8 (metric) tons per year, respectively.
Cl;p < 0.01) and minor constituents such as B (p < 0.01),Br Yet the magnitude of As, Se, and Sb fluxes were significantly
(p < 0.01),and Cr(p < 0.05) relative to outfalls with only ash lower than flux values reported previously for CCR discharge to
pond water or cooling water disposal (n = S and n = 7 the Chattahoochee River, Georgia.22
respectively; Figure 3). The plants with no FGD system, but In contrast to the CCR outfalls, separated cooling water
with wet ash disposal systems and subsequent discharges (n = effluents that were sampled in this study had much lower
5),had higher concentrations of several constituents including contaminant concentrations, which did not exceed any of the
As,V, Sb, Li,T1, and Mo (p < 0.01) relative to effluents from human or aquatic life benchmarks (Supporting Information
FGD systems (Supporting Information Table S2). Selenium Table S2)and were not enriched in any constituents compared
concentrations were also higher at FGD outfalls with several to their respective upstream waters and reference lake (Jordan
plants exceeding the EPA's CCC of 5 pg/L(Mayo at 19 pg/L Lake) (Supporting Information Table S2). Consequently, in
and Asheville at 82 pg/L compared to Riverbend at<3.5 pg/L outfall sites where CCR effluents and cooling water were
and Dan River at<DL of selenium). Overall,the CCR outfalls blended, the contaminant level was significantly reduced. For
were enriched in many constituents compared to the upstream example, in Hyco lake, where the cooling water constitutes
12229 dx.doi.org/10.1021/es303263x I Environ.Sci.Technol.2012,46,12226-12233

•
v
Environmental Science&Technology
1500 P4 • 100 ' - —
• LakeLakeWow ,
: . ....
1..0i r; , • • Y
Kw. •, , ,- •.. : 10 - t -
. 4 ••
sea
. M ri ,: r- •• �• 1 . i -
Sit , • r S■ •• ••
1
• Op • ••
Jr 6.5 •••1•• , -
0 20 •0 se 00 Ito I70 0 70 40 00 •0 100 170 0 1
1 10 100 1000
Glbrtds 10102) Chloride(mpL) Chloride(regd.)
Figure 4.Boron,selenium,and arsenic versus chloride concentrations in Hyco Lake.The CCR effluent concentrations are marked with red circles,
surface lake water by blue squares,porewater from outfall areas by black triangles,and porewater from downstream areas by green diamonds.Note
the high correlation of boron with chloride in the lake water(i.e.,a conservative behavior)relative to the low correlations of arsenic and selenium.
The data show differential depletion of boron and selenium and enrichment of arsenic in pore water relative to lake water.
>98% of the effluent volume (Supporting Information Table 0.001, respectively; Supporting Information Table S3),
S3) the contaminant levels of the NPDES outfall would be indicating strong association with suspended particles in the
significantly higher if the cooling component was reduced or water column. Higher dissolved concentrations of these
restricted(e.g., recirculating cooling water at Mayo Lake).The constituents were observed at the bottom of the lake during
direct effluents from the FGD process and ash ponds at periods of thermal stratification in the summer and low
Roxboro were reported to have concentrations of As ranging dissolved oxygen content (Supporting Information Figure S3).
between 1.6 and 394 f g/L and Se ranging 4.3-238 pg/L Seasonal stratification leads to the depletion of oxygen in
during the yearlong sampling (Supporting Information Table bottom water during summer months and an overturning of the
S3).23,24 Therefore, cooling water has an important mitigating water column during the fall.25 We hypothesize that under
effect on the quality of NPDES outfalls in NC. oxygenated water conditions,As oxyanions would be adsorbed
Impact on the Aquatic Systems.We further analyzed the onto Fe oxyhydroxides particles in the water column and
impact of CCR effluents on the quality of receiving waters by bottom sediments.26'27 During the stratification periods, when
systematically comparing the chemical composition in waters the bottom waters become anoxic, reductive dissolution of Fe
downstream of the disposal sites relative to upstream waters (and Mn) oxyhydroxides results in release of dissolved As, Fe,
from the same river/lake and a reference lake that has no and Mn to the bottom water. The reducing conditions would
connection to coal plant discharge (Jordan Lake; Figure 1). also convert arsenate (As(V)) into arsenite (As(I11)), a
The data show elevated concentrations,particularly for Ca,Mg, neutrally charged form of arsenic at pH 7 (i.e., H3AsO3)
Sr,Li,B,V, Cr,Se,Mo,F, Cl,Br,SO42- (p <0.01), as well as that is less reactive toward sorption on oxyhydroxides28'29 and
for As and T1 (p < 0.05), in downstream water relative to also more toxic to wildlife.3°The covariance of As with other
upstream water.Likewise,the concentrations of Ca,Sr,Li,B(p redox sensitive elements like Fe and Mn during thermal
< 0.01), as well as V, Se, and Mo (p < 0.05) were elevated in stratification in Hyco Lake (Supporting Information Figure S2)
sites downstream of the outfalls relative to concentrations in supports this model.
the reference lake (Supporting Information Table S2). In contrast, selenium does not increase with decreasing
In spite of the large dilution of effluent discharge,which plays dissolved oxygen (and depth) in Hyco and Mayo Lakes, but
a key role in reducing the dissolved constituents released to rather shows a linear relationship with chloride,although with a
surface waters, we observed significant variations and differ- relatively weak correlation (R2=0.65;Figure 4 and Supporting
ential impacts of various constituents after CCR release into the Information Table SS), reflecting both dilution and retention
receiving waters. We grouped the major and minor elements effects. This is consistent with the selenium species geo-
according to their chemical behavior as monitored in Hyco and chemistry: under oxic conditions the oxidized species selenate
Mayo'Lakes (Supporting Information Table SS). In Group 1, (Se(VI)) would be less reactive toward sorption with
the concentrations of boron (R2=0.88; Figure 4),calcium (R2 oxyhydroxides and thus behave conservatively in the water
= 0.96), strontium (R2 = 0.95), bromide (R2 = 0.91), and column. In contrast, under anoxic conditions the partially
sulfate (R2 = 0.86) in filtered water (0.45 µm) show linear reduced Se species selenite (Se(IV)) would have a strong
correlations with chloride during the yearlong sampling(Figure sorption affinity for both oxyhydroxides31 and clay miner-
4, Supporting Information Figure Si, and Supporting als. 2'33 The most reduced forms of selenium (e.g., elemental
Information Table SS), reflecting their conservative (i.e., Se° and FeSe) tend to persist as sparingly soluble minerals.
nonreactive) behavior in the lake system. Thus dilution Overall, a transition to anoxic conditions in the lake
seems to be the key factor determining their concentrations hypoliminion would result in lower dissolved Se concen-
in the affected rivers/lakes. The concentration of other trations.34'35
elements (Se, Mg, Cr, V, and Ba defined as Group 2) in Bottom Lake Sediments and Pore Water.In addition to
filtered water show a nonlinear correlation with Cl (0.3 <R2 > differential distribution of contaminants in the surface waters,
0.6) that suggests some attenuation in the lakes (e.g., sorption this study revealed elevated levels of CCR contaminants
to particles). In contrast,As,Fe, and Mn that defines Group 3 (Supporting Information Table 56; Fe,Mn, Sr,As,Mo,Sb,Ni,
show low or no correlation with chloride (R2=0.01,0.07, and V,and Br(p<0.01),as well as Mg and F(p<0.05))in shallow
12230 dx.doi.org/10.1021/es303263x1 Environ.Sci.Technol.2012,46,12226-12233

Environmental Science & Technology Article
3500 ----i 300
3000 -
250
25(H) - -
200 - -
J J_ ! ,
en 2000 - - m
0
150
c •
EPA CCC
O 1500 - - m
o In
CD
I c
1000 EPA Health Advisory Level Q 100 -
J
_ c•
Ill500 1 C 50 Ii
i , � -Ir � , ."
0 i rI /, II 11=11.0 .1
Hl Hl HL Ml ML ML MIL MIL MIL Jordan HL HL HL ML ML ML MIL MIL MIL Jo10an
Up Omar Down Qo 0044 Down Up DAM Dowd La* up o.ii l Down up OWN Down up CLOW Down La.
Figure 5.Boron and arsenic concentrations in porewater collected from upstream,outfall,and downstream sites of Hyco Lake (HL),Mayo Lake
(ML),Mountain Island Lake(MIL),and Jordan Lake.Red symbols correspond to plants with combined coal ash and FGD systems,blue for only
coal ash,and green for the reference lake (Jordan Lake).The EPA boron health advisory level is indicated, as well as the EPA CCC freshwater
aquatic regulatory level.
pore water extracted from the lake bottom sediments that were contaminants in lake systems could have ecological implica-
significantly higher than those of the overlying bottom water. tions, particularly for benthic organisms and therefore the rest
For example, As concentrations in pore water from Hyco, of the food chain. Indeed, elevated As and Se levels were
Mayo, and Mtn. Island lakes were as high as 83, 297,and 240 reported in fish tissues from Hyco and Mayo Lakes especially
µg/L, respectively, exceeding the EPA's MCL (10 pg/L) and near the NPDES outfall.24'36 Furthermore,the 2010 Mayo Lake
CCC (150 pg/L) standards (Figure 5). For comparison, the Environmental Report36 showed deformities in some fish,
concentrations of trace elements (B and As,p < 0.1) in pore including an extended lower jaw and spinal curvature, both of
water from the reference lake were significantly lower than the which are indicators of ingestion of high levels of Se 37 If the
CCR impacted lakes (Figure 5).We hypothesize that retention base of the food chain is exposed to high levels of contaminants
of CCR contaminants from the lake water via adsorption onto through the sediment and pore water,other organisms could be
suspended matter in the water column results in accumulation at risk if they feed on those organisms that live in the
of these contaminants in the sediments that are deposited on contaminated sediments and pore water.38'39
the lake bottom.Recent reports of higher concentrations of As The impact of the effluent discharged from the NPDES
and Se in lake bottom sediments at the outfall at Hyco and outfalls on water quality in the downstream waterways is
Mayo (As, 23 pg/g and 97 pg/g; Se, 8 pg/g and 10 pg/g dry dependent on the flow rate to the river/lake (i.e., dilution
weight,respectively) relative to the upstream branch of the lake effect; Supporting Information Table S4),residence time in the
(As,6 pg/g and 12 pg/g; Se, 2 pg/g and 1.6 pg/g dry weight, water body, as well as the mobilization (e.g., adsorption/
respectively) confirm that both As and Se are recycled desorption to sediment) properties of specific contaminants in
through adsorption and desorption due to changes in the lake the water. For example, the outfall on the French Broad River
water chemistry, apparently induced from thermal stratification from the Asheville power plant had effluents with high
during the summer. Changes in the ambient conditions (pH, contaminant concentrations (Supporting Information Table
redox state) in the lake sediments would release these
S2), but because of high river discharge flow, the downstream
metalloids to the pore water.4 We documented high levels of
As in pore water and other redox-sensitive elements (Mn, Fe;
water was significantly diluted (although still detectable). A
mass-balance calculation,using boron as a conservative tracer in
Figure 5) that confirm this model.Additionally, direct arsenic
speciation measurements show that over 82% of arsenic in the surface water,show a contribution of 4.5%of CCR effluent into
pore water collected at Hyco and Mayo Lakes were composed the downstream river with boron concentrations of 115 pg/L.
of the reduced and more mobile species arsenite (Supporting It is important to note however,that these hydrologic systems
Information Table S7).In contrast,the Se concentrations were could vary and be greatly affected by droughts. During the
significantly higher in the CCR effluents and lake water relative severe drought of 2007-2008 in North Carolina,the discharge
to the pore water (p < 0.01) (Figures 3 and 5). This indicates of the French Broad River decreased drastically to just over 5
that Se from CCR effluent can become associated with the m3 5-1, approximately 5 times lower than the river flow rate
sediment,but that Se species become immobilized by forming during the time of our sampling (25 m3 s-').4° Using mass-
elemental selenium and metal—selenium complexes in the balance calculation for conservative constituents, a 5-fold
sediment, and therefore are not incorporated into the pore reduction in water flow would increase the CCR contribution
water. up to 22% and would significantly increase the concentrations
Ecological and Environmental Implications. The of such contaminants in the downstream river (e.g., boron up
accumulative nature of arsenic, selenium, and other CCR to 530 pg/L).
12231 dx.doLorp/10.1021/es303263x I Environ.Sci.Technol.2012,46,12226-12233

Environmental Science&Technology Article
Our data also show CCR discharge into smaller lakes appears and data collection. We also thank the French Broad
to have a greater impact relative to the larger lakes (e.g.,Mayo Riverkeeper and the Catawba Riverkeeper for their assistance
Lake versus Lake Norman). This impact is therefore a in sampling their respective rivers.We would also like to thank
combination of the volume of released CCR effluents, the Amrika Deonarine,Katie Barzee,Alissa White,Andrew Sturges,
lake inflows, plant water usage (removing from the lake Julie Ruhl, Shaniece Belcon, and Andrew Matsumoto for their
system), and residence time. All of these factors can play a assistance in the field, Tom Darrah and Nathaniel Warner for
major role in the lake's water quality. For instance, Hyco and constructive comments,Kiril Kolev for statistics assistance,and
Mayo Lakes have boron concentrations of 958,ug/L and 703 to Cidney Christie for the TOC image.
Eeg/L, respectively compared to an upstream creek with boron
concentrations of <3 ug/L and <7 pg/L, respectively • REFERENCES
(Supporting Information Table S2). This is a 300- and 100-
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Washington, DC, 2009; http://water.epa.gov/scitech/wastetech/
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with concentrations below health benchmarks at the NPDES (6)2010 Coal Combustion Product(CCP)Production and Use Report;
outfall, could become problematic as As is retained in American Coal Ash Association: Aurora, CO, 2011; http://acaa.
suspended sediments and remobilized with environmental affiniscape.com/associations/8003/files/2010_CCP_Survey_FINAL_
changes in reduced bottom and pore waters.The results of this 102011.pdf(accessed 2012).
study have significant implications for hundreds of similar sites (7)2008 Coal Combustion Product(CCP)Production and Use Survey
across the US given that CCR storage facilities continuously Report; American Coal Ash Association: Aurora, CO, 2009; http://
generate contaminants via leaching and transport to nearby www.acaa-usa.org(accessed 2012).
hydrological systems. While this study focused on surface (8) Environmental Protection Agency Website. Wastes—Non-
Hazardous Waste—Industrial Waste. http://www.epa.gov/osw/
waters near CCR facilities, groundwater may have similar nonhaz/industrial/special/fossil/coalashletter.htm (accessed 2012).
effects. Many CCR disposal ponds and landfills are not lined (9)Hanlon,J.Memorandum:National Pollutant Discharge Elimination
and, in many instances, are neither adequately monitored, nor System (NPDES) Permitting of Wastewater Discharges from Flue Gas
regulated with respect to their effects on groundwater and Desulfurization (FGD) and Coal Combustion Residuals (CCR)
surface waters. This study highlights the need for rigorous Impoundments at Steam EIectric Power Plants; U.S. Environmental
monitoring and dear regulations for limiting the CCR Protection Agency:Washington,DC,2010.
contaminants that are being discharged into U.S.waterways. (10) Power Plant Water Usage and Loss Study; Department of
Energy:,National Energy Technology Laboratory: Washington, DC,
• ASSOCIATED CONTENT 2007; http://www.netldoe.gov/technologies/coalpower/gasification/
pubs/pdf/WaterReport_Revised%20May2007.pdf(accessed 2012).
® Supporting Information (11) Environmental Protection Agency Website. NPDES Permit
Description of analytical techniques, additional quality control Program Basics: Fequently Asked Questions. http://cfpub.epa.gov/
information, geo-references for sampling sites, along with npdes/faqs.cfm#107 (accessed 2012).
supplementary graphs and figures.This material is available free (12)Codes of Federal Regulations.Steam Electric Power Generating
of charge via the Internet at http://pubs.acs.org. Point Source Category, 1982.http://www.gpo.gov/fdsys/pkg/CFR-
2011-title40-vol29/pdf/CFR-2011-title40-vol29-part423.pdf
■ AUTHOR INFORMATION (13) Energy Information Administration. Coal plants without
Corresponding Author scrubbers account for a majority of U.S. SO2 emissions, 2011.
(a) http://www.eia.gov/todayinenergy/detail.cfm?id=4410# (accessed
*Tel: [phone].Fax: [phone].E-mail:vengosh
2011).
duke.edu. (14) Coal Combustion Waste Damage Case Assessments, U.S.
Notes Environmental Protection Agency Report; U.S. EPA: Washington,
The authors declare no competing financial interest. DC,2007;p 70.
(15) Lemly,A. D.; Skorupa,J. P.Wildlife and Coal Waste Policy
■ ACKNOWLEDGMENTS Debate:Proposed Rules for Coal Waste Disposal Ignore Lessons from
45 years of Wildlife Poisoning.Environ.Sci. TechnoL 2012.
This research was funded by a grant from the NC Water (16) U.S. Geological Survey. National Field Manual for the
Resources Research Institute. We thank the NC DENR Collection of Water-Quality Data, 2008.http://water.usgs.gov/owq/
Division of Water Quality for all of their assistance in sampling FieldManual/index.html.
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com/commitment/environment/what-we-are-doing/airandwater.page
(accessed 2012).
•
(19) Monthly Data Monitoring Report (DMR)for Progress Energy
Carolinas' Roxboro Steam Plant (NPDES Permit NC0003425).
Progress Energy:Raleigh,NC,2009-2011.
(20) Monthly Data Monitoring Reports (DMR)for Progress Energy
Carolinas'Mayo Steam Electric Plant (NPDES Permit NC0038377);
Progress Energy:Raleigh,NC,2009-2011.
(21) Environmental Protection Agency Website.EPA Environfacts:
Toxics Release Inventory Facility Reports. http://www.epa.gov/
enviro/facts/tri/search.html (accessed 2012).
(22) Lesley,M.P.; Froelich, P.N.Arsenic,selenium and antimony
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(25)Balistrieri,L.S.;Murray,J.W.;Paul,B.The cycling of iron and
managnese in the water column of Lake Sammamish, Washington.
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sediments.Geochim. Cosmochim.Acta 2007,71,5782-5803.
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adsorption on ferrihydrite: Kinetics, equilibrium, and adsorption
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(29) Wolthers, M.; Charlet, L; van Der Weijden, C. FL; van der
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mackinawite.Geochim.Cosmochim.Acta 2005,69,3483-3492.
(30)Duker,A.A.;Carranza,E.J.M.;Hale,M.Arsenic geochemistry
and health.Environ.Int.2005,31,631-641.
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Klinck,B.A.Arsenic and Selenium;Elsevier-Pergamon:2003,VoL 9,pp
17-66.
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montmorillonite.Soil Sci 1987, 144, 12-19.
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Modeling—Hydrous Ferric Oxide;Wiley Publisher:New York, 1990.
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remobilisation in sediments of Lake Macquarie,NSW. Org.Geochem.
1999,30, 1287-1300.
(35) Bowie, G.L.Assessing selenium cycling and accumulation in
aquatic ecosystems. Water Air Soil Pollut. 1996,90,93-104.
(36) Mayo Steam Electric Plant, 2010 Environmental Monitoring
Report(NPDES permit NC0038377);Progress Energy:Raleigh,NC,
2011.
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fish:the Belews Lake case example.Aquat.Toxicoi 2002,57,39-49.
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12233 dx.doi org/10.1021/es303263x I Fmhon.Sd Tecrnol 2012,46,12226-12233

Attachment B
Duke Energy Carolinas LLC (IRiverbend)
Complaint and Motion for Injunctive Relief
(May 24, 2013)

STATE OF NORTH CAR( ;NA 'No.
/
Mecklenburg a 7r
County In The General Court Of Justice
❑ District ®Superior Court Division
Name Of lateinEff 75`3 rj.Y } Ji 11- 13
State of North Carolina ex rel.NC DENR,DWQ
Address � `: `i jet, G.Q.C.
1617 Mail Service Center CIVIL SUMMONS
City,State,21v 6'" - ❑-At iAS'AND PLUMES SUMMONS(ASSESS FEE)
Raleigh NC 27699-1617
VERSUS G.S.IA-I,Rules 3.4
Name Of ONamden((s) Deft Original Summons issued
Duke Energy Carolinas,LLC
Dine(s)Subsequent Summo e(es)Issued
To Each Of The Defendant(s)Named Below:
Name And Address OfDeftndnd 1 Name And Addiess Of Defendant 2
Duke Energy Carolinas,LLC a
CT Corporation,Registered Agent
150 Fayetteville St
Raleigh NC 27601
A Civil Action Has Been Commenced Against Youl •
You are notified to appear and answer the complaint of the plaintiff as follows:
1. Serve a copy of your written answer to the complaint upon the plaintiff or plaintiffs attorney within thirty(30)days after
you have been served. You may serve your answer by delivering a copy to the plaintiff or by mailing it to the plaintiffs
last known address,and
2. File the original of the written answer with the Clerk of Superior Court of the county named above.
if you fail to answer the complaint,the plaintiff will apply to the Court for the relief demanded in the complaint.
Name And Address OfMeiners Atbrn y"Monk Address O/t OM) Deft issued Mite ❑AM
Kathryn Jones Cooper,Special Deputy Attorney General S Z C-f / .� f (' ••L7� 0 PM
NC Department of Justice,Environmental Division
Post Office Box 629
Raleigh NC 27602 .p apb CSC 0 Asainent CSC -- Cl awk orsatedor carr
Dein alE Mammon: Time
❑ ENDORSEMENT(ASSESS FEE) 0 AM
This Summons was originally issued on the date 0 PM
indicated above and returned not served.At the request
of the plaintiff,the time within which this Summons must •
be served is extended sixty(60)days. 0 Deputy CSC 0 AaHdanf CSC ❑ Clerk 01SyperforCourt
NOTE TO PARTIES:Many counties have MANDATORY ARBITRATION papaws in which most cases where the amount in controversy IS$15,000 or
less we heard by an arbltratcr before a big! The patties w+11 be moaned I this case is assigned for mandatory arbitration,and I
so,what pmcedtre is t be Mowed
d
AOC-CV-100,Rev.f3/11 (Ovix)
0 2011 Administrative Office of the Courts

. .M . RETURN OF SERVICE
I certify that this Summons and a copy of the complaint were received and served as follows:
DEFENDANT 1
Ogle Saved ' Time Served Name OfDefwrdesnt
SIzy 1Z:. ,la 11: to El/AM ❑ PM
❑ By delivering to the defendant named above a copy of the summons and complaint.
❑ By leaving a copy of the summons and complaint at the dwelling house or usual place of abode of the defendant named
above with a person of suitable age and discretion then residing therein.
O As the defendant is a corporation, service was effected by delivering a copy of the summons and complaint to the
person named below.
None And Address Of Penton Mer,Where Cope..Left(V CO.pOV O.give N.of person copies MR with)
O Other manner of service(sptrdf4 QY yAa 0 Of c r,.slt-''
a .CCJT se c.vrcc or) ' CI44U oF' pL(c.i€>' T As qtT }oQ4.tle0.
❑ Defendant WAS NOT served for the following reason: �T
DEFENDANT 2
Ade Served Tine Served ❑ ElWarm Of Defendant
PM
❑ By delivering to the defendant named above a copy of the summons and complaint.
❑ By leaving a copy of the summons and complaint at the dwelling house or usual place of abode of the defendant named
above with a person of suitable age and discretion then residing therein.
❑ As the defendant is a corporation,service was effected by delivering a copy of the summons and complaint to the
person named below.
Name And Adders Of Person 1,14th Morn Copies Left(V caporeton,give N.of person copies left with)
❑ Other manner of service(spedy)
❑ Defendant WAS NOT served for the following reason.
Service F. Paid -Signature or Deputy ShamMddp Return
$
Dela Received Name Of Sheriff(Type Or Print)
Date Of Return Counfy Of Sheriff
AOC-CV-100,Side Two,Rev.6/11
0 2011 Administrative Office of the Court

8. N.C. Gen. Stat. § 143-211 further provides that "[s]tandards of water and air
purity shall be designed to protect human health, to prevent injury to plant and animal life, to
prevent damage to public and private property, to insure the continued enjoyment of the natural
attractions of the State, to encourage the expansion of employment opportunities, to provide a
permanent foundation for healthy industrial development and to secure for the people of North
Carolina, now and in the future,the beneficial uses of these great natural resources."
9. The Commission has the power to issue permits with conditions attached as the
Commission believes are necessary to achieve the purposes of Article 21 of Chapter 143 of the
General Statutes. N.C. Gen. Stat. § 143-215.1(b)(4).
10. Pursuant to its authority in N.C. Gen. Stat. § 143-215.3(a)(4) to delegate such of
its powers as it deems necessary, the Commission has delegated the authority to issue permits,
and particularly discharge permits,to the Director of the Division of Water Quality. Title 15A of
the North Carolina Administrative Code ("NCAC"), rule 2H.01121. A copy of this rule is
attached hereto as Plaintiffs Exhibit No. 1, and is incorporated herein by reference.
11. N.C. Gen. Stat. § 143-215.1 requires a permit before any person can "make any
outlets into the waters of the state" or "cause or permit any waste, directly or indirectly, to be
discharged to or in any manner intermixed with the waters of the State in violation of the water
quality standards applicable to the assigned classifications ... unless allowed as a condition of
any permit, special order or other appropriate instrument issued or entered into by the
Commission under the provisions of this Article [Article 21 of Chapter 143 of the General
Statutes]." N.C. Gen. Stat. §§ 143-215.1(a)(1)and(6).
•
15A NCAC 2H.0112
3

12. The Commission's rules in the 15A NCAC Subchapter 2L (hereinafter "2L
Rules"), "establish a series of classifications and water quality standards applicable to the
groundwaters of the State." 15A NCAC 2L.0101(a). A copy of the 2L Rules is attached hereto
as Plaintiff's Exhibit No. 2 and is incorporated herein by reference.
13. "Groundwaters" are defined in the 2L Rules as "those waters occurring in the
subsurface under saturated conditions." 15A NCAC 2L.0102(11).
14. The 2L Rules "are applicable to all activities or actions, intentional or accidental,
which contribute to the degradation of groundwater quality, regardless of any permit issued by a
governmental agency authorizing such action or activity except an innocent landowner who is a
bona fide purchaser of property which contains a source of groundwater contamination, who
purchased such property without knowledge or a reasonable basis for knowing that groundwater
contamination had occurred, or a person whose interest or ownership in the property is based or
derived from a security interest in the property, shall not be considered a responsible party."
15A NCAC 2L.0101(b).
15. The policy section of the 2L Rules provides that the 2L Rules "are intended to
maintain and preserve the quality of the groundwaters, prevent and abate pollution and
contamination of the waters of the state, protect public health, and permit management of the
groundwaters for their best usage by the citizens of North Carolina." 15A NCAC 2L.0103(a).
16. "Contaminant" is defined in the 2L Rules as "any substance occurring in
groundwater in concentrations which exceed the groundwater quality standards specified in Rule
.0202 of the Subchapter." 15A NCAC 2L.0102(4).
17. "Natural Conditions" are defined in the 2L Rules as "the physical, biological,
chemical and radiological conditions which occur naturally." 15A NCAC 2L.0102(16).
4

18. The policy section of the 2L Rules provides further that, "[i]t is the policy of the
Commission that the best usage of the groundwaters of the state is as a source of drinking water.
These groundwaters generally are a potable source of drinking water without the necessity of
significant treatment. It is the intent of these Rules to protect the overall high quality of North
Carolina's groundwaters to the level established by the standards and to enhance and restore the
quality of degraded groundwaters where feasible and necessary to protect human health and the
environment, or to ensure their suitability as a future source of drinking water." 15A NCAC
2L.0103(a).
19. The policy section of the 2L Rules provides further that, "[n]o person shall conduct
or cause to be conducted, any activity which causes the concentration of any substance to exceed
that specified in Rule .0202 of this Subchapter, except as authorized by the rules of this
Subchapter." 15A NCAC 2L.0103(d).
20. The groundwater "Standards" are specified in 15A NCAC 2L.0202. See 15A
NCAC 2L.0102(23). Some groundwater standards and their concentrations are specifically
listed in.0202(g) and (h). "Where naturally occurring substances exceed the established
standard, the standard shall be the naturally occurring concentration as determined by the
Director." 15A NCAC 2L.0202(b)(3). If a substance is not specifically listed and it is not
naturally occurring, the substance cannot be permitted in concentrations at or above the practical
quantitation limit in Class GA or Class GSA waters, except that the Director may establish
interim maximum allowable concentrations ("IMAC") pursuant to 15A NCAC 2L.0202(c).
These are listed in Appendix #1 of 15A NCAC 2L. The IMACs are the established standard until
adopted by rule. See the last page of Plaintiff's Exhibit No. 2.
5

21. The DWQ Director established IMAC for Antimony on August 1, 2010 and for
Thallium on October 1, 2010, substances for which standards had not been established under the
2L Rules. A copy of the Public Notice establishing the IMACs and a copy of the Approved
IMACs are attached hereto as Plaintiffs Exhibit Nos. 3 and 4, respectively, and both exhibits are
incorporated herein by reference. The interim maximum allowable concentration for Thallium is
0.0002 mg/L (0.2 µg/L) established pursuant to 15A NCAC 2L .0202(c). The interim maximum
allowable concentration for Antimony is 1 µg/L established pursuant to 15A NCAC 2L .0202(c).
See the last page of Plaintiffs Exhibit No. 2.
22. "It is the intention of the Commission to protect all groundwaters to a level of
quality at least as high as that required under the standards established in Rule .0202 of this
Subchapter." 15A NCAC 2L.0103(b).
23. A "Compliance Boundary" is defined in the 2L Rules as "a boundary around a
disposal system at and beyond which groundwater quality standards may not be exceeded and
only applies to facilities which have received an individual permit issued under the authority of
'[N.C. Gen. Stat. §] 143-215.1 or [N.C. Gen. Stat. §]130A." 15A NCAC 2L.0102(3).
24. Pursuant to 15A NCAC 2L.0107(a), "[fjor disposal systems individually
permitted prior to December 30, 1983, the compliance boundary is established at a horizontal
distance of 500 feet from the waste boundary or at the property boundary, whichever is closer to
the source."
25. The "Waste Boundary" is defined in the 2L Rules as "the perimeter of the
permitted waste disposal area." 15A NCAC 2L.0102(26).
26. A "Corrective Action Plan" is defined in the 2L Rules as "a plan for eliminating
sources of groundwater contamination or for achieving groundwater quality restoration or both.
6

15A NCAC 2L.0102(5). A site assessment pursuant to a corrective action should include the
source and cause of contamination, any imminent hazards to public health and safety, all
receptors and significant exposure pathways, the horizontal and vertical extent of the
contamination, as well as all geological and hydrogeological features influencing the movement
of the contamination. 15A NCAC 2L .01006 (g).
27. Pursuant to N.C. Gen. Stat. § 143-215.6C, "[w]henever the Department has
reasonable cause to believe that any person has violated or is threatening to violate any of the
provisions of this Part [Part 1, Article 21, of the General Statutes], any of the terms of any permit
issued pursuant to this Part, or a rule implementing this Part, . . ." the Department is authorized
to "request the Attorney General to institute a civil action in the name of the State upon the
relation of the Department for injunctive relief to restrain the violation or threatened violation."
28. That section further provides that "[u]pon a determination by the court that the
alleged violation of the provisions of this Part or the regulations of the Commission has occurred
or is threatened, the court shall grant the relief necessary to prevent or abate the violation or
threatened violation." N.C. Gen. Stat. § 143-215.6C.
29. Additionally, the section provides that "[n]either the institution of the action nor
any of the proceedings thereon shall relieve any party to such proceedings from any penalty
prescribed for the violation of this Part." N.C. Gen. Stat. § 143-215.6C.
30. Defendant is a person consistent with N.C. Gen. Stat. § 143-212(4) and pursuant
to N.C. Gen. Stat. § 143-215.6C.
Factual and Leia!Allezations
31. Defendant implemented a voluntary groundwater monitoring program at the
Riverbend Facility(also known as"Facility")in 2006.
7

32. In 2009, Plaintiff DWQ required Defendant to place monitoring wells at the
compliance boundaries of all Coal Ash Ponds at its Facility.
33. DWQ approved Defendant's proposed compliance boundary and monitoring
wells location at Riverbend Steam Station on August 26, 2010.
34. Defendant constructed compliance monitoring wells at the compliance boundaries
of the Coal Ash Ponds at Riverbend Steam Station on December 2010.
35. At Riverbend Steam Station the following set of specific parameters are being
monitored: Antimony, Arsenic, Barium, Boron, Cadmium, Chromium, Chloride, Copper, Iron,
Lead, Manganese, Mercury, Nickel, Nitrate, pH, Selenium, Sulfate, Thallium, TDS, Water
Level,and Zinc.
36. In 2010, Defendant began submitting groundwater monitoring data to DWQ from
the Facilities.
37. On June 17, 2011, the DWQ adopted a policy for compliance evaluation of long-
term permitted Facility with no prior groundwater monitoring requirements (hereinafter "June
17, 2011 Policy"). A copy of the June 17, 2011 Policy is attached hereto as Plaintiff's Exhibit
No. 5 and is incorporated herein by reference.
38. DWQ's June 17, 2011 Policy establishes an approach to evaluate groundwater
compliance at long-term permitted facilities. Specifically, the policy requires staff and
responsible parties to consider multiple factors before determining if groundwater concentrations
in samples taken at the permitted facility are a violation of the groundwater standards, or if the
concentration is naturally occurring. Such factors considered are well design, sample integrity,
analytical methods,statistical testing,etc.
8

39. Riverbend Steam Station is subject to the June 17, 2011 Policy and DWQ has
been working with the Defendant to move through the evaluative process as described in the
policy.
40. DWQ's Aquifer Protection staff compiled tables of the analytical results of
groundwater samples collected at the Facility. The Facility began submitting data in 2010, and
DWQ prepared charts of the Ash Pond Exceedances from 2010 to April 1, 2013. The charts are
labeled by National Pollutant Discharge Elimination System ("NPDES") Permit number and
facility name. The Riverbend Steam Station chart is attached hereto as Plaintiffs Exhibit No. 6
("Riverbend Steam Station Ash Pond Exceedances Chart")and this exhibit is incorporated herein
by reference.
41. The Riverbend Steam Station Ash Pond Exceedances Chart contains the
following information: the well number, the parameter sampled, the date of the sample (month
and year),the 2L limit(groundwater standard),the sampling result and the unit of measurement.
Riverbend Steam Station
42. On March 3, 1976, pursuant to N.C. Gen. Stat. § 143-215.1, other lawful statutes
and regulations issued by the Commission, and the Clean Water Act, DWQ issued NPDES
Permit No. NC0004961 to Defendant and/or Defendant's predecessor for the Riverbend Steam
Station ("Riverbend Steam Station NPDES Permit"), located in Mecklenburg County, North
Carolina.
43. The Riverbend Steam Station NPDES Permit has been renewed subsequently.
The current NPDES Permit was re-issued on January 18, 2011, with an effective date of March
1, 2011, and with an expiration date of February 28, 2015. A copy of the current Riverbend
9

Steam Station NPDES Permit No. NC0004961 is attached hereto as Plaintiff's Exhibit No. 7, and
is incorporated herein by reference.
44. The Riverbend Steam Station NPDES Permit authorizes the continued discharge
of treated wastewater to receiving waters designated as the Catawba River (Class WS-IV & B-
CA waters) in the Catawba River Basin in accordance with the effluent limitations, monitoring
requirements and other conditions set forth therein.
45. Among other things, the Riverbend Steam Station NPDES Permit authorizes the
continued discharge of once-through cooling water through Outfall 001. This discharge consists
of intake screen backwash and water from the plant chiller system, turbine lube oil coolers,
condensate coolers,main turbine steam condensers and the intake tunnel dewatering sump.
46. In addition; the Riverbend Steam Station NPDES Permit authorizes a continued
discharge from an Ash Pond through Outfall 002. The Ash Pond discharge consists of induced
draft fan and preheater bearing cooling water, stormwater from roof drains and paving, treated
groundwater, track hopper sump (groundwater), coal pile runoff, laboratory drain and chemical
makeup tanks and drums rinsate wastes, ash transport water, general plant/trailer sanitary
wastewater, metal cleaning waste, chemical metal cleaning waste, combustion turbine cooling
water discharges, turbine and boiler rooms sumps, vehicle rinse water, and stormwater from
pond areas and upgradient watershed.
47. Further, the Riverbend Steam Station NPDES Permit authorizes the continued
discharge of yard sump overflows through Outfall 002A.
48. Outfalls 002 and 002A consist of coal pile runoff, ash transport water, metal
cleaning wastes, treated domestic wastewater, remediated groundwater, low volume wastes,
blowdown from wet cooling towers for combined cycle unit,and boiler blowdown.
10

49. The effluent limitations and monitoring requirements in the Riverbend Steam
Station NPDES Permit for the discharge from Outfall 001 requires sampling for the following
parameters: Flow and Temperature, with the temperature requirements in effect when only units
with a shared control system are operating.
50. The Riverbend Steam Station NPDES Permit prohibits Chlorination of the once-
through condenser cooling water discharged through Outfall 001.
51. The effluent limitations and monitoring requirements in the Riverbend Steam
Station NPDES Permit for Outfall 002 require sampling for the following parameters: Flow,
Total Suspended Solids, Oil and Grease, Total Copper, Total Iron, Total Arsenic, Total
Selenium,Total Mercury, Total Phosphorus, Total Nitrogen,pH, and Chronic Toxicity.
52. The metal cleaning waste, coal pile runoff, ash transport water, domestic
wastewater and low volume waste must be discharged into the Ash Settling Pond.
53. No chemicals, cleaners or other additives may be present in the vehicle wash
water to be discharged through Outfall 002.
54. The effluent limitations and monitoring requirements in the Riverbend Steam
Station NPDES Permit for Outfall 002A require sampling for the following parameters: Flow,
pH,Total Suspended Solids, Oil and Grease, Fecal Coliform,Total Copper and Total Iron.
55. The Riverbend Steam Station NPDES Permit prohibits the discharge of floating
solids or visible foam other than in trace amounts from any of its outfalls.
Unpermitted Seeps at the Riverbend Steam Station
56. As mentioned above, the Defendant's Riverbend Steam Station has three
permitted outfalls (001, 002 and 002A) discharging directly into the Catawba River which are
included in the Riverbend Steam Station NPDES Permit.
11

57. Defendant's Riverbend Steam Station NPDES Permit does not authorize the
Defendant to make any outlet or discharge any wastewater or stormwater other than those
included in the Riverbend Steam Station NPDES Permit.
58. Upon information and belief, Plaintiff believes there are non-engineered seeps at
Defendant's Riverbend Steam Station, which are different locations from the outfalls described
in the Riverbend Steam Station NPDES Permit.
59. A seep or discharge from the Ash Pond or any other part of the Riverbend Steam
Station that is not included in the Riverbend Steam Station NPDES Permit is an unpermitted
discharge in violation of N.C. Gen. Stat. § 143-215.1(a)(1)and(a)(6).
Exceedances of 2L Groundwater Standards at the Riverbend Steam Station
60. DWQ's Aquifer Protection staff compiled tables of the analytical results of
groundwater samples collected at the Riverbend Steam Station from 2010 through April 1, 2013,
and prepared a chart of the Ash Pond Exceedances which are listed in the Riverbend Steam
Station Ash Pond Exceedances Chart. See Plaintiff's Exhibit No. 6.
61. The Riverbend Steam Station Ash Pond Exceedances Chart shows 21
exceedances from the 2L Groundwater Standard s for Iron (300 µg/L) in MW-11SR, MW-14,
MW-15, MW-7SR, MW-8D, and MW-8I during 7 sampling events from February 2011 to
March 2013.
62. The Riverbend Steam Station Ash Pond Exceedances Chart shows 38
exceedances from the 2L Groundwater Standard for Manganese (50 µg/L) in MW-11DR, MW-
11 SR,MW-114, MW-15,MW-7SR,and MW-8D during 7 sampling events from February 2011
to March 2013.
12

63. DWQ staff is working with the Defendant to determine if these exceedances are
naturally occurring or if corrective action will be required.
CLAIMS FOR RELIEF
64. The allegations contained in paragraphs 1 through 63 are incorporated into these
claims for relief as if fully set forth herein.
65. Defendant's unpermitted seeps from the Facility are violations of N.C. Gen. Stat.
§§ 143-215.1(a)(1)and(a)(6).
66. Plaintiff is entitled to injunctive relief, as set forth more specifically in the prayer
for relief,pursuant to N.C. Gen. Stat. § 143-215.6C.
67. Defendant's violations of N.C. Gen. Stat. §§ 143-215.1(a)(1) and (a)(6) for the
unpermitted seeps and potential violations of the groundwater standards, without assessing the
problem and taking corrective action, poses 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.
PRAYER FOR RELIEF
WHERFORE, the Plaintiff, State of North Carolina, prays that the Court grant to it the
following relief:
1. That the Court accepts this verified complaint as an affidavit upon which to base
all orders of the Court.
2. That the Court preliminarily, and upon final judgment permanently enter a
mandatory injunction requiring the Defendant to abate the violations of N.C. Gen. Stat. § 143-
215.1,NPDES Permits and groundwater standards at the Facility;
3. That the Court preliminarily, and upon final judgment permanently enter a
mandatory injunction requiring the Defendant take the steps required in the attached "Ash Ponds
13

Assessment Needs", which is attached hereto as Plaintiff's Exhibit No. 8 and is incorporated
herein by reference;
4. That the Defendant be taxed with the costs of this action.
5. Any other and further relief that the Court deems to be just and proper.
t
Respectfully submitted,this the day of May,2013.
ROY COOPER
Attorney General
By
Kathryn J s Cooper
Special Deputy Attorney General
NC State Bar No. 12176
[e-mail]
1 mak
By J. .
o . • Lat.n
Assistant Attorney General
NC State Bar 13303
•
By
Anita LeVeaux
Assistant Attorney General
NC State Bar No. 13667
N.C. Department of Justice
• Environmental Division
Post Office Box 629
Raleigh,NC 27602-0629
[phone] phone
[phone] facsimile
[e-mail]
Attorneys for the Plaintiff
State of North Carolina ex rel.
North Carolina Department of
Environment and Natural Resources
Division of Water Quality
14

STATE OF NORTH CAROLINA
COUNTY OF MECKLENBURG
VERIFICATION
Jeffrey Poupart,first being duly sworn,deposes and says that he is the Point Source Branch
Supervisor of the Surface Water Protection Section of the Division of Water Quality in the North
Carolina Department of Environment and Natural Resources; that he has read the foregoing
verified Complaint and Motion Injunctive Relief,and that he is acquainted with the facts and
circumstances alleged therein; and believes them to be true.
effrey Poupart
Wake County,North Carolina
I certify that the following person appeared before me this day,acknowledging to me that he signed the
foregoing document: Jeffrey Poupart.
This the I3ey(day of May, 2013.
O cia!Signature of ora
titeI 2)
Notary's printed or typed name
My Commission Expires: 9— aei3
(�'ffrttlae `I-"
mama twirl
w , � r3
-!\ 4# c e

Attachment C
Wateree Station
Semi-Annual Status Report
July-December 2014
(January 2015)

SOUTH CAROLINA ELECTRIC & GAS
r _ _
POWER FoR LIVING
WATEREE STATION
SEMI-ANNUAL STATUS REPORT
JULY - DECEMBER 2014
JANUARY 2015

1
r
Semi-Annual Status Report
SCE&G Wateree Station
1 PURPOSE
The purpose of this document is to present a status report for the six-month reporting
period of July 1, 2014 through December 31, 2014 in accordance with the August 17,
2012, Settlement Agreement and Release ("Agreement") between the Catawba
Riverkeeper Foundation, Inc. ("Riverkeeper") and South Carolina Electric & Gas
Company ("SCE&G").
2 ASH REMOVED
During the six-month reporting period of July 1, 2014 through December 31, 2014,
115,608 dry tons of ash were removed from Pond 1.
3 RESULTS OF GROUNDWATER SAMPLING
During the six-month reporting period of July 1, 2014 through December 31, 2014,
groundwater sampling for wells monitored pursuant to the Mixing Zone Consent
Agreement was performed, with the results presented in the following report:
Second Semi-Annual 2014 Monitoring Report, South Carolina Electric & Gas
Company, Wateree Station, Eastover, South Carolina
The above report has been submitted to SCDHEC. A copy of the report is attached.
4 ACTIVITIES PERFORMED
During the six-month reporting period of July 1, 2014 through December 31, 2014, the
following activities were performed in furtherance of the Undertakings described in
Paragraph 1 of the Agreement:
A. Paragraph 1.2: SCE&G continued to remove ash from Pond 1 for sale, recycling
or placement in a Class 3 landfill. From January 1, 2012 to present (December
31, 2014), the cumulative net reduction of ash in Pond 1 is 610,748 dry tons.
July— December, 2014 Page 1 of 2

Semi-Annual Status Report
SCE&G Wateree Station
B. Paragraph 1.4: During the six-month reporting period of July 1, 2014 through
December 31, 2014, SCE&G continued construction for the development of
Phase 2 of the on-site Class 3 landfill (construction completed in January 2015).
As reported in item 4B of the January— June, 2014 Semi-Annual Status Report
regarding Paragraph 1.3 of the Agreement, the solid waste permit for
development of the Class 3 landfill became final on July 13, 2013. Therefore, per
the provisions of Paragraph 1.4 of the Agreement, development of Phase 2 of the
on-site Class 3 landfill shall be complete within 20 months, or by March 13, 2015.
C. Paragraph 1.6: During the six-month reporting period of July 1, 2014 through
December 31, 2014, SCE&G prepared and submitted for DHEC approval a
Preliminary Engineering Report for a new synthetically lined wastewater pond to
replace Pond 1. Per the provisions of Paragraph 1.6 of the Agreement, SCE&G
shall apply for a permit to construct (Final Engineering Report) for the new
synthetically lined wastewater pond by December 31, 2015.
July— December, 2014 Page 2 of 2

ATTACHMENT

GEL Engineering LLC PO Box 30712 Charleston,SC 29417
2040 Savage Road Charleston,SC 29407
a member of The GEL Group INC P 843.769.7378 F 843.769.7397
www.pel.com
December 17, 2014
Mr. Mike Moore
SCANA
220 Operation Way
C221
Cayce,South Carolina 29033-5443
Re: Second Semi-Annual 2014 Monitoring Report
South Carolina Electric&Gas Company
Wateree Station
Eastover, South Carolina
Dear Mike:
Enclosed are six copies of the "Second Semi-Annual 2014 Monitoring Report"for
the Wateree Station facility.
On behalf of GEL Engineering, LLC, I would like to thank you for giving us the
opportunity to assist you in meeting your environmental needs. If you have any
questions or need additional information, please call me at [phone].
Sincerely,
c:31•Or-len. ;lte, 61
Thomas D.W. Hutto, P.G.
Principal
enclosures
fc: sceg01914c_2SA14.doc

•
Second Semi-Annual 2014
Monitoring Report
South Carolina Electric & Gas Company
Wateree Station
Eastover, South Carolina
•
December 17, 2014

Second Semi-Annual 2014 Monitoring Report December 17,2014
South Carolina Electric and Gas-Wateree Station Page 2
only overflow from Pond 1 and functions as a polishing pond. After allowing the ash to
settle,the excess water within the ponds is released to the Wateree River in accordance
with National Pollutant Discharge Elimination System (NPDES) Permit No. SC0002038.
The ash in Pond 1 is separated from the Wateree River by a dike which is approximately
150 feet wide at its narrowest location.
3.0 Groundwater and Surface Water Monitoring Program
To ensure the mixing zone compliance criteria established in the Consent
Agreement are met, a groundwater monitoring program was developed. This
monitoring program consists of semi-annual sampling of groundwater monitoring wells
MW-1A through MW-6, MW-8, MW-9, and MW-11, shown on Figure 2. Well MW-1A
was installed in February 2010,to replace background monitoring well MW-1, which
had been damaged by construction activities. In accordance with the Consent
Agreement, groundwater samples from these wells are analyzed for arsenic (total), lead
(total), chromium (total), cadmium (total), sulfate, field pH, and field specific
conductance. In addition,the depth to groundwater is measured in each well. The
samples are also analyzed for copper(total), iron (total), mercury(total), nickel (total),
selenium (total), zinc(total),total organic carbon, chlorides, field turbidity, nitrate
nitrogen (total), laboratory pH, laboratory specific conductivity, and total dissolved
solids.
Surface water samples are collected in the Wateree River at locations upstream of
the ponds, downstream of the ponds, and adjacent to the ponds. The approximate
surface water sampling locations are shown on Figure 3. Each surface water sample is
analyzed for arsenic(total) and nickel (total).
3.1 Sample Collection
Groundwater monitoring wells MW-1A through MW-6, MW-8, MW-9, and MW-
11, and three surface water samples designated as "Upstream," "At Ponds," and
"Downstream," were sampled on October 13, 2014 by EFM Inc. (EFM) personnel. The
sample locations are shown on Figures 2 and 3.
Techniques used for well evacuation, sample collection, and measurement of the
water table depth were designed to ensure that representative groundwater samples
were collected and accurate field measurements were made. The depth to
groundwater was measured in each well using an electronic water level indicator. The
wells were sampled using low flow sampling techniques and a peristaltic or dedicated
GEL Engineering,LLC
A Member of The GEL Group,Inc.
fc: sceg01914c-2SA14.doc

Second Semi-Annual 2014 Monitoring Report December 17,2014
South Carolina Electric and Gas-Wateree Station Page 3
electric pump. The field parameters pH, specific conductivity, and turbidity were
measured during the sample collection activities and recorded on the field data
information sheets which are included in Appendix I.
The Chain of Custody Record was completed for each sample immediately
following the completion of the sample collection. The samples remained in the
custody of EFM personnel throughout the collection process and transportation to the
laboratory. Upon arrival at the laboratory, sampling personnel relinquished the
samples to log-in personnel. The chain of custody was maintained for all samples from
the time of collection through the completion of the analyses.
3.2 Analytical Results
The groundwater samples were analyzed for the parameters specified in Section
3.0. A summary of the detected constituents in groundwater which have MZCL criteria
is presented in Table 1. The Certificates of Analysis and Chain of Custody
documentation are included in Appendix I. Appendix II contains the DHEC"Ground-
water Monitoring Report"forms which summarize all analyzed constituents, including
the field parameters.
As shown in Table 1, MZCLs for the analyzed constituents were not exceeded in
any of the groundwater samples collected during this monitoring event. An
isoconcentration map for arsenic is provided as Figure 4.
The surface water samples were analyzed for arsenic (total)and nickel (total). A
historical summary of arsenic analytical results for the surface water locations is shown
on Table 2. As shown in Table 2, none of the surface water samples contained
detectable concentrations of arsenic or nickel during this monitoring event.
•
3.3 Groundwater Flow Direction
Table 3 provides a summary of the water table elevations calculated during this
monitoring event. A potentiometric surface map of the surficial aquifer, Figure 5,was
constructed based on the elevation data collected on October 13-14, 2014. These data
indicate that the water table in the uppermost aquifer is approximately 11 to 32 feet
below land surface (bls), and that groundwater generally flows toward the Wateree
River, which is consistent with previous findings.
GEL Engineering,LLC
A Member of The GEL Group,Inc.
fc: sceg01914c-2SA14.doc

Second Semi-Annual 2014 Monitoring Report December 17,2014
South Carolina Electric and Gas-Wateree Station Page 4
4.0 Mixing Zone Status
Based on the October 2014 groundwater and surface water monitoring event,the
predominant groundwater flow direction continues to be toward the Wateree River.
Detected metals concentrations in groundwater do not exceed mixing zone levels in any
of the monitoring wells. Arsenic was not detected in any of the surface water samples.
Therefore,the conditions of the mixing zone continue to be met.
The next sampling event will be conducted in April/May 2015, and the monitoring
report will be submitted to DHEC by June 30, 2015, as specified by the Consent
Agreement.
GEL Engineering,LLC
A Member of The GEL Group,Inc.
fc: sceg01914c-2SA14.doc

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Table 1 ,
Summary of Constituent Concentrations in Groundwater(2001-2014)
Wateree Station
South Carolina Electric&Gas Company
Eastover,South Carolina
Parameter Event Sample Date Arsenk Cadmium Chromium Lead Sulfate
MW-1 AWL 50 5 100 50 2,000
1501 4/17/2001 <5 <1 <10 <5 2
2501 11/13/2001 <5 <1 <10 <5 1.3
1502 4/23/2002 <5 <1 <10 <5 2.22
2502 10/23/2002 <5 <1 <10 <5 3.88
1503 4/15/2003 <5 <1 <10 <5 0.86
2503 10/20/2003 <5 <1 <10 <5 2.68
1504 3/9/2004 <5 <1 <10 <5 1.1
2504 9/30/2004 <5 <1 <10 <5 1.7
1505 4/13/2005 <5 <1 <10 6 3.05
+
___2505 10/18/2005 <5 <1 <10 5.0 5.01
1506 3/15/2006 5 <1 23 7.0 1.35
2506 10/16/2006 <5 <1 <10 <5 1.2
1507 4/30/2007 <5 <1 <10 <5 0.69
2507 10/16/2007 <5 <1 12 <5 8.90
1508 4/16/2008 <5 <1 <10 <5 1.4
2508 10/22/2008 21.3 <1 80.3 67.5 0.56
2508(Resample) 11/6/2008 <5.0' NS NS NS N5
1509 4/21/2009 19 <1 93.0 40.0 11.36
1509(Resample) 5/2/2009 24' <1. 86.0 34.0' NS
2509 11/5/2009 <5 <1 <10 <5 136.9
MW-1A MZCL 50 5 100 SO 2,000
1510 4/20/2010 <5 <1 <10 <5 0.75
2510 10/19/2010 <5 <1 <10 5.50 <0.50
1511 4/12/2011 <5 <1 <5 <5 <0.50
2511 11/1/2011 9.30 <1 <5 <5 <0.50
2511(Resample) 11/22/2011 <5. NS NS NS Ns
1512 5/15/2012 <5 <1 <5 <5 <0.50
2512 11/6/2012 <5 <1 <5 <5 <0.50
1513 5/13/2013 <5 <1 <5 <5 <0.50
2513 10/21/2013 <5 <1 <5 <5 0.7
1.514 4/28/2014 <5 <1 <5 <5 0.9
2514 10/14/2014 <5 <1 <5 <5 <0.5
MW-2 MZCL 50 5 too 50 2,000
1501 4/17/2001 <5 <1 <10 <5 66.9
2501 11/13/2001 <5 <1 <10 <5 57.7
1502 4/23/2002 <5 <1 <10 <5 52.6
2502 10/23/2002 <5 <1 <10 <5 60.3
__.._ 1503 4/15/2003 <5 <1 <10 <5 52.4
2503 10/20/2003 <5 <1 <10 <554.39
1504 3/9/2004 <5 <1 <10 <5 - 52
2501 9/30/2004 <5 <1 <10 <5 45.8
1505 4/13/2005 <5 <1 <10 <5 45.9
2505 10/18/2005 <5 <1 <10 <5 44.6
1506 3/15/2006 <5 <1 <10 <5 39.56
2506 10/16/2006 <5 <1 <10 <5 35.9
1507 4/30/2007 <5 <1 <10 <5 32.2
2507 10/16/2007 <5 <1 <10 <5 34.00
1508 4/16/2008 <5 <1 <10 <5 38.3
2508 10/22/2008 <5 <1 <10 8.4 33.7
1509 4/21/2009 <5 <1 <10 8.4 37.70
2509 11/5/2009 <5 <1 <10 <5 31.40
1510 4/20/2010 <5 <1 <10 <5 35.80
2510 10/19/2010 <5 <1 <10 <5 27.90
1511 4/12/2011 <5 <1 <5 <5 33.60
2511 11/1/2011 <5 <1 <5 <5 34.00
1512 5/15/2012 <5 <1 <5 <5 34.60
2512 11/6/2012 5.1 <1 <5 <5 40.70
1513 5/13/2013 <5 <1 <5 <5 44.60
2513 10/21/2013 <5 <1 <5 <5 40.4
1514 4/28/2014 <5 <1 <5 <5 28.8
2514 10/14/2014 <5 <1 <5 <5 45.2
Page 1 of 5

Table 1
Summary of Constituent Concentrations In Groundwater(2001-2014)
Wateree Station
South Carolina Electric&Gas Company
Eastover,South Carolina
Parameter Event Sample Date Arsenic Cadmium Chromium Lead Sulfate
MW-3 M2CL 3,000 5 100 50 2,000
1501. 4/17/2001 165 <1 <10 <5 73.4
2501 11/13/2001 231 <1 <10 <5 57.8
1502 4/23/2002 164 <1 <10 <5 64.1
2502 10/23/2002 186 <1 <10 <5 57.2
1503 4/15/2003 284 <1 <10 <5 63.9
2503 10/20/2003 193 <1 <10 <5 56.76
1504 3/9/2004 432.7 <1 <10 <5 38.8
' 2504 9/30/2004 198 <1 <10 22.4 - 44.8
1505 4/13/2005 377 <1 13 6 40.1
2505 10/18/2005 201 <1 <10 <5 52.3
1506 3/15/2006 305 <1 <10 <5 42.35
2506- 10/16/2006 209 <1 <10 <5 45.1
1507 4/30/2007 232 <1 <10 <5 43.8
2507 10/16/2007 179 <1 <10 <5 38.10
1508 4/16/2008 402 <1 <10 <5 47.2
2508 10/22/2008 189 <1 <10 <5 40.98
2508(Resample) 11/6/2008 208' NS NS NS NS
1509 4/21/2009 294 <1 <10 <5 35.80
1509(Resample) 5/7/2009 143' <1' <10' <5' NS
2509 11/5/2009 162 <1 <10 <5 29.60
1510 4/20/2010 485 <1 <10 <5 36.60
2510 10/19/2010 144 <1 <10 <5 28.10
1511 4/12/2011 176 1.3 <5 <5 63.00
2511. 11/1/2011 202 <1 <5 <5 46.70
1512 5/15/2012 164 <1 <5 <5 58.80
2512 11/6/2012 162 <1 <5 <5 41.90
1513 5/13/2013 103 <1 <5 <5 70.50
2513 10/21/2013 153 <1 <S <5 86.4
1.514 4/28/2014 82.8 1.2 <5 <5 44.6
2514 10/14/2014 122 <1 <5 <5 59.1
MW-4 MiCL 3,000 S 100 50 2,000
1501 4/17/2001 8.1 <1 <10 <5 4.6
2501 11/13/2001 <5 <1 <10 <5 4.4
1.502 4/23/2002 8.8 <1 <10 <5 4.8
2502. 10/23/2002 <5 <1 <10 <5 4.1
1503 4/15/2003 12.3 <1 <10 <5 5.5 .
2503 10/20/2003 <5 <1 <10 <5 2.91
1504 3/9/2004 7.6 3.4 <10 <5 2.2
2504 9/30/2004 7.9 2.2 <10 <5 12.6
1505 4/13/2005 <5 <1 <10 <5 3.39
2505 10/18/2005 15.1 3.4 <10 <5 6.3
1506 3/15/2006 <5 2.2 <10 <5 3.96
2506 10/16/2006 <5 <1 <10 <5 4.3
1507 4/30/2007 <5 <1 <10 <5 <0.50
2507 10/16/2007 <5 <1 <30 <5 <0.50
1508 4/16/2008 <5 1.1 <10 <5 <0.5
2508 10/22/2008 <5 <1 <10 <5 <0.5
1509 4/21/2009 <5 <1 <10 <5 7.02
2509 11/5/2009 <S <1 <10 <5 <0.5
1510 4/20/2010 <5 3.2 <10 <5 10.40
2510 10/19/2010 <5 <1 <10 <5 <0.5
1.511 4/12/2011 <5 <1 <5 <5 <0.5
2511 11/1/2011 <5 <1 <5 <5 - 3.00
1512 5/15/2012 <5 1.9 <5 <5 8.70
2512 11/6/2012 <5 15 <5 <5 <0.5
1513 5/13/2013 <5 1.5 <5 <5 1.05
2513 10/21/2013 <5 <1. <5 <5 0.9
1514 4/28/2014 <5 3.6 <5 <5 6.1
2514 10/14/2014 <5 3.7 <5 <5 0.96
Page 2 of 5

Table 1
Summary of Constituent Concentrations in Groundwater(2001-2014)
Wateree Station
South Carolina Electric&Gas Company
Eastover,South Carolina
Parameter Event Sample Date Arsenic Cadmium Chromium Lead Sulfate
MW-5 MM. 50 15 100 50 2,000
1501 4/17/2001 <5 2.2 <10 <5 0.7
2501 11/13/2001 <5 <1 <10 <5 34.6 •
1502 4/23/2002 5 4.2 18.5 8.5 1.93
2502 10/23/2002 <5 <1 <10 <5 2.71
1503 4/15/2003 15.4 <1 <10 <5 <0.5
2503 10/20/2003 <5 <1 <10 <5 <0.5
1504 3/9/2004 8 3.1 <10 <5 <0.5
2504 9/30/2004 7.3 5.8 <10 <5 4.0
- 1505 4/13/2005 10 <1 15 8 <0.5
2505 10/18/2005 5.2 5.4 <10 <5 <0.5
1506 3/15/2006 <5 5.5 <10 <5 <0.5
2506 10/16/2006 <5 <1 <10 <5 <0.5
1507 4/30/2007 <5 <1 <10 <5 <0.50
2507 10/16/2007 <5 1.14 <10 <5 <0.50
1508 4/16/2008 <5 1.9 <10 <5 <0.5 `�
2508 10/22/2008 <5 1.4 <10 6.6 <0.5
1509 4/21/2009 <5 <1 <10 <5 <0.5
2509 11/5/2009 <5 <1 <10 <5 <0.5
1510 4/20/2010 <5 3.4 <10 <5 <0.5
2510 10/19/2010 <5 <1 <10 <5 <05
1511 4/12/2011 6.1 <1 <5 <5 _ <0.5_
2511 11/1/2011 9.1 <1 <5 6.1 4.00
2511(Resampie) 12/2/2011 <5 NS NS NS NS
1512 5/15/2012 <S 3.4 <5 7 13.4
2512 11/6/2012 <5 2.9 <5 8.8 37.8
1513 5/13/2013 5.7 <1 9.5 7.2 <0.5
2513 10/21/2013 <5 1.1 <5 6.4 0.9
1514 4/28/2014 <5 3.5 5.7 <5 0.9
2514 10/13/2014 <5 <1 <5 6.2 <0.5
MW-6 M2Cl 50 5 100 50 2,000
1501 4/17/2001 <5 <1 <10 <5 41.7
2501 11/13/2001 <5 <1 <10 <5 48.4
1502 • 4/23/2002 <5 <1 <10 <5 47.9
2502 10/23/2002 <5 <1 <10 <5 39.5
1503 4/15/2003 <5 <1 <10 <5 32.4
2503 10/20/2003 <5 <1 <10 <5 44.92
1504 3/9/2004 <5 2.8 <10 <5 2.9
2504 9/30/2004 <5 <1 <10 <5 32.1
1505 4/13/2005 <5 <1 <10 <5 29.6
2505 10/18/2005 <5 <1 <10 <5 35.9
1506 3/15/2006 <5 <1 <10 <5 34.22
2506 10/16/2006 <5 <1 <10 <5 30.4
1507 4/30/2007 <5 <1 <10 <5 <0.50
2507 10/16/2007 <5 <1 187 11.6 <0.50
1508 4/16/2008 6.4 <1 <10 <5 30.0 _
2508 10/22/2008 <5 <1 29.6 <5 24.5
1509 4/21/2009 <5 <1 <10 <5 <0.5
2509 11/5/2009 <5 <1 <10 <5 22.5
1510 4/20/2010 <5 3.4 <10 <5 1.56
2510 10/19/2010 <5 3.7 <10 <5 5.33
1511 4/12/2011 <5 1.2 <5 <5 29.90
2511 11/1/2011 <5 1.2 <5 <5 29.40
• 1512 5/16/2012 6.7 <1 7.3 <5 35.00
2512 11/6/2012 <5 <1 <5 <5 37.20
1513 5/13/2013 5 <1 <5 <5 31.20
2513 10/21/2013 <5 <1 <5 <5 34.8
1514 4/28/2014 <5 <1 <5 <5 26.0
2514 10/13/2014 <5 <1 <5 <5 26.2
Page 3of5

Table 1
Summary of Constituent Concentrations in Groundwater(2001-2014)
Wateree Station
South Carolina Electric&Gas Company
Eastover,South Carolina
Parameter Event Sample Date Arsenic Cadmium Chromium Lead Sulfate
MW4 M20. 50 15 100 50 2,000
1501 4/17/2001 15.1 1 <10 <5 226.8
2501 11/13/2001 <5 <1 <10 <5 91.6
1502 4/23/2002 7.8 <1 <10 5 158.5
2502 10/23/2002 <5 <1 <10 <5 243
1503 4/15/2003 <5 4.4 <10 <5 441.3
2503 10/20/2003 19.8 3.4 <10 <5 164.9
1504 3/9/2004 <5 3.9 <10 <5 99.2
2504 9/30/2004 <5 <1 <10 <5 247.1
1505 4/13/2005 <5 <1 <10 <5 290
2505 10/18/2005. <5 <1 <10 <5 314
1506 3/15/2006 <5 2.8 <10 <5 207.8
2506 10/16/2006 <5 <1 <10 <5 170
1507 4/30/2007 6 <1 <10 <5 73
2507 10/16/2007 <5 <1 <10 <5 13.00
1508 4/16/2008 <5 <1 <10 <5 15.1
2508 10/22/2008 <5 <1 <10 <5 3.2
1.509 4/21/2009 <5 <1 <10 <5 37.10
2509 11/5/2009 <5 <1 <10 <5 37.80
1510 4/20/2010 <5 3.1 <10 <5 12.08
2510 10/19/2010 <5 3.1 <10 <5 .1.11
1511 4/12/2011 <5 <1 6.5 <5 66.30
2511 11/1/2011 <10 2.2 <10 <10 115
1512 5/16/2012 <50 <10 <50 <50 195
2512 11/6/2012 10.7 2.8 <10 <10 198
1513 5/13/2013 <5 <1 5 10.6 129.9
2513 10/21/2013 <5 <1 <5 5.6 125
1514 4/28/2014 <5 2.0 <5 <5 119
2514 10/13/2014 <5 <1 <5 <5 77.4
MW-9 MZCL 50 15 100 50 2,000
1501 4/17/2001 <5 5.8 <10 <5 1,040
2501 11/13/2001 <5 <1 <10 <5 1,182
1502 4/23/2002 <5 7.9 <10 5 1,044
2502 10/23/2002 <5 <1 <10 <5 1,603
1503 4/15/2003 7.7 8.8 <10 <5 775.6
2503 10/20/2003 <5 <1 <10 <5 824.5
1504 3/9/2004 <5 6.9 <10 <5 962.0
2504 9/30/2004 <5 1 <10 <5 775.4
1505 4/13/2005 <5 <1 <10 <5 963
2505 10/18/2005 <5 4.5 <10 <5 916
1506 3/15/2006 <5 <1 <10 <5 957
2506 10/16/2006 <5 <1 <10 <5 861
1507 4/30/2007 <5 <1 <10 <5 241
2507 10/16/2007 <5 <1 <10 <5 1,200
1508 4/16/2008 <5 2.4 <10 <5 9,330
2508 10/22/2008 <5 2.4 <10 <5 1,247.3
1509 4/21/2009 <5 <1 <10 <5 432.0
2509 11/5/2009 <5 <1 <10 <5 1,017
1510 4/20/2010 <5 <1 <10 <5 992
2510 10/19/2010 <5 <1 <10 <5 1,045
1511 4/12/2011 7.4 3.6 <5 8.8 900
2511 11/1/2011 9.6 <1 <5 10 992 •
2511(Resample) 12/2/2011 <5* <1• NS NS NS
1512 5/15/2012 <5 2.2 <5 13.4 978
2512 11/6/2012 <5 8.2 <5 13.6 945
1513 5/13/2013 <5 2.2 <5 13.9 710
2513 10/21/2013 <5 3.4 <5 12.0 926
1514 4/28/2014 <5 <1 <5 9.1 425
2514 10/13/2014 <5 <1 <5 11.5 973
Pape 4 of 5

Table 1
Summary of Constituent Concentrations in Groundwater(2001-2014)
Wateree Station
South Carolina Electric&Gas Company
Eastover,South Carolina
Parameter Event Sample Date Arsenic Cadmium Chromium Lead Sulfate
MW-11 MZCL 3,000 5 100 SO 2,000
1501 4/17/2001 565 <1 <10 <5 59.2
2501 11/13/2001 1,150 <1 <10 <5 60.3
1502 4/23/2002 1,143 <1 <10 <5 63.8
2502 10/23/2002 774 <1 • <10 <5 68.2
1503 4/15/2003 322 <1 <10 <5 57.7
2503 10/20/2003 1,345 <1 <10 <5 63.9
1504 3/9/2004 337 <1 19.2 7.9 54.3
2504 9/30/2004 563 <1 18.7 9.7 40.7
1505 4/13/2005 891 <1 73 39 53.9
2505 10/18/2005 1,512 <1 31.4 13.7 54.2
1506 3/15/2006 5,100 <1 40 14 36.82
1506(Resampie) 6/1/2006 968` NS NS NS NS
2506 10/16/2006 1,492 <1 <10 <5 68.2
1507 4/30/2007 4,051 <1 10 7 27.5
1507(Resampie) 5/7/2007 252` NS NS NS NS
2507 10/16/2007 2,452 <1 <10 5.2 26.80
1508 4/16/2008 310 <1 <10 <5 35.4
2508 10/22/2008 2,149 <1 13.2 8 32.04
2508(Resampie) 11/6/2008 424' NS NS NS NS
1509 4/21/2009 567 <1 <10 <5 41.90
1509(Resample) 5/7/2009 932' <1• <10• <5• NS
2509 11/5/2009 576 <1 <10 <5 27.60
1510 4/20/2010 796 <1 31.70 10.90 60.80
2510 10/19/2010 696 <1 <10 <5 55.7
1.511 4/12/2011 380 <1 8.7 <5 44.5
1511(Resample) 6/15/2011 1,100• <1' <5. <5• 102.4•
2511 11/1/2011 318 <1 <5 <5 107
1512 5/15/2012 690 <1 <5 <5 85.8
2512 11/6/2012 460 <1 <5 <5 43.0
1513 5/13/2013 94.50 <1 <5 <5 24.7
2513 10/22/2013 355 <1 <5 <5 42.4
1514 4/28/2014 97.0 <1 <5 <5 25.9
2514 10/13/2014 101.0 <1 <5 <5 22.2
Notes:
1)All concentrations for total metals and are provided In micrograms per liter(ug/1).
2)Sulfate concentrations are provided in milligrams per liter(mg/1).
3)MZCL=Mixing Zone Contaminant Level.
4)MZCL for arsenic for wells MW-1,MW-2,MW-S,MW-6,MW-8,and MW-9 is 50 ug/I.
5)MZCL for arsenic for wells MW-3,MW-4,and MW-11 is 3,000 ug/I.
6)MZCL for cadmium for wells MW-1,MW-2,MW-3,MW-4,MW-6,and MW-11 is 5.0 ug/l.
7)MZCL for cadmium for wells MW-5,MW-8,and MW-9 Is 15.0 ug/I.
8)NS=Not analyzed.
9)Bold type indicates concentration above MZCL
10)•=Results of resampling
Page 5 of 5

Table 2
Summary of Arsenic Concentrations in Surface Water(2001-2014)
Wateree Station
South Carolina Electric&Gas Company
Eastover, South Carolina
Sampling Event Sample Date Sample Location MCI
Upstream At Ponds Downstream
1501 4/17/2001 <5 <5 <5 10
2501 11/13/2001 <5 <5 <5 10
1S02 4/23/2002 <5 <5 <5 10
2S02 10/23/2002 5.3 6.2 6.2 10
1503 4/15/2003 <5 <5 <5 10
2503 10/20/2003 <5 <5 6.0 10
1504 3/9/2004 <5 <5 <5 10
2SO4 9/30/2004 <5 <5 <5 10
1505 4/13/2005 <5 <5 <5 10
2S05 10/18/2005 <5 <5 <5 10
1506 3/15/2006 <5 <5 <5 10
2S06 10/16/2006 <5 <5 <5 10
1507 4/30/2007 <5 103 <5 10
1S07(Resample) 5/7/2007 NS <5 NS 10
2507 10/16/2007 <5 <5 <5 10
1508 4/16/2008 <5 <5 <5 10
2508 10/22/2008 <5 <5 <5 10
1509 4/21/2009 <5 <5 <5 10
2509 11/5/2009 <5 <5 <5 10
1510 4/20/2010 <5 <5 <5 10
2510 10/19/2010 <5 <5 <5 10
1511 4/12/2011 <5 <5 <5 10
2511 11/1/2011 <5 <5 <5 10
1512 5/15/2012 <5 <5 <5 10
2512 11/6/2012 <5 <5 <5 10
1513 5/13/2013 <5 <5 <5 10
2513 10/21/2013 <5 <5 <5 10
1514 4/28/2014 <5 <5 <5 10
2S24 10/13/2014 <5 <5 <5 10
Notes:
1)Arsenic concentrations are provided in micrograms per liter(ugh!).
2) MCL=Maximum Contaminant Level.
3) NS= Not analyzed.
4) Bold text=Concentration above MCL.

Table 3
Summary of Groundwater Elevation Data - October 2014
Wateree Station
South Carolina Electric & Gas
Eastover, South Carolina
Monitoring Well Measuring Point Depth to Water Table
Number Elevation (feet msl) Groundwater (feet) Elevation (feet msl)
MW-1A 127.85 13.60 114.25
MW-2 109.03 11.15 97.88
MW-3 112.20 14.10 98.10
MW-4 111.62 21.63 89.99
MW-5 108.56 19.86 88.70
MW-6 113.78 32.25 81.53
MW-8 109.49 28.20 81.29
MW-9 103.06 21.20 81.86
MW-11 100.39 17.12 83.27
Notes:
1) msl = mean sea level.
2) Water levels measured on October 13-14, 2014

APPENDIX I
FIELD DATA SHEETS AND
CERTIFICATES OF ANALYSIS

WeltJPiezo ID:
EFM,INC. VI.V-
Ground Water Sample Collection Record
Client: SCE&G Date: 10/N/14
Project No: NPDES Time: Start It Y.2 am/pm
Site Location: Wateree Station Finish t, 3U am/pm
Weather Conds: CL:,,,/ll{ gy° Collector(s) --1, 'i .0 - ,
WATER LEVEL DATA:(measured from Top of Casing) Well © Piezometer 0
a.Total Well Length ..;•1.1- "- c. Casing Material /V•C- e. Length of Water Column /L'• 2-1-0 (a-b)
tl
b. Water Table Depth 13. 6 A.
0 d. Casing Diameter . f. Calculated Well Volume(see back) 1 -
WELL PURGING DATA
a.Purge Method -O(kJ, �G d LLQ)
b.Acceptance Criteria defined(from workplan)
-Minimum Required Purge Volume(© well volumes) Puree Rate: (S2',ml/min.
-Maximum Allowable Turbidity NTUs
-Stabilization of parameters 10 %
c.Field Testing Equipment Used: Make Model Serial Number
cc' 1 iA16069'
f /� , 11G< c:`f 1
d. Field Testing Equipment Calibration Documentation recorded on separate form
Volume TEMP pH Spec.Cond TURBIDITY D.O. ic.:('
Time Removed(ml) C S.U. (umhos) NTUs mg/I Color -Oder DTW
I IV-1 INITIAL ,&Y..2b s.-71 S)'1.7 7,o ( CLcc ) I5�1?? IST-60
Itc z I ,Soo ,�3.?e S,1t .S's S'Y. f. 2.r C4.�� /1u•� 13 (,:c,
11 2-, -LP-19 .1.3-YY r-.6( ss- zt .G y.c. CO-- ON.-1— l3.G"0
1207_ 3, c,c O ;2 '.O' s_.6Q .1— i i.-2-- 1.8 l -\ /P-G C>
/2.(%1 3,7Jr' , 9 (-•t' s:-r•5' S' Il Q Z. Y I81'.O /3.cc;
/LI'7— 1, ,j0 C' .y ,( 51 '19 .r l\_ 3 .37 . lac) /?-oC,
ll-t'1 zr
, . u 1. i s'V 1 .r3 _.1
g . 1 3.3 191..7._ t"S. t,
/5/ .1
e. Acceptance criteria pass/fail Yes No N/A
Has required volume been removed 0 0
Has required turbidity been reached 0 0
Have parameters stabilized 0 0
If no or N/A-Explain below.
SAMPLE COLLECTION: Method:fr_72./S-71Z-T/c_ /oYvt/n
Sample ID Container Type No.of Containers Preservation Analysis Time
GW— IA 480mL Amber 1 Hno3 As,Cd,Cr,Cu,Fe.Pb,Hg,N1,Se, (,'9,1 ' •
Zn Wa3_ _
Liter Plastic. 1 None Ph,Cond.,SO4,TDS,C1/n.p3
2ioML (Oz--) /1/0/1.M T T- C_._- \i/
Comments
Signature ./ Date loll //14

EFM,INC. Well/Piezo ID:
C, 1J -
Ground Water Sample Collection Record
Client: SCE&G Date: _10/I x//14
Project No: NPDES Time: Start 03 4(0 am/pm
Site Location: Wateree Station Finish G`i 3) am/pm
Weather Conds: {;,•,,jNt( 1 Collector(s) 71-6.-", ti{�tf�.
WATER LEVEL DATA:(measured from Top of Casing) Well © Plezometer IDa.Total Well Length ;,{ .&Y /�c. Casing Material ! V(--- e. Length of Water Column /C .3)'of (a-b)
b. Water Table Depth I l , I d. Casing Diameter ,-( I f. Calculated Well Volume(see back) •:": • S'
WELL PURGING DATA
a.Purge Method LcCCL/ /.c:,C-c.1
b.Acceptance Criteria defined(from workplan) l�
-Minimum Required Purge Volume(@ well volumes) Purge Rate: ( ., ml/min.
-Maximum Allowable Turbidity NTUs
-Stabilization of parameters 10 %
c. Field Testing Equipment Used: Make Model Serial Number
.� ` 5S G j.,2 ill i &U` e
Yl1=K . /OC' ' ':<//-26C-
d.
//-26Cd. Field Testing Equipment Calibration Documentation recorded on separate form
Volume TEMP pH Spec.Cond TURBIDITY D.O. ,o,�,l'
Time Removed(ml) C S.U. (umhos) NTUs mg/I Color Odor— DTW
oSYV INITIAL .?&..33 6-0I _ c!3( '13. 9 (,.`(CC CL.\7 1S"2. I( 2-L
OM) I1400 ao.c� s-nt `VI c,-� (16749c.`i �t9 1c8.1 t( 2�
bS :Q, 1oc) tv.v. s. yY 57? Y1.'1 a. 6 CLr{: . lby.s I(.2.L
o 0 , TCO go.oF, c Y 1 c-z.c 0.9,ci 0.5' 0.1 !co._r (1.zz
(Nor- 1 =Teo ter.;. It E .c,c sa.5' 1.1, t O.3t C/, !6. 0 II.2.-7
6`i i v III,74C' 20 1"I L.o Z S',7 r t 7.1 p. 7_,p,7_,p, 1 3`(.3 11.22_
dil.1- Y�9CC -).C/
C . 6,.0'.1 , Sv1-' 1t-I ,o.L' KS) (I. L.L
01 2-05-(( 2C) .2v .tel 6 'C S---":.4,17, y.Sq c :l--1 Rare t t.zL
e. Acceptance criteria pass/fail Yes No N/A
Has required volume been removed ❑ 0
Has required turbidity been reached 0 ❑
Have parameters stabilized - 1 ❑ 0
If no or N/A-Explain below.
SAMPLE COLLECTION: Method: (' /j /c fLJ,vl/"
Sample ID Container Type No.of Containers Preservation Analysis Time
Ci,,;-L 480mL Amber 1 Hno3 As,Cd,Cr,Cu,Fe.Pb,Hg,NI,Se, C ZL
Zn;N
PhCo
None Ph,
Liter Plastic 1 ond.,SO4,TDS,CI rVb
2.r'o nt( (GG) ( /\-oiki' ToC--
Comments
Signature �f 1 --,e----
Date 10/(?/14

'Well/Piezo ID:
EFM,INC. L, —_
Ground Water Sample Collection Record
Client: SCE&G Date: _10// -(/l4
Project No: NPDES Time: Start o()Y 2- am/pm
Site Location: Wateree Station Finish (L.- 3 am/pm
Weather Conds: ;"L c V Y)`' Collector(s) Srilit, _
WATER LEVEL DATA:(measured from Top of Casing) Well © Piezometer ❑
a.Total Well Length ..-2((.r(C' c. Casing Material r'b^C e. Length of Water Column / ' • ,TLi (a-b)
b. Water Table Depth (`-1.1 0 d. Casing Diameter ,-4- f. Calculated Well Volume(see back) •1•
WELL PURGING DATA
a.Purge Method c '-'J /iuCt,/
b.Acceptance Criteria defined(from workplan)
-Minimum Required Purge Volume(@ well volumes) Purge Rate: l 2-0 ml/min.
-Maximum Allowable Turbidity NTUs
-Stabilization of parameters 10 %
c.Field Testing Equipment Used: Make Model Serial Number
Y -GLk Lc ( (2-0
d. Field Testing Equipment Calibration Documentation recorded on separate form
Volume TEMP pH Spec.Cond TURBIDITY D.O. u>u.,
Time Removed(ml) C S.U. (umhos) NTUs mg/I Color -6der- DTW
oci It C INITIAL .'3:3.z,r c,14 ' S'. t+ 3.y( l(t3.4' 1 3 .7 II
G-(SL 1
1, 0 G a3 tf 5 / (( Y 3 ? 7 6 ckVS
7 F, i-
y•ci ( LI. I t:
0J-'1 II3,' O ..:,-.4.0 c-:-.6, -/L- . c.cjc c .s' ) , `t(( •4 1 . i6
/CCL .; voc) , x1-,• J. 1'. Lc\ `i'-ki 3 -1-I 0.EL 177. 6 / . I,G
l
/ons 7 c co -27,.k s .i_.-3 .5 Z-z 3 1-L c, -•1 yY. 0 /V. i-G
/0'1'7 7+ 600 .' 3. II s. 11 -1'30 1.c1 c .J'o 11 •> /Y. iC
r0f1. 9I2-cL .a73, i6 -C'. fl j.3Z -,:? .yb 0 J V _`t /y -1'.7
e. Acceptance criteria pass/fail Yes No N/A
Has required volume been removed ❑ ❑
Has required turbidity been reached - El ❑
Have parameters stabilized ❑ 0
If no or N/A-Explain below.
SAMPLE COLLECTION: Method: /' t.C71'L- (, c,vli
Sample ID Container Type No.of Containers Preservation Analysis Time
u Lv -7 480mL Amber 1 Hno3 As,Cd,Cr,Cu,Fe.Pb,Hg,Ni,Se, (c Z C,
Zn Nei
Liter Plastic 1 None Ph,Conl.d.,SO4,TDS,CI n/p
,SMS ��4 I 1 O(
Comments
Signature 1; ."----//71/: -....-1.--,---N___.. Date_10/(y/14

Well/Piezo ID:
EFM.INC. E't.u,- L/
Ground Water Sample Collection Record ,
Client: SCE&G Date: _101(} /14
Project No: NPDES Time: Start (oYG am/pm
Site Location: Wateree Station Finish it 3.S am/pm
Weather Conds: [C..,!Y so.` Collector(s) S („7540/7F7-2_
WATER LEVEL DATA:(measured from Top of Casing) Well © Piezometer ❑
a.Total Well Length S 1C.�Y c. Casing Material t"— rC- e. Length of Water Column / -2S- (a-b)
•
1.
b. Water Table Depth l• b. �-d. Casing Diameter ` f. Calculated Well Volume(see back) -
WELL PURGING DATA
a.Purge Method LU Lt. /�o LU'
b.Acceptance Criteria defined(from workplan)
-Minimum Required Purge Volume(@ well volumes) Purge Rate: Re ml/min.
-Maximum Allowable Turbidity NTUs
-Stabilization of parameters 10 %
c.Field Testing Equipment Used: Make Model Serial Number
Yri
14-7" `4 /.2../71/0 c."y S'
/ vtf- zt c:cc• 6'1 t,;1-C c
d. Field Testing Equipment Calibration Documentation recorded on separate form
Volume TEMP pH Spec.Gond TURBIDITY D.O. (,,C
Time Removed(ml) C S.U. (umhos) NTUs mg/I Color DTW
/GC& INITIAL 1'2.J( x.31, 't A:3. 1 Y.Y t �Lou'D 3..5' `21•-1-
/ctT) t,z-oo .2.4; C,.'.o CG / Si$ _ t. ?' amu? . / '.'j :l-.1
(OCT' I, $e0 a2 `-ft, 5.81 - ��.r (..C .c G1Y c(-c,.,n 3o . I 21 r7cCt
/1OC L., , Yeo ia.35- CAA f1'6 yy . ' o.(`( C4i -f'.(, ( --1
(1e .f 3/ cc,c3 ;0.3`t S-Al 3-`.f"� . 10 -\ L) . COT 1.\':"--1 .RI .-7y
t t ) 0 3, G c0 ;2, .11 s,.pct S / aY. Y c..c.c .31..1 •Zi ')"I
„ks '-1,.:Z'00 .):- _ -LI c'-ii 5 a3.s u.� �6 .c' .Xl..1y
laze yt �C(eCJ 42.4 _.-'.-- b Y 1 5 oZ3=1 0 I \ 37.'2- 1 .1 Y
e. Acceptance criteria pass/fail Yes No N/A
Has required volume been removed ❑ ❑
Has required turbidity been reached 0 0
Have parameters stabilized ❑ ❑
If no or N/A-Explain below.
•
SAMPLE COLLECTION: Method: / t•f71-I-77 c Ai Ali'
Sample ID� Container Type _ No.of Containers Preservation Analysis Time
(ui `
--( 480mLAmber 1 Hno3 As,Cd,Cr,Cu,Fe.Pb,Hg,Ni,Se, 11 L3
Zn,No3—
(11 Liter Plastic 1 None Ph,Cond.,SO4,TDS,CI t Nu i
Y/ 2)ed lL ( / ( /VaN� %�vc...L....- \/
Comments
Signature . / c� � Date_10//Y/14
( / 7l

•
Well/Piezo ID:
EFM,INC. 5 cu—s—
.
Ground Water Sample Collection Record
Client: SCE&G Date: 10/13/14
Project No: NPDES Time: Start (1.575— am/pm
Site Location: Wateree Station Finish (5-2-o am/pm
Weather Conds: C�".nY Y L° Collector(s) --3--F� 'U,cEU '---
WATER LEVEL DATA:(measured from Top of Casing) Well © Piezometer 0
a.Total Well Length J fir)' c. Casing Material PVC. e. Length of Water Column I y.0 . (a-b)
'1
b. Water Table Depth l9, ,c, d. Casing Diameter - f. Calculated Well Volume(see back) .2•3
WELL PURGING DATA
a.Purge Method G0 �G..7 CC/
b.Acceptance Criteria defined(from workplan)
-Minimum Required Purge Volume(@ well volumes) Purge Rate: 6C ml/min,
-Maximum Allowable Turbidity NTUs
-Stabilization of parameters 10%
c.Field Testing Equipment Used: Make Model Serial Number
y_ 7‘-.- 5 rC IaMrec'o`N
I-MC-11 L(cc-v�� 0 9 0--E>C_
, d. Field Testing Equipment Calibration Documentation recorded on separate form
Volume TEMP pH Spec.Gond TURBIDITY D.O. c•eP
Time Removed(ml) C S.U. (umhos) NTUs m /IColor :Oder— DTW
I'totalINITIAL ....5---3.1 S,Y( ,Q
6 V y_ 3 . 51 Y.20 c4)4 j 9i, 9 :20, (I
(YoS-' il (3o0 •25,(`* 5.8) -711 3.3..7 i .—c) ev )4V G9,9 . o. zy
1Y/o I, 30,0 .32.);,}/ s.°tb g"3y 29, o..?i OaJ04 `/X•'-1 .10 :3'Z
(y l c— 1, 4 0 0 2 J',C-`( c . si cr�i at, 6 0.G CU,c�41 15.0 626,Y o
Nis �
. ,Zofi as-.cc a.10\ Lt3R 11- `-( 0.`l C6L10 33 3 .�o.ti
l 3S a, YO 0 r.-`1 Lao q36 IY . S 0,yr. C(,c..40 31.j 2c.J
1yYs 3,((c)0 2Jr• go 6.00 937 I(.-i o.yz cc¢i} 3i"G .R0.6y
) fl�— , 3 .7 c o 2s'�e S 6. o I VI it. 0.S,3 c.G 30. .L -26. G$
IYTS `/�o�C) �r YY 6,c L k 'Z /o. l( o-3"1 caL Jo.3 2.? I
e. Acceptance criteria pass/fail Yes No N/A
Has required volume been removed W0 ❑
Has required turbidity been reached 0 ❑
Have parameters stabilized A- ❑ ❑
If no or N/A-Explain below.
SAMPLE COLLECTION: Method: 664,w),Er ,' ',v1 7}
Sample ID Container Type No.of Containers Preservation Analysis Time
G —S 480mL Amber 1 Hno3 As,Cd,Cr,Cu,Fe.Pb,Hg,Nl,Se, ISS Q
Zn,Ne3
Liter Plastic 1 None Ph,Cond.,SO4,TDS,CI, 'c•3
J.S-b (66) I. , / /,-, - Te,C-- 'N1
Comments ,;4,rl!'€&T Tin+rd) c(1 iio 0,2r cur-/ ,4 i-—. -- /7; ii-
Signature / � / Date 10/13/14

I
Well/Piezo ID:
EFM,INC. G(- ' - 6
Ground Water Sample Collection Record
Client: SCE&G Date: _10/1 /14
Project No: NPDES Time: Start 175,y am/pm
Site Location: Wateree Station Finish 1330 am/pm
Weather Conds: CGvv,q• S'ZC Collector(s) - FJ: Gi/Q,__.
WATER LEVEL DATA:(measured from Top of Casing) Well © Piezometer 0
a.Total Well Length 42.2.7 c. Casing Material r liC e. Length of Water Column C • c-)-2- (a-b)
b. Water Table Depth 3.2. S d. Casing Diameter , ll f. Calculated Well Volume(see back) /- S—
WELL PURGING DATA
a.Purge Method Z-l0 Cu' Fk Lr }
b.Acceptance Criteria defined(from workplan)
-Minimum Required Purge Volume(@ well volumes) Purge Rate:2'YC'mi/min.
-Maximum Allowable Turbidity NTUs
-Stabilization of parameters 10 %
c.Field Testing Equipment Used: Make Model Serial Number
1-1AC1k --,7rCO 0, G 4/ G C
d. Field Testing Equipment Calibration Documentation recorded on separate form
Volume TEMP pH Spec.Cond TURBIDITY D.O. Og�
Time Removed(ml) C S.U. (umhos) NTUs mg/I Color .6def- DTW
1Z eii INITIAL -T1 c"-.1.l Sal ('], 3 a.9? c1�,;q'- IoC 32.23
11Sj 2,Ye0 al...i 7 c_65/, 31Y ttr.e o. 1 96..? 1Z- '
tkcc., 1 66c J/.3t s.0 3)-ti t( . p_Y`1 9Y T
- / 2L_
I ,X,d,r' `f.,`S� , 1 2_,') .s". c.Y 3 7 c. `1-Y( G 67 G s/6.. 1 2 Z--,.i
i l O , WG ..\.2-L.—c '{ '3 )_9 4-1-- o.t,�, 7 S .32....2s-
gr i
1...zs$ri 'it 2,,e..,(1-) ?1,z-.s 5-.4.,3 33'G c. .97— 0 .33 Y'-. 3t.z -
e. Acceptance criteria pass/fail Yes. No N/A
Has required volume been removed !: ❑ 0
Has required turbidity been reached 0 0
Have parameters stabilized ' ❑ 0
If no or N/A-Explain below.
SAMPLE COLLECTION: Method: &('M5' /0',NI/2
Sample ID Container Type No.of Containers Preservation Analysis Time
Gt,v -6 480mL Amber 1 Hno3 As,Cd,Cr,Cu,Fe.Pb,Hg,Ni,Se, /5?
,
Ph
Liter Plastic
Zb NI L ( ) 1 None Ph,ConCond.,SO4,TDS,CI///o?
( ��n To L_
Comments
Signature 1.5,,--N_ Date_10//.3 /14

Weli/Piezo ID:
EFM,INC. G(A,/ —
Ground Water Sample Collection Record
Client SCE&G Date: _10//3/14
Project No: NPDES Time: Start/64Y am/pm
Site Location: Wateree Station Finish (13S am/pm
Weather Conds: a VPJ,---)Y Cr' Collector(s) "3- ..F7-= /c V
WATER LEVEL DATA:(measured from Top of Casing) Well © Piezometer ❑
a.Total Well Length 5/6.. cj c. Casing Material iabrC, e. Length of Water Column /5'.S i (a-b)
b. Water Table Depth $.,.0 d. Casing Diameter - f. Calculated Well Volume(see back) 3 - u
WELL PURGING DATA //
a.Purge Method C-O(A./ f7o c.-L/.
b.Acceptance Criteria defined(from workplan)
-Minimum Required Purge Volume((@ well volumes) Purge Rate:,76 O mi/min,
-Maximum Allowable Turbidity NTUs
-Stabilization of parameters 10
c.Field Testing Equipment Used: Make Model Serial Number
)/.1- - -ca-Z, l../11(co0t5
/-6+-44 Z/oc 4 09/24 c
d. Field Testing Equipment Calibration Documentation recorded on separate form
Volume TEMP pH Spec.Cond TURBIDITY D.O. oe/'
Time Removed(ml) C S.U. (umhos) NTUs mg/I Color -Odor-- DTW
14 L---) INITIAL .22...CS 57 6S-1 "77.? 2.$lo c4;,Lo y -b-.--2_ x2$.2..1-
(6 3 Le-
..-
(63Lt a,00'G ,., 1.y`( ...c `( 65-t) S/. O.9Slr1:,�AG Yo. t Z3. 2.YY
lc,'S9 '3/ 000 at, 6.oc� (Y ,S
/ ' -. ©SYc:4,(41 ii- o ,2,y. .z1
16 YY tf Do 0 aL S 6.oz (,3c> . 4.i K. o.30 c60, t3. ( ma .3z,
1 -"F" 6', 6 0 2( .6Y 6 - y (;3v _36• o. ict c4:vn lb.-) aV. 32
iio.- $ /00o at.Yc 6.02- 6.2-k Act. o-('1 c (2-5- z'.29
Ci a
111.5 /0,oc ( -Q'S' (,.o0 6:21 91-Ci_ o,ii c_t Is-.O ,,73.zet
1120 l(i 0 c C) 3-1 -ct _ 3",°?° L.521 91.Lt o .S - circ 1'- Y a5).3c.,
e. Acceptance criteria pass/fail Yes No N/A
Has required volume been removed 0 0
Has required turbidity been reached 0 0
Have parameters stabilized 0 0
If no or N/A-Explain below.
SAMPLE COLLECTION: Method: 8j',q/,..,L4-,_ /00-,,v1/'
Sample ID Container Type No.of Containers Preservation Analysis Time
GU,-) - " 480mL Amber 1 Hno3 As,Cd,Cr,Cu,Fe.Pb,Hg,Ni,Se, ('lz2-
Zn Wen=
Liter Plastic 1 None Ph,Cond.,SO4,TDS,CI I,A/G; /21-0,,n, 64) l �� 7�c�
Comments
SignaturV A,..-u,c--/ Date_10113/14

WelVPiezo ID: �j
EFM,INC. G L - - 1
Ground Water Sample Collection Record
Client: SCE&G Date: _10l( /14
Project No: NPDES Time: Start /570 am/pm
Site Location: Wateree Station Finish I L I(c) am/pm
Weather Conds: /', S of../N y 1 z," Collector(s) 7\--/.L.:7---- -GGA V ' -
WATER LEVEL DATA:(measured from Top of Casing) Well © Piezometer 0
a.Total Well Length 3C.30 c. Casing Material PVC e. Length of Water Column I Y_/ Ci (a-b)
it
b. Water Table Depth 2/.,,2 0 d. Casing Diameter 3- f. Calculated Well Volume(see back) d- 3
WELL PURGING DATA ,
a.Purge Method (CiAr F L& /
b.Acceptance Criteria defined(from workplan)
-Minimum Required Purge Volume(@ well volumes) Purge Rater°C'ml/min.
-Maximum Allowable Turbidity NTUs
-Stabilization of parameters 10 %
c.Field Testing Equipment Used: Make Model Serial Number
YJ= STG Ofrz( aCCJ 5
/'-/ c4 R/Goc� 69(26,G
d. Field Testing Equipment Calibration Documentation recorded on separate form
Volume TEMP pH Spec.Cond TURBIDITY D.O. .cy,nf'
Time Removed(ml) C S.U. (umhos) NTUs mg/l Color -Odor DTW
IS3Y INITIAL La_3_Z`) .ss 1 I (E. 3 , yl , `( k-(. 3 (, { 71.4 di.›_..-/-
lSSvo c ,00o :2(.9 S'-C"1- i'13.-\---- _ ,Y U7�
.0 .2. 'LL'Dv 6s'. 3i. 1-3
iDiF .: ,c) -c) at u% j-�.l tic-2_ 19 . '7 O. t cL ,11, 62-ci at .-z
/s10 1, o00 21.1 '( 5',6C. t`1L,4 ic- I 0,E: c-Lr<4,e. (o-3 (�1.-2-
l$ f j^ s- 0Oc d1-1 ct s.C,Cz t'1 L2 l .�( o . LOW -' Z(- t-~
/6c� 61 cc 1 .1 , S.1,is i`t (, , 1 .s'l o,s- 7, .03, ?1 , 2_S-
e. Acceptance criteria pass/fail Yes No N/A
Has required volume been removed g ❑ ❑
Has required turbidity been reached ❑ ❑
Have parameters stabilized --0- ❑ ❑
If no or N/A-Explain below.
SAMPLE COLLECTION: Method: /,e��,r/-AGS is f'c/rt?/)
Sample ID Container Type No.of Containers Preservation Analysis Time
J+-J —cc 480mL Amber 1 Hno3 As,Cd,Cr,Cu,Fe.Pb,Hg,Ni,Se, /6o L
Zn
Ph Con I
Liter Plastic 1 None Ph,Cond.,SO4,TDS,CI+�o?
,,i/ 22b,p 1, KC.61 I ,,�r- ro L V
Comments
Signature_ v -1',"------- Date 10/13/14

Well/Piezo ID:
EFM,INC. G(A),-
Ground Water Sample Collection Record
Client: SCE&G Date: 10/t.3/14
Project No: NPDES Time: Start 12.130 am/pm
Site Location: Wateree Station Finish 13 YS am/pm
Weather Conds: CI. vDY S(6t) Collector(s) ' ,5/5 /hAVT,c
WATER LEVEL DATA:(measured from Top of Casing) Well © Piezometer 0
a.Total Well Length .2.25 n c. Casing Material /'(/LI e. Length of Water Column •C,( S (a-b)
b. Water Table Depth j 7. (,�, d. Casing Diameter :". f. Calculated Well Volume(see back) 0_ 5'`j`
WELL PURGING DATA
a.Purge Method C.0 t.t., ,�/�U
b.Acceptance Criteria defined(from workplan)
-Minimum Required Purge Volume(© well volumes) Purge Rate: �C3 ml/min.
-Maximum Allowable Turbidity NTUs
-Stabilization of parameters 10 %
c.Field Testing Equipment Used: Make Model Serial Number
,y4t- ss-C (,7'v1 loc.'o?g
I44cff ..,2lob? O?l.2o L.
d. Field Testing Equipment Calibration Documentation recorded on separate form
Volume TEMP pH Spec.Gond TURBIDITY D.O. o,�
Time Removed(ml) C S.U. (umhos) NTUs m /I Color Odor DTW
I LSI- INITIAL ?S7 6.o t1. .2c L 30. 1 3,C. c�Y /�-3 11. ti3
no c, t10cc, a2,3( S.9S 1g . 19. . I. (.5 C( i c.0 (-7 S-5
130.7 t 13 c o X7.5( ST,Z. / b'' i'(-ex 0.1`\ cz (S'3. ,-(- 1 . 1,4
('i t v I,6 e,G L2-.2.16 SA t t 8 13. I 0. 21- C(4;82 I rr..1 Ii .4`1
1"5 I T (1 9 c _la.77 J',$2`, 1`6 1- 0.11 (--&-642 f Y?_7 /1.�'3
1-31c) a, 7....<90 aa.K. r,'218O (a .Y '7
e . '( cai--44, irn
E_9 .-tl
13zS" ,S00 .712.? 5'.-11 Lick (<2-0 D."2( air-4Q.__ tY4:-1 l?,Ya
e. Acceptance criteria pass/fail Yes No N/A
Has required volume been removed 0 ❑
Has required turbidity been reached !d 0 ❑
Have parameters stabilized 0 0
If no or N/A-Explain below.
SAMPLE COLLECTION: Method: /s art -7 /'„„„,p
Sample ID Container Type No.of Containers Preservation Analysis Time
G C \( 480mL Amber 1 Hno3 As,Cd,Cr,Cu,Fe.Pb,Hg,Ni,Se, (3..2-1
\i/
Zn,Ne3-
L(terPtastic 1 None Ph,Cond.,SO4,TDS,Cl/(,fd; \/
(,w -(L aro 6C4-Sr I rLorvr--- TO c Ni
Comments
Signature l ,-2 .--..-4...-1.---e--..„_ Date 10/(3/14

Central Laboratory (P-08)
1-1111;01Eke. 2102 North Lake Drive
A SCANA COMPANY Columbia, SC 29212
Tel: [phone]
Fax: [phone] . .
•
October 27, 2014
iipb:#40144,;"1
?„,:i...s.ii-.,::' :-$.',.-1•-• - - - - :,---'''''''' Sample ID: AB13096
Mike Moore C221
Wateree NPDES Well MW 1 Total Metals (NPDES)
Michael Cade A221
Date&Time Sampled: October 14,2014 12:18
Date&Time Submitted: October 14,2014 15:40
Collected by: J.LEAVER Location Code: WAGO1TM
MW 1 Login Record File: 141014155108
•-_,.,-.-.1_-_,•,--:--,,:,•::•:“. ,,:-;,.w.,,,..:_;2*-•_,-.--.::•:,_-:.:i,..„:;:.,,,-,L,:,,!-,,..,):,,,k:, , ,,.,:mel.1f,t,pporlinl-1_,T,.;iiiii:4 ,42.f:-:,criplptecli-49 !Ypkti-Aik:'
criglifj, ,.9:11y§ppli. jkAla,19,M.-P'9); Nct.;5?fivsZS::-- iiiilito04., .. -.2 ,-.,.-= :.--,:-'w,..Date'&'Thee. .1!,:„'1-..•, ,:v.1-,,,i,-.;:,,N,,::,
Arsenic by ICP_OES EPA 2001 Less than 5.0 ppb 10/20/14 09:05 MC
Cadmium by ICP_OES EPA 200.7 Less than 1.0 ppb 10/20/14 09:05 MC
Chromium by ICP-OES EPA 200.7 Less than 5.0 ppb 10/20/14 09:05 MC
Copper by ICP-OES 200.7 Less than 10.0 ppb 10/20/14 09:05 MC
Iron EPA 200.7 15.4 10.0 ppb 10/20/14 09:05 MC
Lead(CWA)200.7 Less than 5.0 ppb 10/20/14 09:05 MC
Mercury(CWA)by EPA 245.2 Less than 0.2 ppb 10/20/14 09:58 PRC
Nickel by ICP EPA 200.7 Less than 10.0 ppb 10/20/14 09:05 MC
Selenium by ICP EPA 200.7 Less than 10.0 ppb 10/20/14 09:05 MC
Zinc by ICP-OES 200.7 20.4 10.0 ppb 10/20/14 09:05 MC
If there are any questions concerning this sample, please contact the lab at 3)217-9384.
Approved By:
Page 1 of 1

4raggeam-Ee. Central Laboratory (P-08)
2102 North Lake Drive
A SCANA COMPANY Columbia, SC 29212 .
Tel: [phone]
Fax: [phone]
October 27, 2014
, •'.-,:i:P.,:i1.?:.,1-..-:,,--._--A.-,-.,--...•...'--,..0,
..-_',,-,. ,,,p.A7.3-,-.,Q:-,,,,,,
REPPM07..-.5:'i':-..,.N•tV:),.:--.:0,
Sample ID: AB13093
Mike Moore C221
Wateree NPDES Well MW 2 Total Metals (NPDES)
Michael Cade A221
Date&Time Sampled: October 14, 2014 09:22
Date&Time Submitted: October 14, 2014 15:40
Collected by: J.LEAVER Location Code: WAGO2TM
MW 2 Login Record File: 141014155108
••H. '..-.-.' '''''':.rn"•.:'-'-'"—:' ';' t'-'-' :'-'n'''''--:'-.
..,9ZT,IF1- .P.PY.: 9.P7,,,..9.‘,9,:rP.IR. F-99f.9-1, 4:-i.,,,P-, i1..[ *6---,`-1-'i--i! 1...,:I
I-:P9FP21f14A -,IYPiR ogiiii::',
Arsenic by ICP_OES EPA 200.7 Less than 5.0 ppb 10/20/14 08:57 MC
Cadmium by ICP_OES EPA 200.7 Less than 1.0 ppb 10/20/14 08:57 MC
Chromium by ICP-OES EPA 200.7 Less than 5.0 ppb 10/20/14 08:57 MC
Copper by ICP-OES 200.7 Less than 10.0 ppb 10/20/14 08:57 MC
iron EPA 200.7 18300 1000 ppb 10/20/14 08:57 MC
Lead (CWA)200.7 Less than 5.0 ppb 10/20/14 08:57 MC
Mercury(CWA)by EPA 246.2 Less than 0.2 ppb 10/16/14 15:30 PRC
Nickel by ICP EPA 200.7 Less than 10.0 ppb 10/20/14 08:57 MC
Selenium by ICP EPA 200.7 Less than 10.0 ppb 10/20/14 08:57 MC
Zinc by ICP-OES 200.7 61.9 10.0 ppb 10/20/14 08:57 MC
If there are any questions concerning this sample, please contact the lab at(803)217-9384.
Approved By: --A
Page 1 of 1

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Central Laboratory(P-08)
g� 2102 North Lake Drive
- �m��vv Columbia, SC 29212
�oo�^muu�,�wr
Tel: 7'9884
Fax: [phone]
October 27, 2014
="nYa=°°'�1 ~^0 '~^ 1°'~-~~kt_ ''~ Sample ID: AB13094
Mike Moore C221
INatenme NPDES Well MW 3 Total Metals (NPDES)
Michael Cade A221 �
D�e&Time Sampled: O�obori4. 2Di4 10:20 !
Date&Time Submitted: October 14,2014 15:40
Collected by: J.LEAVER Location Code: WAGO3TM
MVV3 Login Record File: 141014156108
Arsenic by ICP_OES EPA 200.7 122 5.0 ppb 1020h4 08:57 MC
------'_------ __---- ---_--_
Cadmium by ICP_OES EPA 200.7 Less than 1.0 ppb 10/20/14 08:57 MC
Chromium by ICP-OES EPA 200.7 Less than 5.0 ppb 10/20/14 08:57 MC
—Copper by ICP-OES 200.7
_Copporby|OP-OES2OO.7 Less than 10.0 ppb 10/20/14 08:57 MC
Iron EPA 200.7 13000 1000 ppb 10/20/14 08:57 MC
Lead (CWA)200.7 Less than 5.0 ppb 1020h4 08:67 MC
—Mercury
--
K8anzury(CVVA)byEPA245.2 Less than 0.2 ppb 10/20/14 89:50 PRC
Nickel by ICP EPA 200.7 Less than 10.0 ppb 10/2014 08:57 MC •
Selenium by ICP EPA 200.7 Less than 10.0 ppb 10/20/14 08:57 MC
'----' -- ----'''-'-- —
Zinc by ICP-OES 200.7 Less than 10.0 ppb 10/20/14 08:57 MC
- ' -_ ____'__ -__
If there are any questions concerning this sample, please contact the lab at(8
17�384
Approved By: (-)J
/
J / .'
.
.

Central Laboratory (P-08)
SCEGO 2102 North Lake Drive
A SCANA COMPANY Columbia, SC 29212
Tel: [phone]
Fax: [phone]
October 27, 2014
REPORTTO
Sample ID: AB13095
Mike Moore C221
Wateree NPDES Well MW 4 Total Metals (NPDES)
Michael Cade A221
Date&Time Sampled: October 14,2014 11:23
Date&Time Submitted: October 14,2014 15:40
Collected by: J.LEAVER Location Code: WAGO4TM
MW 4 Login Record File: 141014155108
CERTIFIED BY SQDHEC(LAB ID 3201)6) Result Urnts QompedAnaiySS I0mlst
.Date'8t.Time
Arsenic by ICP_OES EPA 200.7 Less than 5.0 ppb 10/20/14 08:57 MC
Cadmium by ICP_OES EPA 200.7 3.7 1.0 ppb 10/20/14 08:57 MC
Chromium by ICP-OES EPA 200.7 Less than 5.0 ppb 10/20/14 08:57 MC
Copper by ICP-OES 200.7 Less than 10.0 ppb 10/20/14 08:57 MC
Iron EPA 200.7 83200 10.0 ppb 10/20/14 08:57 MC
Lead(CWA)200.7 Less than 5.0 ppb 10/20/14 08:57 MC
Mercury(CWA) by EPA 245.2 Less than 0.2 ppb 10/16/14 15:30 PRC
Nickel by ICP EPA 200.7 Less than 10.0 ppb 10/20/14 08:57 MC
Selenium by ICP EPA 200.7 Less than 10.0 ppb 10/20/14 08:57 MC
Zinc by ICP-OES 200.7 61.9 10.0 ppb 10/20/14 08:57 MC
If there are any questions concerning this sample, please contact the lab at(803)217-9384.
t( jC)''
Approved By:
Page 1 of 1

Central Laboratory (P-08)
SCE 1 O 2102 North Lake Drive
A SCANA COMPANY Columbia, SC 29212
Tel: [phone]
Fax: [phone]
October 27, 2014
�•t'-}.,. } i..::; REPORT TO 'a '. . . . fix:
Sample ID: AB12966
Mike Moore C221 Wateree NPDES Well MW 5 Total Metals (NPDES)
Michael Cade A221
Date&Time Sampled: October 13, 2014 15:00
Date&Time Submitted: October 14, 2014 07:20
Collected by: J.LEAVER Location Code: WAGO5TM
MW 5 Login Record File: 141014082053
Iteportin9' Units Completed Analysis Cheiist
Arsenic by ICP_OES EPA 200.7 Less than 5.0 ppb 10/17/14 14:53 MC
Cadmium by ICP_OES EPA200.7 Less than 1.0 ppb 10/17/14 14:53 MC
Chromium by ICP-OES EPA 200.7 Less than 5.0 ppb 10/17/14 14:53 MC
Copper by ICP-OES 200.7 Less than 10.0 ppb 10/17/14 14:53 MC
Iron EPA 200.7 155000 1000 ppb 10/22/14 10:53 MC
Lead(CWA)200.7 6.2 5.0 ppb 10/17/14 14:53 MC
Mercury(CWA)by EPA 245.2 Less than 0.2 ppb '10/16/14 15:30 PRC
Nickel by ICP EPA 200.7 Less than 10.0 ppb 10/17/14 14:53 MC
Selenium by ICP EPA200.7 Less than 10.0 ppb 10/17/14 14:53 MC
Zinc by ICP-OES 200.7 59.6 10.0 ppb 10/17/14 14:53 MC
If there are any questions concerning this sample, please contact the lab at(803)217-9384.
Approved By:
Page 1 of 1

�s Central Laboratory (P-08)
SVE�0o 2102 North Lake Drive ..
A SCANA COMPANY Columbia, SC 29212
Tel: [phone]
Fax: [phone]
October 27, 2014
Y 'REPORT,TO
Sample ID: AB12969
Mike Moore C221 Wateree NPDES Well MW 6 Total Metals (NPDES)
Michael Cade A221
Date&Time Sampled: October 13,2014 18:17
Date&Time Submitted: October 14, 2014 07:20
Collected by: J.LEAVER Location Code: WAGO6TM
MW 6 Login Record File: 141014082053
Repo[hng' Completed Analyse' .Chemist
CERTIFIED BY SCDHC- LAB AD 32p06 L Result 4nits
( ) Lmlt(lR )I Rate&Time
Arsenic by ICP_OES EPA 200.7 Less than 5.0 ppb 10/20/14 07:52 MC
Cadmium by ICP_OES EPA 200.7 Less than 1.0 ppb 10/20/14 07:52 MC
Chromium by ICP-OES EPA 200.7 Less than 5.0 ppb 10/20/14 07:52 MC
Copper by ICP-OES 200.7 Less than 10.0 ppb 10/20/14 07:52 MC
Iron EPA200.7 20200 1000 ppb 10/20/14 07:52 MC
Lead(CWA)200.7 Less than 5.0 ppb 10/20/14 07:52 MC
Mercury(CWA)by EPA 245.2 Less than 0.2 ppb 10/16/14 15:30 PRC
Nickel by ICP EPA 200.7 31.1 10.0 ppb 10/20/14 07:52 MC
Selenium by ICP EPA200.7 Less than 10.0 ppb 10/20/14 07:52 MC
Zinc by ICP-OES 200.7 22.5 10.0 ppb 10/20/14 07:52 MC
If there are any questions concerning this sample, please contact the lab at(803)217-9384.
n
Approved By:
Page 1 of 1

'
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Central Laboratory (P-08)
�1�� yA��hL��� []r��
��~�����"��='=��o Columbia, S�� 29212
ASCANA COMPANY
Tel: 7-9384
Fax: [phone]
October 27. 2O14
~~"^'^ ^ ~^''~~~'-`'~~ ------~'-`--- Sample ID: AB12968
Mike Moore C221
Wateree NPDES Well MW 8 Total Metals (NPDES)
Michael Cade A221
Date&Time Sampled: October 13,2014 17:22
Date&Time Submitted: October 14,2014 07:20
Collected by: J.LEAVER Location Code: WAGO8TM
/NVV8 Login Record File: 141014082053
Reawt
| |
‘ n0m �mu � �kea���mma��� q%mr�e'p.ypce�/ov :a� .�casus� ,De°.&^ vss ,^z^*:'^s=*:',
Arsenic by|Op_OE8EPA 2OU.7 Less than 5.0 ppb 10h7M4 14:53 MC
Cadmium by ICP_OES EPA 200.7 Less than 1.0 ppb 10d7d4 14:53 MC
Chromium by ICP-OES EPA 200.7 Less than 5.0 ppb 10M7/14 14:53 MC
Copper by ICP-OES 200.7 Less than 10.0 ppb 10d7/14 14:53 MC
Iron EPA 2DO.7 89100 1000 ppb 10/22/14 10:53 MC
Lead(CWA)200.7 Less than 5.0 ppb 10d7/14 14:53 MC
�
1 Mercury�X0AJbyEPA Z45.2 Less than 0.2 ppb 10/16/14 15:30 PRC
|
---' -- ' -- ' -- --- -'--------- - -- ---- - |
Nickel by ICP EPA 200.7 174 10.0 ppb 10U7U4 14:53 MC
Selenium by ICP EPA 200.7 Less than 10.0 ppb 10/17/14 14:53 MC
- _—'-_'-__—_- -. - --'-' ''-- -- --_
Zinc by ICP-OES 200.7 50.5 10.0 ppb 10U7U4 14:63 MC
- -----'----' --------''— -----------
If there are any questionconcerning this sampleplease contact the lab at(80 , 17-9384.
/ --
Approved By:
~_AppmvedBy: A_A.

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Central Laboratory ��0)
i� �102 &|orthLake C>�ve
��~-�-����~~��~�~~ Columbia, SC2g212
ASCANA COMPANY
Tel: [phone]
Fax: [phone]
October 27, 2014
~^``-~~ -~~�~-'--'-~^-- --- ---` Sample ID: AB12967
Mike Moore C221
Wateree NPDES Well MW 9 Total Metals (NPDES)
Michael Cade A221
Date&Time Sampled: October 13,2014 16:02
Date&Time Submitted: October 14,2014 07:20
Collected by: J.LEAVER Location Code: WAGO9TM
WYVV9 Login Record File: 141014082053
^r~=^ ^~ - 1hemt
^ ^ ~ ''"`' ~° ° �~ =~ "~��~�'| , =^=`^|,~ ~-~` -` ~°= ^ ~
•
~-~~- ~
Arsenic by ICP_OES EPA 200.7 Less than 5.0 ppb 10/17/14 14:53 MC
Cadmium by |CP_OE8EPA 200J Less than 1.0 ppb 10d7/14 14:53 MC
Chromium by ICP-OES EPA 200.7 Less than 5.0 ppb 1037/14 14:53 MC
--'--
Copper by ICP-OES 200.7 Less than 10.0 ppb 10/17/14 14:53 MC i
-----' - -' ----- --------
Iron EPA 20O.7 201000 1000 ppb 10/22/14 10:53 MC
Lead(CWA)200.7 11.5 5.0 ppb 10/17/14 14:53 MC
_- ----- -_'_-_- --'_---___---
Mercury(CVVA)byEPA2452 Less than 0.2 ppb 10d0d4 15:30 PRC
Nickel by ICP EPA 200.7 Less than 10.0 ppb 10d7d4 14:58 MC
Selenium by ICP EPA 200.7 Less than 10.0 ppb 1017d4 14:53 MC
- -- --- - -
Zinc by ICP-OES 200.7 91.4 10.0 ppb 10d3M4 14:53 MC
__
If there are any questions concerning this sample, please contact the lab at(803)217-9384.
__---
Approved By:
-'AppmvodBy: azD A /v —

Central Laboratory (P-08)
SCEJW 2102 North Lake Drive
A SCANA COMPANY • Columbia, SC 29212
Tel: [phone]
Fax: [phone]
October 27, 2014
t ORT O� ' ,.
A Sample ID: AB12965
�. REP_ - m
Mike Moore C221 Wateree NPDES Well MW 11 Total Metals (NPDES)
Michael Cade A221
Date&Time Sampled: October 13,2014 13:27
Date&Time Submitted: October 14,2014 07:20
Collected by: J.LEAVER Location Code: WAGIITM
MW 11 Login Record File: 141014082053
Reporting CotnpletgdArtallysis 4hemist";
CERTIFIED RY ScDHC'(LAB;ID 32O 6) 1 Result_. Llmit(MRL);I nits ...�I_. :, L,D let&Time ;s,: .,-.,;,
Arsenic by ICP_OES EPA 200.7 101 5.0 ppb 10/17/14 13:07 MC
Cadmium by ICP_OES EPA 200.7 Less than 1.0 ppb 10/17/14 13:07 MC
Chromium by ICP-OES EPA 200.7 Less than 5.0 ppb 10/17/14 13:07 MC
Copper by ICP-OES 200.7 Less than 10.0 ppb 10/17/14 13:07 MC
Iron EPA200.7 1070 10.0 ppb 10/17/14 13:07 MC
Lead(CWA)200.7 Less than 5.0 ppb 10/17/14 13:07 MC
Mercury(CWA)by EPA245.2 Less than 0.2 ppb 10/16/14 15:30 PRC
Nickel by ICP EPA 200.7 Less than 10.0 ppb 10/17/14 13:07 MC
Selenium by ICP EPA200.7 13.7 10.0 ppb 10/17/14 13:07 MC
Zinc by ICP-OES 200.7 51.8 10.0 ppb 10/17/14 13:07 MC
If there are any questions concerning this sample, please contact the lab at(83)217-9384.
Approved By: •1/4,..j.j\___, ---IAA/\------------
Page 1 of 1

Central Laboratory (P-08)
SCEG0 2102 North Lake Drive
A SCANA COMPANY Columbia, SC 29212
Tel: [phone]
Fax: [phone]
October 17, 2014
Sample ID: AB13103
Mike Moore C221 Wateree NPDES Well MW 1 (NPDES)
Michael Cade A221
Date&Time Sampled: October 14, 2014 12:18
Date&Time Submitted: October 14, 2014 15:40
Collected by:J.LEAVER Location Code: WAGOITDS
MW 1 Login Record File: 141014155108
VaR1016:**6470,1*0413k1p0,,goommor,,,ng)i {su � Co Da t 8� cirrieIc�tL I i _f I
Chlorides by IC EPA 300.0 5.8 0.5 mg/L 10115/14 13:55 TG
Conductivity, EPA 120.1 (1982) 70.6 0.05 umhos 10/15/14 14:09 PRC
Nitrate-N by IC, EPA 300.0 1,88 0.11 mg/L as N 10/15/14 13:55 TG
pH by SM4500HB 5.27 0.00 S.U. 10/15/14 14:09 PRC
Holding Time of 15 minutes has been exceeded.
Sulfates by IC EPA 300.0 Less than 0.5 mg/L 10/15/14 13:55 TG
Total Dissolved Solid-SM2540C 39 2.0 mg/L 10/17/14 15:03 CDB
If there are any questions concerning this sample, please contact the lab at(:53)217-9384.
Approved By:
Page 1 of 1

Central Laboratory (P-08)
SCE. so 2102 North Lake Drive
Columbia, SC 29212
A SCANA COMPANY Tel: [phone]
Fax: [phone]
October 17, 2014
REPORTi O ,1 � . Sample ID: AB13100
Mike Moore C221 Wateree NPDES Well MW 2 (NPDES)
Michael Cade A221
Date&Time Sampled: October 14,2014 09:22
Date&Time Submitted: October 14, 2014Code:40
WAG02TDS
Collected by: J.LEAVER Location
MW 2 . ... iR Login Record File: 14
1014155108
CRTFI YSGDEG( ABD 2006 � Ul , lmoMn,, tls il 'Tysr
Cem
...-
Chlorides by IC EPA 300.0 89.1 0.5 mg/L 10/15/14 13:55 TG
Conductivity, EPA 120,1 (1982) 490.8 0.05 umhos 10/15/14 14:09 PRC
Nitrate-N by 1C, EPA 300.0 Less than 0.11 mg/L as N 10/15/14 13:55 TG
pH by SM4500HB 6.39 0.00 S.U. 10/15/14 14:09 PRC
Holding Time of 15 minutes has been exceeded.
Sulfates by IC EPA 300.0 45.2 0.5 mg/L 10/15/14 13:55 TG
Total Dissolved Solid-SM2540C 278 2.0 mg/L 10/17/14 15:03 CDB
If there are any questions concerning this sample, please contact the lab at(803)217-9384.
Approved By: J
Page 1 of 1

Central Laboratory(P-08)
scEa0 2102 North Lake Drive
A SCANA COMPANY Columbia, SC 29212
Tel: [phone]
Fax: [phone]
October 17, 2014
REPORT b y
t Sample ID: AB13101
Mike Moore C221 Wateree NPDES Well MW 3 (NPDES)
Michael Cade A221
Date&Time Sampled: October 14,2014 10:20
Date &Time Submitted: October 14,2014 15:40
Collected by: J.LEAVER Location Code: WAGO3TDS
MW 3 Login Record File: 141014155108
ReportingComplete IA-WY-- ICh
V etnist
CERTJFIED BYE 5CD)iECs�LAB ID 32006)' Result_ I Limlt(MRL) ,ti°�ts Date'&71me, s
Chlorides by IC EPA 300.0 110 0.5 mg/L 10/15/14 13:55 TG
Conductivity, EPA 120.1 (1982) 695.1 0.05 umhos 10/15/14 14:09 PRC
Nitrate-N by IC,EPA 300.0 Less than 0.11 mg/L as N 10/15/14 13:55 TG
pH by SM4500HB 6.55 0.00 S.U. 10/15/14 14:09 PRC
Holding Time of 15 minutes has been exceeded.
Sulfates by IC EPA 300.0 59.1 0.5 mg/L 10/15/14 13:55 TG
Total Dissolved Solid-SM2540C 393 2.0 mg/L 10/17/14 15:03 CDB
If there are any questions concerning this sample, please contact the lab at(803)217-9384.
Approved By: JJ\D
Page 1 of 1

Central Laboratory (P-08)
SCE�IrG® 2102 North Lake Drive
Columbia, SC 29212
A SCANA COMPANY Tel: [phone]
Fax: [phone]
October 17, 2014
,,,$-} REPOi'2T 01 K a r Sample ID: AB13102
Mike Moore C221 Wateree NPDES Well MW 4 (NPDES)
Michael Cade A221
Date&Time Sampled: October 14,2014 11:23
Date&Time Submitted: October 14,2014 15:40
Collected by:J.LEAVER Location Code: WAGO4TDS
MW 4 Login Record File: 141014155108
li;04:6:44.14.*'
$CHED( 29`)k Retr #epUtdg4i4 ?CaPeewndss4I
CIHml$f'I
7,, jk‘ ltrOt MRLy41Is . D tev&Time. TV
Chlorides by IC EPA 300.0 45.8 0.5 mg/L 10/15/14 13:55 TG
Conductivity, EPA 120.1 (1982) 486.5 0.05 umhos 10/15/14 14:09 PRC
Nitrate-N by IC, EPA 300.0 Less than 0.11 mg/L as N 10/15/14 13:55 TG
pH by SM4500HB 5.92 0.00 S.U. 10/15/14 14:09 PRC
Holding Time of 15 minutes has been exceeded.
Sulfates by IC EPA 300.0 0.96 0.5 mg/L 10/15/14 13:55 TG
Total Dissolved Solid-SM2540C 248 2.0 mg/L 10/17/14 15:03 CDB
If there are any questions concerning this sample, please contact the lab at(803)217-9384.
Approved By:
:JAA/ —_______
Page 1 of 1

Central Laboratory (P-08)
SCE�i r�so 2102 North Lake Drive
A SCANA COMPANY Columbia, SC 29212
Tel: [phone]
Fax: [phone]
October 17, 2014
", REPORT TO
Sample ID: AB12974
Mike Moore C221 Wateree NPDES Well MW 5 (NPDES)
Michael Cade A221
Date&Time Sampled: October 13, 2014 15:00
Date&Time Submitted: October 14, 2014 07:20
Collected by: J.LEAVER Location Code: WAGO5TDS
MW 5 Login Record File: 141014082053
"
P
or
t
ited Analysis chemist
CERTIFIED BY SCDHEC'(LAB ID 32006) Result t;lmit MRL UnEts Datel,Time
Chlorides by IC EPA 300.0 43.3 0.5 mg/L 10/14/14 13:47 TG
Conductivity, EPA 120.1 (1982) 632 0.05 umhos 10/15/14 13:46 PRC
Nitrate-N by IC, EPA 300.0 Less than 0.11 mg/L as N 10/14/14 13:47 TG
pH by SM4500HB 6.01 0.00 S.U. 10/15/14 13:46 PRC
Holding Time of 15 minutes has been exceeded.
Sulfates by IC EPA 300.0 Less than 0.5 mg/L 10/14/14 13:47 TG
Total Dissolved Solid-SM2540C 706 2.0 mg/L 10/15/14 12:00 CDB
If there are any questions concerning this sample, please contact the lab at(803)217-9384.
Approved By:
cpt,"-ku ,
Page 1 of 1

Central Laboratory (P-08)
SCE�1 O 2102 North Lake Drive
A SCANA COMPANY Columbia, SC 29212
Tel: [phone]
Fax: [phone]
October 17, 2014
REPQRT TQ a 2
Sample ID: AB12977
Mike Moore C221 Wateree NPDES Well MW 6 (NPDES)
Michael Cade A221
Date&Time Sampled: October 13,2014 18:17
Date&Time Submitted: October 14,2014 07:20
Collected by: J.LEAVER Location Code: WAGO6TDS
MW 6 Login Record File: 141014082053
Reporting CorripletedAnalys�s t,Ghemist,,;
C RTIFIEp �SCDHEC(LAS JD 3'2006).' Zesu�t `Lurr it(MRL) ' spits ; , pate&Tune.;.
Chlorides by IC EPA 300.0 37.6 0.5 mg/L 10/14/14 13:47 TG
Conductivity, EPA 120.1 (1982) 260.2 0.05 umhos 10/15/14 13:46 PRC
Nitrate-N by IC, EPA 300.0 Less than 0.11 mg/L as N 10/14/14 13:47 TG
pH by SM4500HB 5.92 0.00 S.U. 10/15/14 13:46 PRC
Holding Time of 15 minutes has been exceeded.
Sulfates by IC EPA 300.0 26.2 0.5 mg/L 10/14/14 13:47 TG
Total Dissolved Solld-SM2540C 188 2.0 mg/L 10/15/14 12:00 CDB
If there are any questions concerning this sample,please contact the lab at 803)217-9384.
Approved By:
•
Page 1 of 1

Central Laboratory (P-08)
SCE 1 ® 2102 North Lake Drive
A SCANA COMPANY Columbia, SC 29212
Tel: [phone]
Fax: [phone]
October 17, 2014
REPORT TO!
Sample ID: AB12976
Mike Moore C221 Wateree NPDES Well MW 8 (NPDES)
Michael Cade A221
Date&Time Sampled: October 13, 2014 17:22
Date&Time Submitted: October 14, 2014 07:20
Collected by: J.LEAVER Location Code: WAGO8TDS
MW 8 Login Record File: 141014082053
• R.@porting Gompleted Analysts Chemist `
CERTIFIEp BY$CDHEC(LAB ID 32pOt) Resulk'
'LI in t(MRL)I Units ( pate&Time
Chlorides by IC EPA 300.0 19.6 0.5 mg/L 10/14/14 13:47 TG
Conductivity, EPA 120.1 (1982) 502 0.05 umhos 10/15/14 13:46 PRC
Nitrate-N by IC, EPA 300.0 0.19 0.11 mg/L as N 10/14/14 13:47 TG
pH by SM4500HB 6.06 0.00 S.U. 10/15/14 13:46 PRC
Holding Time of 15 minutes has been exceeded.
Sulfates by IC EPA 300.0 77.4 0.5 mg/L 10/14/14 13:47 TG
Total Dissolved Solid-SM2540C 448 2.0 mg/L 10/15/14 12:00 CDB
If there are any questions concerning this sample, please contact the lab at(803 217-9384.
Approved By:
Page 1 of 1

Central Laboratory(P-08)
2102 North Lake Drive
A SCANA COMPANY Columbia, SC 29212
Tel: [phone]
Fax: [phone]
October 17, 2014
REPORT TO
- Sample ID: AB12975
Mike Moore C221
Wateree NPDES Well MW 9 (NPDES)
Michael Cade A221
Date&Time Sampled: October 13,2014 16:02
Date&Time Submitted: October 14,2014 07:20
Collected by: J.LEAVER Location Code: WAGO9TDS
MW 9 Login Record File: 141014082053
Analysis
_
Chlorides by IC EPA 300.0 22.8 0.5 mg/L 10/14/14 13:47 TG
Conductivity, EPA 120,1 (1982) 1518 0,05 umhos 10/15/14 13:46 PRC
Nitrate-N by IC, EPA 300.0 Less than 0.11 mg/L as N 10/14/14 13:47 TG
pH by SM4500HB 5.85 0.00 S.U. 10/15/14 13:46 PRC
Holding Time of 15 minutes has been exceeded.
Sulfates by IC EPA 300.0 973 0.5 mg/L 10/14/14 13:47 TG .
Total Dissolved Solid-SM2540C 1642 2.0 mg/L 10/15/14 12:00 CDB
If there are any questions concerning this sample, please contact the lab at(803)217-9384.
Approved By:
Page 1 of 1

Central Laboratory (P-08)
2102 North Lake Drive
A SCANA COMPANY Columbia, SC 29212
Tel: [phone]
Fax: [phone]
October 17, 2014
0,0; k‘T 7Q
Sample ID: AB12973
Mike Moore C221 Wateree NPDES Well MW 11 (NPDES)
Michael Cade A221
Date&Time Sampled: October 13, 2014 13:27
Date&Time Submitted: October 14, 2014 07:20
Collected by: J.LEAVER Location Code: WAGIITDS
MW 11 Login Record File: 141014082053
•CERTIFIED BY SCDHEG LAB ID 32006. }result Reporting Uplls Completed Analysis Ghemist'>
{ ,- •
Chlorides by IC EPA 300.0 2.3 0.5 mg/L 10/14/14 13:47 TG
Conductivity, EPA 120.1 (1982) 144.3 0.05 umhos 10/15/14 13:46 PRC
Nitrate-N by(C, EPA 300.0 0.14 • 0.11 mg/L as N 10/14/14 13:47 TG
pH by SM4500HB 6.48 0.00 S.U. 10/15/14 13:46 PRC
Holding Time of 15 minutes has been exceeded.
Sulfates by IC EPA 300.0 22.2 0.5 mg/L 10/14/14 13:47 TG
Total Dissolved Solid-SM2540C 145 2.0 m IL 10/15/14 12:00 CDB
If there are any questions concerning this sample, please contact the lab at(803 217-9384.
Approved By:
Page 1 of 1

Central Laboratory (P-08)
5CEKG0 2102 North Lake Drive
A SCANA COMPANY Columbia, SC 29212
Tel: [phone]
Fax: [phone]
October 22, 2014
' • " Sample ID: AB13110
Mike Moore C221 Wateree NPDES Well MW 1A (NPDES)
Michael Cade A221
Date&Time Sampled: October 14, 2014 12:18
Date &Time Submitted: October 14, 2014 15:40
Collected by: J.LEAVER Location Code: WAGOITOC
MW 1 Login Record File: 141014155108
a.+[< :atvl;.._ •aL. d',•:.:.°� '.!:yt" +'.:;[.. •1'a'i D n �{t
f-a. ^:i4'`vt.,w�:.i� .[y - - a.. "?^c ' �'3.,•�,[.-.4;a '-•` s"1 t J�..ls. F` r.
i � s.�� ' t w.f ice@ L1 h
;p4 FI R,iriVRl41#i94LAB Igagog ni . Ras lfi, '.��,` triRiit{NIR ).
vU n. ,s,r,�s...._ vim,:. �. ..t,<,..:.1a s.a. . .,:,r,
Total Organic Carbon, SM5310B Less than 1.0 . mg/L 10/21/14 14:12 • CDB
If there are any questions concerning this sample, please contact the lab at(803)217-9384.
Approved By: �
y —
•
•
•
Page 1 of 1

Central Laboratory (P-08)
2102 North Lake Drive
A SCANA COMPANY Columbia, SC 29212
Tel: [phone]
Fax: [phone]
October 22, 2014
REPORT TO
Sample ID: AB13107
Mike Moore C221 Wateree NPDES Well MW 2 (NPDES)
Michael Cade A221
Date&Time Sampled: October 14, 2014 09:22
Date&Time Submitted: October 14, 2014 15:40
Collected by: J.LEAVER Location Code: WAGO2TOC
MW 2 Login Record File: 141014155108
CERTIFIED BY SCDHC'(LAB ID 32006) Resuit t;" ReporEittg Unfits Completed An lysis Chemist
Lmit(MRL;) I Date 84'
Tim,Q .
Total Organic Carbon,SM5310B 2.48 1.0 mg/L 10/21/14 11:39 CDB
If there are any questions concerning this sample, please,contact the lab at(803)217-9384.
Approved By:
Page 1 of 1

Central Laboratory (P-08)
2102 North Lake Drive
A SCANA COMPANY Columbia, SC 29212
Tel: [phone]
Fax: [phone]
October 22, 2014
til:'}:'i ti^P \+..,.vim.. u y� .I� 't.; '�,.Y ,l lif.
'A'1e�'�ti ^� "n 1=30T�;3xQ�sY: F h��:.�,� 3}�:7��
'�"'`'"`r"': Sample ID: AB13108
Mike Moore C221 Wateree NPDES Well MW 3 (NPDES)
Michael Cade A221
Date&Time Sampled: October 14,2014 10:20
Date&Time Submitted: October 14,2014 15:40
Collected by: J.LEAVER Location Code: WAG03TOC
MW 3 Login Record File: 141014155108
-- F, :.nd.,.:r-?7r;X9iti - •.,�?,g';;^'a;.�;.ro
tit1�R 2e:.,.1^d�";>.L:.,>�•.:�,l'`s-? ,�nt`iY,:3:;.w ..,..,.,:#w< 1!;(j ;v�''-z::`R, a,ti.4'C:� s Q�1o!'�lno.k �c._v :f '. ; .,.. p�B�4.# 10 1� y
a MFRA SCDIFS YAM ''t t t' iniit(M8141,: 3 Ai:O .;Date 8,710,0 , ;°
_.... ..1_.. ,.,_. 4•.'4.. :. .h?._.n+... �_v r- -s'�'..o. .1l._.�7� .... ,. G;ate..,.
Total Organic Carbon, SM5310B 4.82 1.0 mg/L 10/21/14 13:11 CDB
If there are any questions concerning this sample, please contact the lab at(803)217-9384.
Approved By:
1
Page 1 of 1

Central Laboratory (P-08)
SCE G 2102 North Lake Drive
A SCANA COMPANY Columbia, SC 29212
Tel: [phone]
Fax: [phone]
October 22, 2014
REPORT TO
Sample ID: AB13109
Mike Moore C221 Wateree NPDES Well MW 4 (NPDES)
Michael Cade A221
Date&Time Sampled: October 14,2014 11:23
Date&Time Submitted: October 14,2014 15:40
Collected by:J.LEAVER Location Code: WAGO4TOC
MW 4 Login Record File: 141014155108
CERTIFIED BY$GDHECy LAB ID 32006 ( Resuit Reportm I units 1 .Completed Analysis Chem.st
� i 1;Irp[t{MRI:) � J pate&Time
Total Organic Carbon, SM5310B 5.91 1.0 mg/L 10/21/14 13:41 CDB
If there are any questions concerning this sample, please contact the lab at(803)217-9384.
a..._/3.
Approved By:
•
Page 1 of 1

Central Laboratory (P-08)
full.S. G. 2102 North Lake Drive
A SCANA COMPANY Columbia, SC 29212
Tel: [phone]
Fax: [phone]
October 22, 2014
lCt�;!s.yd�.,..-�y1'�`flt tai=:agyiAF:�'txi,"'':�a'y°:L,'��a�'k��t=z�+'�'�C,ti:{a�i'�''.
rolat N, 2 `Z,i �4� Le '1� 3 �g14a�' zti 1�L`_h'•41
;r��:�.;' ,'-'1t.;_ ..1._':r�.._. af.�k .:�x ',c�P,�4 Sample ID: AB12979
Mike Moore C221 Wateree NPDES Well MW 5 (NPDES)
Michael Cade A221
Date&Time Sampled: October 13,2014 15:00
Date&Time Submitted: October 14,2014 07:20
•
Collected by:J.LEAVER Location Code: WAGO5TOC
MW 5 Login Record File: 141014082053
";5=:1'- .}.a to -� �{. ?ti::Ye'.'t-'.''aSYa isY•u5'��.i? a .5ai}�`,`ti^`qK•�,.v 4?y ia�•�e.:.•±4 br > n' ,>. fF v.e�.il'i:
���*R IFIED r ,!` ` ` ; r Completed An�lyets,; p em �:
��r��,,..'TT i.��.$,,j� ECIY?j L� Q D f /��g1 Y F" Cl .�1 ^4'` pr�. �j� 1 �l y, n e ._ ! Ak �M,�?! •�:
iAg �5=y,.. �..` .,RA .�..' *sY,�`�ric. Y-,`�3.!`�"a,n�{.:.o44.. �-'?y0='ngTv`,*ilt(Ktiriz ..;;,t aut.;?{i4:I}it.k,,,4:3+a<te&T1me` il 1, -4,9....1,, ,,,f,_-_,
.
Total Organic Carbon,SM53103 137.2 5.0 mg/L 10/20/14 23:04 CDB
If there are any questions concerning this sample, please contact the lab at(803)217-9384.
Approved By:
liNt
Page 1 of 1

Central Laboratory (P-08)
4e...StiE110 2102 North Lake Drive •
A SCANA COMPANY Columbia, SC 29212
Tel: [phone]
Fax: [phone]
October 22, 2014
REPORT TO. `
Sample ID: AB12982
Mike Moore C221 Wateree NPDES Well MW 6 (NPDES)
Michael Cade A221
Date&Time Sampled: October 13, 2014 18:17
Date&Time Submitted: October 14, 2014 07:20
Collected by: J.LEAVER Location Code: WAGO6TOC
MW 6 Login Record File: 141014082053
S (LAB ID 32006) R P(rtmgj Completed
CERTIFIED BYCDHEC Analysis Chemist
.. - ... ._Result �, ti LI'It MRL�� Units . � Date&Time Total Organic Carbon,SM5310B 7.38 1.0 mg/L 10/21/14 00:35 CDB
If there are any questions concerning this sample, please contact the lab at(80 217-9384.
Approved By: Q.A.T„)
pp
Page 1 of 1

Central Laboratory (P-08)
SCE� G© 2102 North Lake Drive
A SCANA COMPANY Columbia, SC 29212
Tel: [phone]
Fax: [phone]
October 22, 2014
RPORT1. .,i: ETQs ,, ,-
r . Sample ID: AB12981
Mike Moore C221 Wateree NPDES Well MW 8 (NPDES)
Michael Cade A221
Date &Time Sampled: October 13, 2014 17:22
Date &Time Submitted: October 14, 2014 07:20
Collected by: J.LEAVER Location Code: WAGO8TOC
MW 8 Login Record File: 141014082053
,> ' Y ,� eportttl it C mplpte Analyst
perm �,EIR ows,gpFm (LAR lb 32096). t,, iftg:p tit to; „+ Units : d s Chemist
.... , . :Date e k t � ,.
Total Organic Carbon, SM5310B 42.7 5.0 mg/L 10/21/14 00:05 CDB
If there are any questions concerning this sample, please contact the lab at(8f� )217-9
Approved By: a .
Page 1 of 1

Central Laboratory (P-08)
4riaSCE „GO 2102 North Lake Drive
A SCANA COMPANY Columbia, SC 29212
Tel: [phone]
Fax: [phone]
October 22, 2014
- REPORT,TO'
Sample ID: AB12980
Mike Moore C221 Wateree NPDES Well MW 9 (NPDES)
• Michael Cade A221
Date&Time Sampled: October 13,2014 16:02
Date&Time Submitted: October 14, 2014 07:20
Collected by: J.LEAVER Location Code: WAGO9TOC
MW 9 Login Record File: 141014082053
CERTIFIED t3Y SODHEG, LAB ID 32006 ReSolt iteporting-.' 1lr![t� Contple�ed Analysis Chemist
( ) I. Ll .t(MRL)I,
Total Organic Carbon, SM5310B 27.3 5.0 mg/L 10/20/14 23:34 CDB
If there are any questions concerning this sample, please contact the lab at(8 217-9384. n /�
Approved By: /A)
Page 1 of 1

Central Laboratory (P-08)
2102 North Lake Drive
A SCANA COMPANY Columbia, SC 29212
Tel: [phone]
Fax: [phone]
October 22, 2014
REPORT TO
Sample ID: AB12978
Mike Moore C221 Wateree NPDES Well MW 11 (NPDES)
Michael Cade A221
Date &Time Sampled: October 13, 2014 13:27
Date &Time Submitted: October 14, 2014 07:20
Collected by: J.LEAVER Location Code: WAGIITOC
MW 11 Login Record File: 141014082053
Reporting; Completed n
Aalysis chemist;-;
CERTIFIED BY SCDHEC`(LAB ID 32006):1 Result I Units I
Limit(MRL) Date&Time.
Total Organic Carbon, SM5310B 2.87 1.0 mg/L 10/20/14 22:08 CDB
If there are any questions concerning this sample, please contact the lab at(803)217-9384.
Approved By: 0.-0-A-3\44/
Page 1 of 1

Central Laboratory(P-08)
2102 North Lake Drive
A SCANA COMPANY Columbia, SC 29212
Tel: [phone]
Fax: [phone]
October 20, 2014
REPORT TO
Sample ID: AB12970
Mike Moore C221 Wateree River Upstream
Michael Cade A221
Date&Time Sampled: October 13,2014 15:50
Date&Time Submitted: October 14, 2014 07:20
Collected by: J.LEAVER Location Code: WATUPSTR
Login Record File: 141014082053
Repotting; Comple#ed Analysts Ch6m1st;'
{
CERTIFIER BY SCpHEC, LAB IR 32006 ' fiesult l I Untts� Limit(MRL). Date&Time_;
Arsenic by ICP_OES EPA 200.7 Less than 5.0 ppb 10/20/14 07:52 MC
Nickel by ICP EPA 200.7 Less than 10.0 ppb 10/20/14 07:52 MC
If there are any questions concerning this sample, please contact the lab at(803)217-9384.
Approved By:
Page 1 of 1

Central Laboratory (P-08)
SCE�rGO 2102 North Lake Drive
A SCANA COMPANY Columbia, SC 29212
Tel: [phone]
Fax: [phone]
October 20, 2014
J REPORT T4.
Sample ID: AB12971
Mike Moore C221 Wateree River at Ponds
Michael Cade A221
Date&Time Sampled: October 13,2014 13:40
Date&Time Submitted: October 14,2014 07:20
Collected by: J.LEAVER Location Code: WATPONDS
Login Record File: 141014082053
:, Reporting: Completed An lysis he►�,is1t
CERTI�IEQ B SGDHEC LAB ID 32t)06 �tesu[t `, Un)ts
Y .,; .,( , ,. .� t:yriit{MRL) . . , • ,.. _. _ .;:..:
Arsenic by ICP_OES EPA 200.7 Less than 5.0 ppb 10/20/14 08:08 MC
Nickel by ICP EPA200.7 Less than 10.0 ppb 10/20/14 08:08 MC
If there are any questions concerning this sample, please contact the lab at(803)217-9384.
iAk
Approved By: # 1
Page 1 of 1

Central Laboratory(P-08)
tsamSlimma.
2102 North Lake Drive
A SCANA COMPANY Columbia, SC 29212
Tel: [phone]
Fax: [phone]
October 20, 2014
REPORT TO
Sample ID: AB12972
Mike Moore C221 Wateree River Downstream
Michael Cade A221
Date&Time Sampled: October 13,2014 14:20
Date&Time Submitted: October 14,2014 07:20
Collected by: J.LEAVER Location Code: WATDWNST
Login Record File: 141014082053
Reporting Completed Anat�rsi$ Chemist
CERTIFIED BY SGDHEC(LAS ID 320Q6) Re$uit Limit(MRL) Units Date&Time
Arsenic by ICP_OES EPA 200.7 Less than 5.0 ppb 10/20/14 08:08 MC
Nickel by ICP EPA 200.7 Less than 10.0 ppb 10/20/14 08:08 MC
If there are any questions concerning this sample, please contact the lab at(803)217-9384
Approved By:
Page 1 of 1

APPENDIX II
GROUNDWATER MONITORING REPORT FORMS

DHEC
.. X _ _ Groundwater Monitoring Report
PROMO r F.PROT FCT PROSPER
Date Sampled Date Analyzed
SC0002038
Permit Number 10 13-14 14 10 14-21 14
Facility: Wateree Station Month Day Year Month Day Year
Address:142 Wateree Station Road Lab Name: SCE&G
City:Eastover State:South Carolina
County:Richland Zipcode:29044 SC Lab Certification No.:
Site I.D.#: 32006
PARAMETERS WELL NUMBERS
Name Units MW-01A MW-02 MW-03 MW-04 MW-05 MW-06 MW-08
Depth to Water ft 13.6 11.15 14.10 21.63 19.86 32.25 28.20
Water Elevation ft 114.25 97.88 98.10 89.99 88.70 81.53 81.29
Water Temperature deg.C 24.15 20.21 23.16 22.44 25.88 21.25 21.92
Specific Conductivity umhos 53 523 537 545 942 330 627
pH S.U. 5.47 6.03 5.81 5.76 6.01 5.63 5.99
Turbidity NTU 8 . 77 9 . 88 2 . 86 23 . 7 10.4 6 . 92 27 .4
Arsenic ppb <5 . 0 <5 . 0 122 <5 . 0 <5 . 0 <5 . 0 <5. 0
Cadmium ppb <1. 0 <1. 0 <1 . 0 3 .7 <1 .0 <1. 0 <1 . 0
Chromium ppb <5 . 0 <5 . 0 <5 .0 <5 . 0 <5 . 0 <5. 0 <5 . 0
Copper PPb <10 . 0 <10 . 0 <10 . 0 <10 . 0 <10 . 0 <10 . 0 <10 . 0
Iron Ppb 15 .4 18, 300 13 , 000 83,200155, 00020,20099, 100
Lead ppb <5 . 0 <5 .0 <5 .0 <5 . 0 6 .2 <5 . 0 <5 .0
Mercury ppb <0 .2 <0.2 <0 .2 <0 .2 <0 .2 <0. 2 <0.2
Nickel ppb <10 . 0 <10 . 0 <10 . 0 <10 . 0 <10 . 0 31. 1 17.4
Selenium ppb <10 . 0 <10 . 0 <10. 0 <10. 0 <10 . 0 <10. 0 <10 .0
Zinc ppb 20 .4 61 .9 <10 .0 61 . 9 59 . 6 22 .5 50 .5
Chlorides mg/L 5 . 8 89 . 1 110 45 . 8 43 .3 37 .6 19.6
Lab Conductivity umhos 70 . 6 490 . 8 695. 1 486 . 5 632 260 .2 502
Lab pH S.U. 5 .27 6 .39 6 .55 5 . 92 6. 01 5 .92 6 . 06
(Type or Print) Telephone: - 331-44L 3
Authorized Release By: Date: alai/`1'
DHEC 2110(0511999)

DHEC
-:_ _. -
_ r _�_ _ ------Ip
Groundwater Monitoring Report
PRO IOTF.PROT FCT PROS I'FR
Date Sampled Date Analyzed
SC0002038
Permit Number 10 14 14 10 16-21 14
Facility: Wateree Station Month Day Year Month Day Year
Address:142 Wateree Station Road Lab Name: SCE&G
City:Eastover State:South Carolina .
County:Richland Zipcode:29044 SC Lab Certification No.: 32006
Site I.D.#:
PARAMETERS WELL NUMBERS
Name Units MW-01A MW-02 MW-03 MW-04 MW-05 MW-06 MW-08
Depth to Water ft 13.6 11.15 14.10 21.63 19.86 32.25 28.20
Water Elevation ft 114.25 97.88 98.10 89.99 88.70 81.53 81.29
Water Temperature deg.C 24.15 20.21 23.16 22.44 25.88 21.25 21.92
Specific Conductivity umhos 53 523 537 545 942 330 627
pH S.U. 5.47 6.03 5.81 5.76 6.01 5.63 5.99
Sulfates mg/L <0 .5 45 .2 59 . 1 0 . 96 <0. 5 26 .2 77 .4
Total Dissolved Solids mg/L 39 278 393 248 706 188 448
Total Organic Carbon mg/L <1. 0 2 .48 4 .82 5. 91 137 .2 7.38 42 .7
Nitrate-N mg/L 1 .88 <0 . 11 <0 . 11 <0.11 <0 . 11 <0. 11 0 .19
(Type orPrint) ' Telephone: Z�3-33(- `1`44-3Y
Authorized Release By: /``/!�-�- Date: /2-/I ft 2- t y
DHEC 2110(05/1999)

DHEC
_r/" 7- ° ' Groundwater Monitoring Report
PRO\101-F PRO7'F(:T PROM R
Date Sampled Date Analyzed
SC0002038
Permit Number 10 13 14 10 14-17 14
Facility: Wateree Station Month Day Year Month Day Year
Address:142 Wateree Station Road Lab Name: SCE&G
City:Eastover State:South Carolina
County:Richland Zipcode:29044 SC Lab Certification No.: 32006
Site I.D.#:
PARAMETERS WELL NUMBERS
Name Units MW-09 MW-11
Depth to Water ft 21.20 17.12
Water Elevation ft 81.86 83.27
Water Temperature deg.C 21.76 22.83
Specific Conductivity umhos 1,762 179
pH S.U. 5.66 5.79
Turbidity NTU 9 . 81 12 . 0
Arsenic PPb <5 . 0 101
Cadmium ppb <1 . 0 <1 . 0
Chromium ppb <5 . 0 <5 . 0
Copper PPb <10 . 0 <10 . 0
Iron Ppb 291, 000 1, 070
Lead ppb 11.5 <5 . 0
Mercury ppb <0 .2 <0 .2
Nickel ppb <10 . 0 <10 . 0
Selenium ppb <10 . 0 13 . 7
Zinc ppb 91 .4 51 .8
Chlorides mg/L 22 . 8 2 .3
Lab Conductivity umhos 1, 518 144 .3
Lab pH S.U. 5 . 85 6 .48
(Type or Print) Telephone: -33 I---LP-16-3
Authorized Release !�I 2 By: Date: 2 !
Y � `
DHEC 2110(05/1999)

DHEC
74 7_7 _ Groundwater Monitoring Report
PROMOTE PROTECT PROSPER
Date Sampled Date Analyzed
SC0002038
Permit Number 10 13 14 10 14-20 14
Facility: Wateree Station Month Day Year Month Day Year
Address:142 Wateree Station Road Lab Name:
City:Eastover State:South Carolina SCE&G
County:Richland Zipcode:29044 SC Lab Certification No.: 32006
Site I.D.#:
PARAMETERS WELL NUMBERS
•
Name Units MW-09 MW-11
Depth to Water ft 21.20 17.12
Water Elevation ft 81.86 83.27
Water Temperature deg.C 21.76 22.83
Specific Conductivity umhos 1,762 179
S.U. 5.66 5.79
PH
Sulfates mg/L 973 22 .2
Total Dissolved Solids mg/L 1, 642 145
Total Organic Carbon mg/L 27 .3 2 . 87
Nitrate-N mg/L <0 . 11 0.14
(Type or Print) i Telephone: YO-3 "33 t Lf`{G 3
Authorized Release By: Date: 1 21/211 L-/
DHEC 2110(05/1999)

Attachment D
SCE&G IRP Statements
(February 2014)

1
Reductions" is the sum of the residential and commercial cumulative reductions and represents
the "SCE&G DSM Programs" column shown in a subsequent forecast summary table.
Derivation of Annual EE Savings
Baseline Cumulative Incremental Baseline Cumulative Incremental Cumulative
Residential Reductions ReductionsInc % Commercial Reductions Reductions Inc % Reductions
(GWH) (GWH) (GWH) (GWH) (GWH) (GWH) (GWH)
2014 7,883 - - - 7,247 - - - -
2015 7,919 - - - 7,257 - - - -
2016 8,053 -25 -25 -0.31 7,437 -10 -10 -0.13 -35
2017 8,192 -50 -25 -0.31 7,615 -20 -10 -0.13 -70
2018 8,318 -76 -26 -0.31 7,777 -30 -10 -0.13 -106
2019 8,511 -103 -26 -0.31 8,042 -40 -10 -0.13 -143
2020 8,697 -129 -27 -0.31 8,300 -51 -11 -0.13 -180
2021 8,877 -157 -28 -0.31 8,544 -62 -11 -0.13 -219
2022 9,054 -185 -28 -0.31 8,783 -73 -11 -0.13 -259
2023 9,242 -214 -29 -0.31 9,041 -85 -12 -0.13 -299
2024 9,420 -243 -29 -0.31 9,288 -97 -12 -0.13 -340
2025 9,602 -273 -30 -0.31 9,540 -110 -12 -0.13 -382
2026 9,777 -303 -30 -0.31 9,782 -122 -13 -0.13 -425
2027 9,947 -334 -31 -0.31 10,015 -135 -13 -0.13 -469 ,
2028 10,120 -365 -31 -0.31 10,257 -149 -13 -0.13 -514
3. Energy Efficiency Adjustments
Several adjustments were made to the baseline projections to incorporate significant
factors not reflected in historical experience. These were increased air-conditioning and heat
pump efficiency standards and improved lighting efficiencies, both mandated by federal law, and
the addition of SCE&G's energy efficiency programs. The following table shows the baseline
projection,the energy efficiency adjustments and the resulting forecast of territorial energy sales.
5
1

• Energy Efficiency
SCE&G Total
Baseline DSM Federal EE Territorial
Sales Programs Mandates Impact Sales
(GWH) (GWH) (GWH) (GWH) (GWH)
2014 22,773 0 -125 -125 22,648
2015 22,919 0 -187 -187 22,732
2016 23,446 -35 -467 -502 22,944
2017 23,999 -70 -506 -576 23,423
2018 24,415 -106 -544 -650 23,765
2019 25,011 -143 -589 -732 24,279
2020 25,565 -180 -702 -882 24,683
2021 26,103 -219 -819 -1,038 25,065
2022 26,633 -259 -841 -1,100 25,533
2023 27,195 -299 -864 -1,163 26,032
2024 27,740 -340 -886 -1,226 26,514
2025 28,297 -382 -908 -1,290 27,007
2026 28,836 -425 -930 -1,355 27,481
2027 29,355 -469 -951 -1,420 27,935
2028 29,883 -514 -972 -1,486 28,397
Baseline sales are projected to grow at the rate of 2.0%per year. The impact of energy
efficiency,both from SCE&G's DSM programs and from federal mandates,causes the ultimate
territorial sales growth to fall to 1.6%per year as reported earlier.
Since the baseline forecast utilizes historical relationships between energy use and driver
variables such as weather, economics, and customer behavior, it embodies changes which have
occurred between them over time. For example,construction techniques which result in better
insulated houses have had a dampening effect on energy use. Because this process happens with
the addition of new houses and/or extensive home renovations, it occurs gradually. Over time
this factor and others are captured in the forecast methodology. However, when significant
events occur that impact energy use but are not captured in the historical relationships,they must
be accounted for outside the traditional model structure.
The first adjustment relates to federal mandates for air-conditioning units and heat
pumps. In 2006,the minimum Seasonal Energy Efficiency Ratio("SEER") for newly
manufactured appliances was raised from 10 to 13, which means that cooling loads for a house
that replaced a 10 SEER unit with a 13 SEER unit would decrease by 30%assuming no change
6

in other factors. The last mandated change to efficiencies like this took place in 1992, when the
minimum SEER was raised from 8 to 10, a 25% increase in energy efficiency. Since then air-
conditioner and heat pump manufacturers introduced much higher-efficiency units, and models
are now available with SEERs over 20. However, overall market production of heat pumps and
air-conditioners is concentrated at the lower end of the SEER mandate. The 2006 minimum
SEER rating represented a significant change in energy use which would not be fully captured by
statistical forecasting techniques based on historical relationships. For this reason an adjustment
to the baseline was warranted.
A second reduction was made to the baseline energy projections beginning in 2013 for
savings related to lighting. Mandated federal efficiencies as a result of the Energy Independence
and Security Act of 2007 took effect in 2013 and will be phased in through 2015. Standard
incandescent light bulbs are inexpensive and provide good illumination, but they are extremely
inefficient. Compact fluorescent light bulbs("CFLs") have become increasingly popular over
the past several years as substitutes. They last much longer and generally use about one-fourth
the energy that incandescent light bulbs use. However, CFLs are more expensive and still have
some unpopular lighting characteristics, so their large-scale use as a result of market forces was
not guaranteed. The new mandates will not force a complete switchover to CFLs,but they will
impose efficiency standards that can only be met by them or newly developed high-efficiency
incandescent light bulbs. Again,this shift in lighting represents a change in energy use which
was not fully reflected in the historical data.
The final adjustment to the baseline forecast was to account for SCE&G's new set of
energy efficiency programs. These energy efficiency programs along with the others in
SCE&G's existing DSM portfolio are discussed later in the IRP. In developing the forecast it
was assumed that the impacts of these programs were captured in the baseline forecast for the
next two years but thereafter had to be reflected in the forecast on an incremental basis.
4. Load Impact of Energy Efficiency and Demand Response Programs
The Company's energy efficiency programs("EE")and its demand response programs
("DR")will reduce the need for additional generating capacity on the system. The EE programs
implemented by our customers should lower not only their overall energy needs but also their
power needs during peak periods. The DR programs serve more directly as a substitute for
peaking capacity. The Company has two DR programs: an interruptible program for large
7

customers and a standby generator program. These programs represent over 200 megawatts
("MW") on our system. The following table shows the impacts of EE from the Company's DSM
programs and from federal mandates as well as the impact from the Company's DR programs on
the firm peak demand projections.
Territorial Summer Peak Demands(MWs)
Energy Efficiency
System Firm
Baseline SCE&G Federal Total EE Peak Demand Peak
Year Trend Programs Mandates Impact Demand Response Demand
2014 5,046 0 -3 -3 5,043 -257 4,786
2015 5,112 0 -4 -4 5,108 -260 4,848
2016 5,270 -11 -26 -37 5,233 -267 4,966
2017 5,406 -21 -38 -59 5,347 -275 5,072
2018 5,525 -33 -48 -81 5,444 -279 5,165
2019 5,631 -44 -59 -103 5,528 -283 5,245
1 2020 5,735 -55 -74 -129 5,606 -286 5,320
2021 5,829 -67 -89 -156 5,673 -289 5,384
2022 5,920 -79 -92 -171 5,749 -292 5,457
2023 6,021 -91 -96 -187 5,834 -296 5,538
2024 6,125 -104 -100 -204 5,921 -299 5,622
2025 6,228 -116 -103 -219 6,009 -303 5,706
2026 6,331 -129 -107 -236 6,095 -306 5,789
2027 6,429 -143 -110 -253 6,176 -310 5,866
2028 6,525 -157 -113 -270 6,255 -313 5,942
8

II. SCE&G's Program for Meeting Its Demand and Energy Forecasts in an
Economic and Reliable Manner
A. Demand Side Management
Demand Side Management(DSM)can be broadly defined as the set of actions that can be taken
to influence the level and timing of the consumption of energy. There are two common subsets
of Demand Side Management: Energy Efficiency and Load Management(also known as
Demand Response). Energy Efficiency typically includes actions designed to increase efficiency
by maintaining the same level of production or comfort, but using less energy input in an
economically efficient way. Load Management typically includes actions specifically designed
to encourage customers to reduce usage during peak times or shift that usage to other times.
Energy Efficiency
SCE&G's Energy Efficiency programs include Customer Information Programs, Web-Based
Information and Services Programs, Energy Conservation and the Demand Side Management
Programs. A description of each follows:
1. Customer Information Programs: SCE&G's customer information programs fall under
two headings: the Annual Energy Efficiency Campaigns and Web-based Information
Initiatives. The following is an overview of each.
Annual Energy Efficiency Campaigns
a. Customer Insights and Analysis: In 2013, SCE&G continued to proactively
educate its customers and create awareness on issues related to energy efficiency
and conservation. To help maximize the effectiveness of our campaigns, ongoing
customer feedback is used to ensure marketing and communications efforts are
consistent with what customers value most. Key insights gained through
SCE&G's Brand Health Study and Voice of the Customer Panels are integrated to
ensure we are communicating in a consistent manner that customers will
understand.
As a result, SCE&G continues to highlight programs/services that reflect three
main categories identified by our customers as offering the best opportunity to
9

save energy and money. These areas include rebates and incentives, in-home
services and education.
b. Media/Channel Preferences: Placement of all marketing and advertising is
carefully reviewed,taking into consideration the customers' preferred methods of
receiving information about SCE&G's energy efficiency programs and services.
Priority channels include television(local news and select cable stations);online
banner advertising, radio, electronic/print newsletters,direct mail, bill inserts and
newspapers(major daily and weekly minority publications). SCE&G's statewide
business office locations also serve as a distribution point for sharing information
with customers. In addition, SCE&G has also incorporated social media, e.g.
Twitter and Facebook, into its communications strategy. Key South Carolina
markets covered,with all marketing communications, include Columbia,
Charleston, Aiken and Beaufort.
c. Public Affairs/News Media/Speakers Bureau: Furthermore, SCE&G
understands the value of public affairs as an integral part of a well-rounded
energy efficiency communication strategy and actively engages news media
(broadcast and print)for coverage of key programs and services that will benefit
our customers now and in the future. Public Affairs and Marketing staff also
provide support with securing company experts to address a variety of
organizations through a formal Speakers' Bureau, extending our outreach to
church groups, senior citizen and low-income housing communities,civic •
organizations,builder groups and homeowner associations.
d. Special Events: Another key component to SCE&G's annual marketing
initiatives include participation in a variety of events that offer the opportunity to
further extend customer education and outreach of energy information. SCE&G's
2013 schedule included a solid mix of special events to include the Home
Builders Association ("HBA") Home Improvement Show and Tour of Homes in
Columbia and Black Expos in Columbia and Charleston.
e. EnergyWise Communications: Brand positioning of SCE&G's energy
efficiency programs and services with all marketing and advertising initiatives
falls under the EnergyWise umbrella—an SCE&G registered trademark in South
10 •

Carolina and encompasses general awareness education as well as program
specific offerings.
General Awareness Education: Last year's advertising included
messaging on a wide range of topics such as year-round and seasonal
energy efficiency tips that are practical for customers to manage on their
own or that have a no-cost, low-cost factor to them. Examples include
thermostat settings, checking air filters monthly,water heater settings and
unplugging appliances that are sometimes perceived to be"energy
vampires"(lights, TV's, computers, cell phone chargers, etc.).
Program Specific Offerings: In 2013, SCE&G continued to heavily
promote its portfolio of residential electric rebate/incentive programs
under its Demand Side Management(DSM)department—many of which
were featured in our general awareness advertising schedule. Specific
programs included ENERGY STAR Lighting, our free Home Energy
Check-up, Home Performance with ENERGY STAR and Residential
Heating& Cooling and Water Heating Equipment.
2. Web-Based Information and Services Programs: SCE&G's online offerings can be
broken into four components: Customer Awareness Information,the Energy Analyzer,
free online Energy Audit and EnergyWise e-newsletter. Altogether,there have been
more than 5.1 million visits to SCE&G's website in 2013. Customers must be registered
to use the interactive tools Energy Analyzer and Energy Audit. There are over 350,000
customers registered for this access. Descriptions of the four categories listed above
follows:
a. Customer Awareness Information: The SCE&G website,www.sceg.com,
supports all communication efforts to promote energy savings information—
both general awareness tips and program-specific overviews,tools and
resources—all through a section called"Be EnergyWise and Save". Energy
savings information includes detailed information on each of the Demand Side
Management programs for residential and commercial/industrial customers, as
well as how-to videos on insulation,thermostats and door and windows.
b. Energy Analyzer: The Energy Analyzer, in use since 2004, is a 24-month
bill analysis tool. It uses complex analytics to identify a customer's seasonal
11

usages and target the best ways to reduce demand. This Web-based tool
allows customers to access their current and historical consumption data and
compare their energy usage month-to-month and year-to-year--noting trends,
temperature impact and spikes in their consumption. There were a little over
106,000 visits to the Energy Analyzer tool in 2013.
c. Online Energy Audit: The Online Energy Audit tool leads customers
through the process of creating a complete inventory of their home's
insulation and appliance efficiency. The tool allows customers to see the
energy and financial savings of upgrades before making an investment. Over
7,000 customers used the Energy Audit tool in 2013.
d. SCE&G EnergyWise E-Newsletter: SCE&G's web-based information and
services included ongoing management of its EnergyWise e-newsletter to
support customer demand for additional information on ways to help them
save energy. A total of 2,464 customers are registered for the e-newsletters
distributed in 2013. •
3. Energy Conservation
Energy conservation is a term that has been used interchangeably with energy efficiency.
However,energy conservation has the connotation of using less energy in order to save
rather than using less energy to perform the same or better function more efficiently. The
following is an overview of each SCE&G energy conservation offering:
a. Energy Saver/Conservation Rate: The Rate 6 (Energy
Saver/Conservation)rewards homeowners and homebuilders who upgrade
their existing homes or build their new homes to a high level of energy
efficiency with a reduced electric rate. This reduced rate, combined with a
significant reduction in energy usage,provides for considerable savings for
our customers. Participation in the program is very easy as the requirements
are prescriptive which is beneficial to all of our customers and trade allies.
Homes built to this standard have improved comfort levels and increased re-
sale value over homes built to the minimum building code standard, which is
also a significant benefit to participants. Information on this program is
available on our website and by brochure.
12

b. Seasonal Rates: Many of our rates are designed with components that vary
by season. Energy provided in the peak usage season is charged a premium to
encourage conservation and efficient use.
4. Demand Side Management Programs
In 2013, SCE&G completed a comprehensive evaluation of the existing DSM programs
with the specific intention of updating programs and introducing new programs to the
DSM portfolio. In May 2013,the Company presented the new portfolio to the
Commission and received approval in November 2013. The Commission approved a
suite of eleven(11) DSM programs,which includes nine programs targeting SCE&G's
residential customer classes and two programs targeting SCE&G's commercial and
industrial customer classes. A description of each program follows:
a. Residential Home Energy Reports provides customers with free monthly/bi-
monthly reports comparing their energy usage to a peer group and providing
information to help identify, analyze and act upon potential energy efficiency
measures and behaviors.
b. Residential Energy Information Display provides customers with an in-home
display that shows information from the customer's meter regarding current
energy usage and cost, and the approximate use and cost to date for the month.
The displays were distributed to targeted customers,upon their request,at a
discounted price.
c. Residential Home Energy Check-up program provides customers with a visual
energy assessment performed by SCE&G staff at the customer's home. At the
completion of the visit, customers are offered an energy efficiency kit containing
simple measures, such as compact fluorescent light bulbs ("CFL"), water heater
wraps and/or pipe insulation. The Home Energy Check-up is provided free of
charge to all residential customers who elect to participate.
d. Residential Home Performance with ENERGY STAR®program promotes a
comprehensive energy efficiency audit of the home by trained contractors.
SCE&G provides incentives to customers for implementing specific measures
based on the audit findings.
13

e. Residential ENERGY STAR®Lighting program incentivizes residential
customers to purchase and install high-efficiency ENERGY STAR®qualified
lighting products by providing discounts to the manufacturers and retailers.
f. Residential Heating & Cooling and Water Heating Equipment program
provides incentives to customers for purchasing and installing high efficiency
HVAC equipment and non-electric resistance water heaters in new and existing
homes.
g. Residential Heating& Cooling Efficiency Improvements program provides
residential customers with incentives to improve the efficiency of existing AC and
heat pump systems through HVAC tune-ups (system optimizer), complete duct
replacements,duct insulation and duct sealing. The system optimizer was
discontinued in May 2013.
h. Residential ENERGY STAR®New Homes program provides incentives to
customers and builders who are willing to commit to ENERGY STAR®standards
in new home construction.
i. Neighborhood Energy Efficiency Program (NEEP), approved by the
Commission in April 2013,provides qualifying customers energy education,an
on-site energy survey of the dwelling, and direct installation of low-cost energy
saving measures at no additional cost to the customer. The program is delivered
in a neighborhood door-to-door sweep approach and offers customers who are
eligible and wish to participate a variety of direct installation energy efficiency
measures.
j. Commercial and Industrial Prescriptive program provides incentives to non-
residential customers to invest in high-efficiency lighting and fixtures, high
efficiency motors and other equipment. To ensure simplicity,the program
includes a master list of measures and incentive levels that are easily accessible to
commercial and industrial customers on the website.
k. Commercial and Industrial Custom program provides custom incentives to
commercial and industrial customers based on the calculated efficiency benefits
of their particular energy efficiency plans or construction proposals. This
program applies to technologies and applications that are more complex and
14

customer-specific. All aspects of this program fit within the parameters of both
retrofit and new construction projects.
5. Load Management Programs
The primary goal of SCE&G's load management programs is to reduce the need for
additional generating capacity. There are four load management programs: Standby
Generator Program, Interruptible Load Program, Real Time Pricing Rate and the Time of
Use Rates. A description of each follows:
a. Standby Generator Program: The Standby Generator Program for wholesale
customers provides about 25 megawatts of peaking capacity that can be called
upon when reserve capacity is low on the system. This capacity is owned by our
wholesale customers and through a contractual arrangement is made available to
SCE&G dispatchers. SCE&G has a retail version of its standby generator
program in which SCE&G can call on 20 or more customers to run their
emergency generators. This retail program provides about 17 MWs of additional
capacity as needed.
b. Interruptible Load Program: SCE&G has over 150 megawatts of interruptible
customer load under contract. Participating customers receive a discount on their
demand charges for shedding load when SCE&G is short of capacity.
c. Real Time Pricing("RTP") Rate: A number of customers receive power under
our real time pricing rate. During peak usage periods throughout the year when
capacity is low in the market,the RTP program sends a high price signal to
participating customers which encourages conservation and load shifting. Of
course during low usage periods, prices are lower.
d. Time of Use Rates: Our time of use rates contain higher charges during the peak
usage periods of the day and lower charges during off-peak periods. This
encourages customers to conserve energy during peak periods and to shift energy
consumption to off-peak periods. All SCE&G customers have the option of
purchasing electricity under a time of use rate.
SCE&G's resource plan shows the need for additional capacity in the future to continue
providing reliable electric service to its customers. As SCE&G evaluates how to satisfy
this need,the Company will consider,among other things, demand response
technologies.
15

B. Supply Side Management
Clean Energy at SCE&G
Clean energy includes energy efficiency and clean energy supply options like nuclear
power, hydro power, combined heat and power and renewable energy.
1. Existing Sources of Clean Energy
SCE&G is committed to generating more of its power from clean energy sources. This
commitment is reflected: in the amount of current and projected generation coming from clean
sources, in the certified renewable energy credits that the Company generates each year, in the
Company's net metering program, and in the Company's support for Palmetto Clean Energy,
Inc. Below is a discussion of each of these topics.
a. Current Generation: SCE&G currently generates clean energy from hydro, nuclear, solar
and biomass. The following chart shows the current and expected amounts of clean energy in
GWH and as a percentage of retail sales.
SCE&G Clean Energy Plan
30,000 - 80%
25,000
• ........� ......
....... - 60%
20,000 - 50%
15,000 �1/ ! 40%
10,000 —" "� / - 30%
- 20%
5,000 - 10%
I 0%
.�0,'S .10y '� y0,� .y61 -y61'S '61'
— -Clean Energy Retail Sales ——— %Clean Energy
011614
As seen in the chart above. SCE&G currently generates a little over 30% of its retail sales from
clean energy sources but by 2019 it expects to generate about 74%from clean energy.
According to the EIA, the U.S. as a nation currently generates about 33% of its retail sales as
clean energy and it expects this percentage to increase slightly over the next ten years or so. The
following chart graphs EIA's forecast for US clean energy.
16

US Clean Energy Forecast
EIA AE02014
5,000 — - - - - 36.0%
�� 35.5%
4,000 /.. `................ - 35.0%
- 34.5%
3,000
C7 - 34.0%
c
.2 2,000 - 33.5%
- 33.0%
1,000 - - 32.5%
- 32.0%
31.5%
ON'4 ,0. ,0,E 01 . ,6-v-5
010614 -Clean Energy Net Generation to the Grid ——— %Clean Energy
SCE&G compares very favorably to the nation in its clean energy plans since by 2019 it should
be meeting about twice as much of its retail sales with clean energy on a relative basis compared
to the nation.
b. Renewable Energy Credits: The SCE&G-owned electric generator, located at the KapStone
Charleston Kraft LLC facility, generates electricity using a mixture of coal and biomass.
KapStone Charleston Kraft, LLC, produces black liquor through its Kraft pulping process and
produces and purchases biomass fuels. These fuels which are used to produce renewable energy
and the electricity generated qualify for Renewable Energy
Certificates (`'REC") as approved by Green-e Energy, a Year MWh %of Retail Sales
2007 371,573 1.7%
leading national independent certification and verification 2008 369,780 1.7%
program for renewable energy administered by the Center 2009 351,614 1.7%
for Resource Solutions, a nonprofit company based in San 2010 346,190 1.5%
Francisco, California. The nearby table shows the MWHs 2011 336,604 1.5%
2012 414,047 1.9%
of renewable energy generated by the Kapstone generator, 2013 385,202 1.8%
formerly known as the Cogen South generator:
c. Boeing Solar Generator: In 2011, SCE&G installed approximately 10 acres of thin-film
laminate panels (18,095 individual panels) on the roof of Boeing's North Charleston assembly
plant. The PV system, having an alternating current peak output of 2.35 MW, began generating
in October 2011. All RECs and energy generated by the roof top solar system are provided to
17

Boeing for onsite use. At the time of completion this was the largest roof-top solar generator in
the Southeast. Over the last two years the Boeing solar plant has generated the following
amounts of energy:
Year MWh
2012 3,513
2013 3,410
d. Net Metering Rates and the PR-1 Rate: Protecting the environment includes encouraging
and helping our customers to take steps to do the same. Net metering provides a way for
residential and commercial customers interested in generating their own renewable electricity to
partially power their homes or businesses and sell the excess energy back to SCE&G. For
residential customers,the generator output capacity cannot exceed the annual maximum
household demand or 20 KW,whichever is less. For small commercial customers,the generator
output capacity cannot exceed the annual maximum demand of the business or 100 KW,
whichever is less. Under its PR-1 rate for qualifying facilities, the Company will pay the
qualifying customer for any power generated and transmitted to the SCE&G system. The PR-1
rate is developed using SCE&G's avoided costs.
e. Palmetto Clean Energy,Inc.: Palmetto Clean Energy, Inc. ("PaCE") is a non-profit,tax
exempt organization formed by SCE&G, Duke Energy, Progress Energy,the South Carolina
Office of Regulatory Staff("ORS")and the S.C. Energy Office for the purpose of promoting the
development of renewable power in South Carolina. Customers make a tax deductible
contribution to PaCE and PaCE uses the funds collected to pay renewable generators a financial
incentive for their power.
2. Future Clean Energy
SCE&G is participating in activities seeking to advance renewable technologies in the
future. Specifically the Company is involved with off-shore wind activities in the state,co-firing
with biomass fuels, building solar generation, studying smart grid opportunities and distribution
automation. These activities are set forth in more detail below.
a.New Renewable Projects: SCE&G's customers and other South Carolina stakeholders have
expressed a desire for solar energy in the State, and SCE&G is looking for ways to integrate
18

additional solar into the system in the most economical way possible while beginning to grow a
new energy economy in South Carolina based on a diverse portfolio of generation. SCE&G
currently has approximately 4 megawatts of solar generation on the system,and plans to build
new solar farms that will add up to 20 megawatts of renewable energy to our system. We have
created an experienced team focused on research, design, and implementation of renewable
energy resources (solar, wind,and biomass). In 2014-2016, we plan to install several solar farms
on the system. These solar farms will be built in various locations throughout the system and
will include opportunities for research,education,and expansion of the energy economy in S.C.
b. Off-Shore Wind Activities: SCANA/SCE&G is a founding member of the Southeastern
Coastal Wind Coalition and participates in the Utility Advisory Group of that organization. The
mission of Southeastern Coastal Wind Coalition is to advance the coastal and offshore wind
industry in ways that result in net economic benefits to industry, utilities, ratepayers,and citizens
of the Southeast. The focus is three fold:
1. Research and Analysis—objective,transparent, data-driven, and focused on
economics.
2. Policy/Market Making—exploring multistate collaborative efforts and working
with utilities,not against them.
3. Education and Outreach—website,communications,and targeted outreach.
SCE&G participated in the Regulatory Task Force for Coastal Clean Energy. This task
force was established with a 2008 grant from the U.S.Department of Energy. The goal is to
identify and overcome existing barriers for coastal clean energy development for wind,wave and
tidal energy projects in South Carolina. Efforts included an offshore wind transmission study; a
wind,wave and ocean current study; and creation of a Regulatory Task Force. The mission of
the Regulatory Task Force was to foster a regulatory environment conducive to wind,wave and
tidal energy development in state waters. The Regulatory Task Force was comprised of state and
federal regulatory and resource protection agencies, universities, private industry and utility
companies.
SCANA/SCE&G participated in discussions to locate a 40 MW demonstration wind farm
off the coast of Georgetown. This effort,known as Palmetto Wind, includes Clemson
University's Restoration Institute, Coastal Carolina University, Santee Cooper,the S.C. Energy
19

Office and various utilities. Palmetto Wind has been put on hold due to the high cost of the
project.
SCE&G invested $3.5 million in the Clemson University Restoration Institute's wind
turbine drive train testing facility at the Clemson campus in North Charleston. This new facility
is dedicated to groundbreaking research, education,and innovation with the world's most
advanced wind turbine drive train testing facility capable of full-scale highly accelerated
mechanical and electrical testing of advanced drive train systems for wind turbines.
c. Co-firing with Biomass: SCE&G continues to investigate and evaluate the co-firing of
biomass and other engineered waste products in our existing coal burning facilities. The goal of
the project is to determine the operational practicality as well as the economic and fuel supply
implications of co-firing in existing coal units. Co-firing of biomass fuel in our existing units
represents an opportunity to include additional renewable fuels in our production mix without
having to build new facilities or spend significant capital on existing facilities. Results are
evaluated by the Fossil Hydro department to determine the feasibility for a future course of
action.
d. Smart Grid Activities: SCE&G currently has approximately 9,300 AMI meters that are.
installed predominately on our medium to large commercial customers as well as our smaller
industrial customers. Other applications where this technology is deployed include all time-of-
use accounts and all accounts with customer generation (net metering). These meters utilize
public wireless networks as the communication backbone and have full two-way communication
capability. Register readings and load profile data are remotely collected daily from all AMI
meters. In addition to traditional metering functions,the technology also provides real-time
monitoring capability including power outage/restoration, meter/site diagnostics, and power
quality monitoring. Load profile data is provided to customers daily via web applications
enabling these customers to have quick access to energy usage allowing better management of
their energy consumption. Moving forward,this technology will also enable more sophisticated
DSM offerings that may be attractive to a variety of customer classes.
e.Distribution Automation: SCE&G is continuing to expand the penetration of automated
Supervisory Control and Data Acquisition ("SCADA") switching and other intelligent devices
20

throughout the system. We have approximately 850 SCADA switches and reclosers, most of
which can detect system outages and operate automatically to isolate sections of line with
problems thereby minimizing the number of affected customers. Some of these isolating
switches can communicate with each other to determine the optimal configuration to restore
service to as many customers as possible without operator intervention. We are continuing to
evaluate systems that will help these automated devices communicate with each other and safely
reconfigure the system in a fully automated fashion.
f.Environmental Mitigation Activities: In order to reduce NOx emissions and to meet
compliance requirements, SCE&G installed Selective Catalytic Reduction ("SCR") equipment at
Cope Station in the fall of 2008. The SCR began full time operation on January 1,2009, and has
run well since that time. It is capable of reducing NOx emissions at Cope Station by
approximately 90%. SCE&G is also utilizing the existing SCRs at Williams and Wateree
Stations along with previously installed low NOx burners at the other coal-fired units to meet the
Clean Air Interstate Rule ("CAIR")requirements for NOx which are in effect while the Cross
State Air Pollution Rule is under a court-ordered stay. Additionally, SCE&G has installed flue
gas desulfurization ("FGD")equipment, commonly known as wet scrubbers, at Williams and
Wateree Stations to reduce SO2 emissions. The in-service dates for Williams and Wateree
Stations were February 25,2010,and October 12, 2010, respectively. Scrubber performance
tests at both stations met the SO2 designed removal rate of 98%. Mercury emission control has
also been realized in the industry via the operation of FGD equipment. Consequently,the
continued operation of the FGD equipment will contribute to SCE&G's strategy for meeting the
impending requirements of the US EPA's Mercury and Air Toxics Standard("MATS")that will
become effective on April 16, 2015. The Chem-Mod fuel additive being used at McMeekin
Station, Cope Station,and Williams Station will similarly contribute to SCE&G's efforts in stack
emission control for mercury, as well as for NOx and SO2.
In response to the US EPA's impending MATS,the last coal-fired boiler at Urquhart
Station, Unit 3,was converted to natural gas. Decommissioning of the plant's former coal
handling facilities is in progress. Also in response to MATS Canadys Station ceased operations
on November 6,2013, and decommissioning efforts are in progress.
In an effort to cease bottom ash sluicing to the Wateree Station's ash ponds, SCE&G
installed two remote submerged flight conveyors that dewater boiler bottom ash sluice and
21

recycle the overflow back to the boiler for reuse. This retrofit was completed for Units 1 and 2
during October 2012. The bottom ash is then marketed as an ingredient in the manufacture of
pre-stressed concrete products.
g.Nuclear Power in the Future—Small and Modular: Small Modular Reactor("SMR")
technology continues to be developed. DOE has awarded two grants,totaling$452 million, for
SMR development. At about a third, or less, of the size of current nuclear power plants, SMRs
could make available, for a smaller capital investment,a modular design for specific generation
needs. SCE&G will continue to evaluate this technology as it develops.
3. Summary of Proposed and Recently Finalized Regulations
The EPA has either proposed or recently finalized 6 regulations and modified one
additional regulation. These are Cross-State Air Pollution Rule("CSAPR"), Mercury and Air
Toxics Standards("MATS"), Greenhouse Gases, Cooling Water Intake Structures, Coal
Combustion Residuals, Effluent Limitation Guidelines,and a new 1-hour sulfur dioxide National
Ambient Air Quality Standard("NAAQS").
a. Cross-State Air Pollution Rule("CSAPR")
On December 30,2011,the U.S. Court of Appeals for the District of Columbia Circuit issued a
stay delaying implementation of CSAPR pending the outcome of a legal appeal. On August 21,
2012,the U.S. Court of Appeals for the D.C. Circuit vacated CSAPR and left CAIR in place.
The federal court ordered the EPA to continue administering the previously promulgated CAIR.
On October 5,2012,the EPA filed a petition for rehearing of the order. On January 24,2013,
the United States Court of Appeals for the D.C. Circuit denied EPA's petition for rehearing.
The Court ordered EPA to continue to enforce the 2005 CAIR until CSAPR could be re-issued.
The EPA's petition for rehearing of the Court of Appeals'order was denied. In June 2013,the
U.S. Supreme Court agreed to review the Court of Appeals'decision and oral arguments were
held on December 10,2013. A decision is still pending. Air quality control installations that
SCE&G has already completed have allowed the Company to comply with the reinstated CAIR
and will also allow it to comply with CSAPR if reinstated.
CSAPR, which was intended to replace CAIR, was initially finalized in July 2011 under
the Clean Air Act and would affect 27 states including South Carolina,requiring reductions in
22

sulfur dioxide (SO2)and nitrogen oxides(NOx)emissions beginning in 2012,with stricter
reductions in 2014. The rule established an emissions cap for SO2 and NOx and limited the
trading region for emission allowances by separating affected states into two groups with no
trading between the groups.
SCE&G Fossil Hydro generation is in compliance with emission limits set by CSAPR
and CAIR.
b. Mercury and Air Toxics Standards("MATS")
Proposed under the Clean Air Act,this rule sets numeric emission limits for mercury,
particulate matter as a surrogate for toxic metals, and hydrogen chloride as a surrogate for acid
gases. The final rule also revises new source performance standards for power plants to address
emissions of particulate matter, sulfur dioxide and nitrogen oxides. The rule would replace the
court-vacated Clean Air Mercury Rule. MATS was proposed in May 2011, and the final rule
was issued on December 21,2011.
The rule became effective on April 16,2012. Compliance with MATS is required within
three years. A 1-year extension may be granted by the state permitting authorities if additional
time is needed for units that are required to run for reliability purposes which would otherwise be
deactivated,or which, due to factors beyond the control of the owner/operator, have a delay in
installation of controls or need to operate because another unit has had such a delay. It is
expected that coal-fired generators will need to have a combination of flue gas desulfurization,
selective catalytic reduction and fabric filters in order to comply with the standards. A second
year of extension may also be possible for reliability critical units that qualify for an
Administrative Order at the end of the 1-year extension. All extension requests must be
supported by the written concurrence of the appropriate Planning Authority and will be
considered by EPA on a case-by-case basis, supplemented by consultation with FERC and/or
other entities with relevant reliability expertise as appropriate.
SCE&G applied for and received a 1-year extension from DHEC for both McMeekin and
Canadys. With the retirement of Canadys in the 4th quarter of 2013,only McMeekin has a
waiver that will allow the continued use of coal until April 2016.
23

c. Greenhouse Gases
The EPA's rule addressing the emission of greenhouse gases was proposed under the
Clean Air Act and would establish performance standards for new and modified generating units,
along with emissions guidelines for existing generating units.This action will amend the new
source performance standards("NSPS") for electric generating units("EGU")and will establish
the first NSPS for greenhouse gas("GHG")emissions. The Rule essentially requires all new
fossil fuel-fired power plants to meet the carbon dioxide ("CO2")emissions profile of a
combined cycle natural gas plant. While most new natural gas plants will not be required to
include any new technologies,no new coal plants can be constructed without carbon capture and
sequestration("CCS")capabilities. The first part of this rule,related to new generation sources,
was released in April 2012 and was expected to become final in March 2013.
As part of the President's Climate Action Plan and by Presidential Memorandum issued
June 25, 2013,the EPA issued a revised carbon standard for new power plants by re-proposing
NSPS under the CAA for emissions of carbon dioxide from newly constructed fossil fuel-fired
units. The April 2012 rule was withdrawn by EPA and the new rule,which became final on
January 8, 2014, still requires all new fossil fuel-fired power plants to meet the carbon dioxide
. emissions profile of a combined cycle natural gas plant. While most new natural gas plants will
not be required to include any new technologies, no new coal fired plants could be constructed
without carbon capture and sequestration capabilities. The Company is evaluating the final rule,
but does not plan to construct new coal fired units in the near future.
The Presidential Memorandum also directed EPA to issue standards, regulations, or
guidelines for existing units by June 1,2014,to be made final no later than June 1, 2015. The
Company also cannot predict when rules will become final for existing units, if at all, or what
conditions they may impose on the Company, if any.
SCE&G's new nuclear generation will mitigate CO2 concerns going forward. The
following chart shows that SCE&G's CO2 emissions will fall well below its 1995 level after the
next several years.
24

SCE&G Electric CO2
21 — --- -
19
17
15
0
I-
g 13
11
9
7 - I I I 1 I 1 I I 1 I I 1 I I , , I I
111 LO N. CO 01 O N m Vl l0 CO O1 O .--1 N
O O 0 0 0 -I e-I .--I a--I r-1 a--I N N N
O O 0 0 O 0 0 0 0 0 0 0 0 0 0 0 0 0
N N N N N N N N N N N N N N N N N N
—Actual —Projected —1995 Actual —2005 Actual
010614
d. Cooling Water Intake Structures
Proposed under section §316(b) of the Clean Water Act, this rule is intended to reduce
damage to aquatic life through impingement, when organisms are trapped against inlet screens,
and entrainment, when they are drawn into the generator's cooling water system. Facilities that
withdraw at least 2 million gallons per day would be subject to a limit on the number of fish that
can be killed through impingement. Facilities that withdraw at least 125 million gallons per day
and new units at existing facilities may be subject to more stringent restrictions. The rule was
proposed in April 2011, and a final rule is now expected by April 17, 2014.
There is considerable uncertainty regarding when the regulations would be effective and
the steps that would have to be taken in order to meet them. Facilities must comply with Best
Available Technology Standards within 8 years, but many required submittals are due much
earlier, as early as six months after rule promulgation. Compliance actions range from enhanced
screening and reconfiguration of water intake systems to installation of cooling towers to reduce
the flow rate. On SCE&G's system, Jasper, Cope and Wateree Stations have closed cycle
cooling towers installed and should not be significantly affected by these regulations. The
Company is currently conducting studies and is developing or implementing compliance plans
for these initiatives.
25

e. Coal Combustion Residuals
In response to concerns over the potential structural failure of coal ash impoundment
facilities instigated by the December 2008 failure that occurred at a Tennessee Valley Authority
facility, EPA has proposed changing the classification of coal combustion residuals from its
current status of an exempt waste. Two options were proposed under the Resource Conservation
and Recovery Act: (1)list residuals as special hazardous wastes when destined for disposal in
landfills or surface impoundments or(2) regulate as a non-hazardous waste. The proposed rule
was released in June 2010 and comments were received through November 2010. EPA has not
issued the rule as yet and has not specified when a final rule will be issued. The effective date is
believed to be dependent on which option is selected. If coal combustion residuals are classified
as non-hazardous wastes, the rule would be effective six months after promulgation. A special
hazardous waste designation would likely push compliance out until about 2021 when the state
adopts the rule. Timing will vary from state to state.
On January 18, 2012, several environmental groups, led by Earthjustice, filed a notice of
intent to sue the EPA to force the agency to finalize its proposed rule determining how coal
combustion residuals(commonly referred to as"coal ash")will be categorized. On January 22,
2013,the Court in the coal combustion residuals("CCR")deadline litigation postponed the
status conference in the case until April 26,2013. On October 29,a federal district judge
ordered EPA to file by December 29, 2013, a timeline for the completion of this rule. However,
because environmental groups and coal ash recyclers are in settlement negotiations concerning
the timeline, in December,the district court accepted a motion to give EPA additional time
(until late January)to file the timeline. In January, a consent decree was filed that sets forth
EPA's obligation to sign, by December 19, 2014, a notice for publication in the Federal Register
taking final action on the Agency's rule for CCR.
The final CCR rule may require the closure of ash ponds. SCE&G has three generating
facilities that have employed ash storage ponds,and all of these ponds have either been closed
after all ash was removed or are part of an ash pond closure project that includes complete
removal of the ash prior to closure. The electric generating facilities which continue to be coal-
fired have dry ash handling,and the ash ponds undergoing closure have a detailed dam safety
inspection conducted at least quarterly.
26

f.Effluent Limitation Guidelines
The Clean Water Act("CWA")establishes the basic structure for regulating discharges of
pollutants into the waters of the United States. It provides EPA and the States with a variety of
programs and tools to protect and restore the nation's waters. These programs and tools
generally rely either on water quality-based controls, such as water quality standards and water
quality-based permit limitations, or technology-based controls such as effluent guidelines and
technology-based permit limitations. The EPA is currently developing a proposed rule to amend
the effluent guidelines and standards for the Steam Electric Power Generating category. Once
issued,the Steam Electric effluent guidelines and standards will be incorporated into State
administered wastewater permits known as National Pollutant Discharge Elimination System
("NPDES")permits. EPA's decision to proceed with a rulemaking was announced on
September 15, 2009, following completion of a preliminary study.
EPA reviewed wastewater discharges from power plants and the treatment technologies
available to reduce pollutant discharges. EPA believes that the current regulations, which were
last updated in 1982, do not adequately address the pollutants being discharged and have not kept
pace with changes that have occurred in the electric power industry over the last three decades.
EPA's main reason for this concern is that the air pollution control technologies that have been
retrofitted to power plants in order to reduce air emissions put a majority of those contaminants
into the wastewater discharge. In 2010, EPA submitted an Information Collection Request
("ICR")to all electric utilities to aid in their review of plant operations, pollution control
technologies, and current wastewater discharges. Consequently, SCE&G expended considerable
time and resources to answer a 213-page questionnaire for each of its electric generating
facilities.
Under the CWA,compliance with applicable limitations is achieved under State-issued
National Permit Discharge Elimination System (NPDES)permits. As a facility's NPDES permit
is renewed(every 5 years)any new effluent limitations would be incorporated. New federal
effluent limitation guidelines for steam electric generating units (the ELG Rule)were published
in the Federal Register on June 7, 2013. Comments were due by September 20,2013, and the
rule is expected to be finalized May 22, 2014. EPA expects compliance as soon as possible after
July 2017 but no later than July 2020. Once the rule becomes effective,the State environmental
regulators will modify the NPDES permits to match more restrictive standards thus requiring
utilities to retrofit each facility with new wastewater treatment technologies. Based on the
27

proposed rule, SCE&G expects that wastewater treatment technology retrofits will be required at
Williams and Wateree at a minimum.
g.NAAQS 1-hour SO2
In June 2010, EPA revised the primary SO2 standard by establishing a new 1-hour
standard at a level of 75 parts per billion("ppb"). The EPA revoked the two existing primary
standards of 140 ppb evaluated over 24-hours, and 30 ppb per hour averaged over an entire year.
The new form is the 3-year average of the 99th percentile of the annual distribution of daily
maximum 1-hour average concentrations. EPA also required states to install new monitors by
January 1, 2013. Compliance requires both monitoring and refined dispersion modeling of SO2
sources to meet the new standard.
The new 1-hour national ambient air quality standard("NAAQS")for SO2 presents new
challenges and is driving strategic planning for large SO2 emitters around the country. For this
new standard, EPA is requiring the unusual step of using air quality modeling for criteria
pollutant attainment designations. EPA released its draft guidance for this State Implementation
Plan("SIP")modeling and the states prepared for designation modeling efforts. However, later
guidance issued during June 2012 indicated that EPA would back off of the modeling
requirement.
Historically, ambient air monitoring data has provided the basis for attainment
designations. The shift to using models instead of ambient data poses significant challenges.
For example, due to the stringent nature of the short term SO2 standards,the conservative nature
of the models and use of conservative inputs in the model (short-term emission limits),the
results can significantly overstate reality. Also there are likely to be surprises for historically
grandfathered sources or even new well-controlled sources.
During 2013, EPA deferred designations for South Carolina for future action. On
January 7,2014, EPA made available two updated draft documents that provide technical
assistance for states implementing the 2010 health-based, sulfur dioxide(SO2) standard. These
documents provide technical advice on the use of modeling and monitoring to determine if an
area meets the 2010 SO2 air quality standard. In a future rule expected in 2014,the EPA will
establish requirements for characterizing SO2 air quality in priority areas, focusing on areas with
sources that have emissions higher than a threshold amount. The EPA expects to establish these
thresholds taking population into account. States will have the flexibility to characterize air
28

quality using modeling of actual emissions or using appropriately sited existing and new
monitors. These data would be used in two future rounds of designations in 2017 (based on
modeling) and 2020 (based on new monitoring). EPA expects to issue a Data Requirements
Rule for implementing the 1-Hour SO2 standard during 2014. Air quality control installations
that SCE&G and GENCO have already completed and planned retirements of older coal-fired
units are expected to allow the Company to comply with the 1-Hour SO2 standard.
4. Supply Side Resources at SCE&G
a.Existing Supply Resources
SCE&G owns and operates six(6)coal-fired fossil fuel units,one(1) gas-fired steam
unit, eight(8)combined cycle gas turbine/steam generator units (gas/oil fired), sixteen(16)
peaking turbine units, four(4)hydroelectric generating plants, and one Pumped Storage Facility.
In addition, SCE&G receives the output of 85 MWs from a cogeneration facility. The total net
non-nuclear summer generating capability rating of these facilities is 4,590 MWs in summer and
4,764 MWs in winter. These ratings,which are updated at least on an annual basis, reflect the
expectation for the coming summer and winter seasons. When SCE&G's nuclear capacity(647
MWs in summer and 661 MWs in winter), a long term capacity purchase(25 MWs)and
additional capacity(20 MWs)provided through a contract with the Southeastern Power
Administration are added, SCE&G's total supply capacity is 5,282 MWs in summer' and 5,470
MWs in winter. This is summarized in the table on the following page.
1 This supply capacity does not include the Company's solar generator with a DC nominal rating of 2.6 MWs which
lies behind a customer's meter.
29

Existing Long Term Supply Resources
The following table shows the generating capacity that is available to SCE&G in 2014.
In-Service Summer Winter
Date IMW1 fMW)
Coal-Fired Steam:
McMeekin—Near Irmo,SC 1958 250 250
Wateree—Eastover,SC 1970 684 684
*Williams—Goose Creek, SC 1973 605 610
Cope -Cope, SC 1996 415 415
Kapstone —Charleston,SC 1999 85
Total Coal-Fired Steam Capacity 2.039 2.044
Gas-Fired Steam:
Urquhart—Beech Island, SC 1953 95 96
Nuclear:
V.C. Summer-Parr, SC 1984 647 661
I.C.Turbines:
Hardeeville, SC 1968 9 9
Urquhart—Beech Island, SC 1969 39 48
Coit—Columbia, SC 1969 28 38
Parr, SC 1970 60 73
Williams—Goose Creek, SC 1972 40 52
Hagood—Charleston,SC 1991 128 145
Urquhart No. 4—Beech Island, SC 1999 48 49
Urquhart Combined Cycle—Beech Island, SC 2002 458 484
Jasper Combined Cycle—Jasper, SC 2004 852 924
Total I. C.Turbines Capacity 1,662 1,822
Hydro:
Neal Shoals—Carlisle,SC 1905 3 4
Parr Shoals—Parr, SC 1914 7 12
Stevens Creek-Near Martinez,GA 1914 8 10
Saluda-Near Irmo, SC 1930 200 200
Fairfield Pumped Storage-Parr, SC 1978 576 576
Total Hydro Capacity 794 802
Other: Long-Term Purchases 25 25
SEPA 20 20
Grand Total: 1212 5.470
* Williams Station is owned by GENCO,a wholly owned subsidiary of SCANA and is operated by SCE&G.
Not reflected in the table is a solar PV generator owned by SCE&G with a nominal direct current rating of
2.6 MWs nor a purchase of 300 MWs of firm capacity for the years 2014-2015.
30

The bar chart below shows SCE&G's actual 2013 relative energy generation and relative
capacity by fuel source.
2013 Resource Mix
Hydro )♦ 4% °
14%
Nuclear 24%
12%
Coal 45%
41%
Gas
32%
Biomass 1%
1%
0% 10% 20% 30% 40% 50%
■Energy ■Capacity
b. DSM from the Supply Side
SCE&G is able to achieve a DSM-like impact from the supply side using its Fairfield
Pumped Storage Plant. The Company uses off-peak energy to pump water uphill into the
Monticello Reservoir and then displaces on-peak generation by releasing the water and
generating power. This accomplishes the same goal as many DSM programs, namely, shifting
use to off-peak periods and lowering demands during high cost, on-peak periods. The following
graph shows the impact that Fairfield Pumped Storage had on a typical summer weekday.
Impact of Pumped Storage
Average Summer Day in 2013
4000r. —
m
3500 -----
3000 —_— --
eo
iv 2500 — — — — ---
2000
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
(Territorial Load 4 Net of Fairfield
31

•
In effect the Fairfield Pumped Storage Plant was used to shave about 218 MWs from the
daily peak times of 2:00pm through 6:00pm and to move about 2.4%of customer's daily energy
needs off peak. Because of this valuable supply side capability,a similar capability on the
demand side, such as a time of use rate, would be less valuable on SCE&G's system than on
many other utility systems.
c.Planning Reserve Margin and Operating Reserves
The Company provides for the reliability of its electric service by maintaining an
adequate reserve margin of supply capacity. The appropriate level of reserve capacity for
SCE&G is in the range of 14 to 20 percent of its firm peak demand. This range of reserves will
allow SCE&G to have adequate daily operating reserves and to have reserves to cover two
primary sources of risk: supply risk and demand risk.
Supply reserves are needed to balance the"supply risk"that some SCE&G generation
capacity may be forced out of service or its capacity reduced on any particular day because of
mechanical failures, fuel related problems,environmental limitations or other force
majeure/unforeseen events. The amount of capacity forced-out or down-rated will vary from
day-to-day. SCE&G's reserve margin range is designed to cover most of these days as well as
the outage of any one of our generating units.
Another component of reserve margin is the demand reserve. This is needed to cover
"demand risk" related to unexpected increases in customer load above our peak demand forecast.
This can be the result of extreme weather conditions or other unexpected events.
The level of daily operating reserves required by the SCE&G system is dictated by
operating agreements with other VACAR companies. VACAR is the organization of utilities
serving customers in the Virginia-Carolinas region of the country who have entered into a
reserve sharing agreement. These utilities are members of the SERC Reliability Corporation, a
nonprofit corporation responsible for promoting and improving the reliability of the bulk power
transmission system in much of the southeastern United States. While it can vary by a few
megawatts each year, SCE&G's pro-rata share of this capacity is always around 200 megawatts.
To analyze these three components of reserve and establish a reserve margin target range,
SCE&G employs three methodologies: 1)the component method which analyzes separately
each of the three components mentioned above;2)the traditional and industry standard
technique of"Loss of Load Probability,"or LOLP, using a range of LOLP from 1 day per year to
32

1 day in 10 years; and 3)the largest unit out method. The results of this analysis are summarized
in the following table and support a reserve margin target range of 14%to 20%.
Low MWs Low % High MWs High 6/0
Component Method 766 16.0% 1016 21.3%
LOLP 721 14.4% 1171 23.5%
Largest Unit 644 13.5% 966 20.2%
644 1171
Reserve Policy 14.0% 20.0%
By maintaining a reserve margin in the 14 to 20 percent range, the Company addresses the
uncertainties related to load and to the availability of generation on its system. It also allows the
Company to meet its VACAR obligation. SCE&G will monitor its reserve margin policy in light
of the changing power markets and its system needs and will make changes to the policy as
warranted.
d. New Nuclear Capacity
On May 30,2008, SCE&G filed with the Commission a Combined Application for a
Certificate of Environmental Compatibility and Public Convenience and Necessity and for a
Base Load Review Order for the construction and operation of two 1,117 net MW nuclear units
to be located at the V.C. Summer Nuclear Station near Jenkinsville, South Carolina. Following a
full hearing on the Combined Application,the Commission issued Order No. 2009-104(A)
granting SCE&G,among other things, a Certificate of Environmental Compatibility and Public
Convenience and Necessity.
On March 30, 2012,the United States Nuclear Regulatory Commission issued a
combined Construction and Operation License ("COL")to SCE&G for each unit. Both units
will have the Westinghouse AP1000 design and use passive safety systems to enhance the safety
of the units.
On January 27,2014, SCE&G and Santee Cooper agreed to increase SCE&G's
ownership share from 55%to 60% in three stages. •SCE&G will acquire an additional 1%of the
2,234 MWs of capacity when Unit#2 achieves commercial operation which is expected around
December 2017 or the first quarter of 2018. An additional 2%will go to SCE&G one year later
33

and another 2%one year after that. By December 2019 or the first quarter of 2020, SCE&G will
own 60%of both units(670 MWs each)while Santee Cooper will own 40%.
e. Retirement of Coal Plants
When the EPA promulgated its Mercury and Air Toxics Standards("MATS") on
December 21,2011, SCE&G had six small coal-fired units in its fleet totaling 730 MWs ranging
in age from 45 to 57 years that could not meet the emission standards without further
modifications to the units. Those six units are displayed in the following table.
Plant Name Capacity(MW) Commercialization Date
Canadys 1 90 1962
Canadys 2 115 1964
Canadys 3 180 1967
Urquhart 3 95 1955
McMeekin 1 125 1958
McMeekin 2 125 1958
After a thorough retirement analysis,the Company decided that these six units would be retired
when the addition of new nuclear capacity was available as a replacement 2 As part of this
retirement plan the Company has retired Canadys' Units#1, 2 and 3 and has converted Urquhart
#3 to be fired with natural gas while dismantling the coal handling facilities at this unit. The
capacity(250 MWs)of the remaining two coal-fired units,McMeekin 1&2, is required to
maintain system reliability until the new nuclear capacity is available. Under the MATS
regulations but with a one year waiver granted by South Carolina Department of Health and
Environmental Control ("SCDHEC")these units cannot run on coal after April 15, 2016. The
Company is currently looking at ways to bridge, with dispatchable resources,the gap between
the MATS compliance date and the availability of the new nuclear capacity.
2 In announcing its plans to retire the units in its 2012 Integrated Resource Plan,the Company
was careful to note that its retirement plans were subject to change if circumstances changed.
See SCE&G's 2012 Integrated Resource Plan,at 29(May 30,2012) ("Although today's
reference resource plan calls for the retirement of the six coal-fired units,the Company will
continue to monitor, among other things,developments in environmental regulation and will
continue to analyze its options and modify the plan as needed to benefit its customers.").
34

f. Renewable Resources
SCE&G continues to monitor the development of renewable sources of energy and looks
for economic opportunities to include them in its resource plan.
1. Busbar Costs of Renewable Resources
The following charts show the busbar cost of renewable resources compared to other
potential resource additions. The busbar cost is shown in terms of$/MWh at various capacity
factors. It is assumed that the overnight capital costs of solar PV and off-shore wind are$3,873
per KW and$6,230 per KW respectively. The capital cost for a combined cycle facility and a
combustion turbine facility are $1,023 per KW and $676 per KW respectively. Solar PV and off
shore wind can be seen as more costly than traditional sources of power.
There are four charts shown on the next page. The two charts on the left side of the page
show the busbar costs with and without the federal investment tax credit("ITC"). As an
approximation it is assumed that the ITC will reduce the capital cost of solar and wind by 30%.
The two charts on the right side of the page show the same information but with the vertical axis
truncated at$500/MWh thereby displaying more granularity at higher capacity factors.
35

$/MWh vs Capacity Factor $/MWh vs Capacity factor
3000 -- 500 —
450
400
20002500 350
300
1144\1 1:116411E.4111:000,0000.04.0.01=0:0404=0=0
1500 _ 250
200
1000 150
100
500 50
0 - 111111111
1 1 1 1 , 1 1
0 ' o o g o * o o .eo 0 0 0 0 • o e o
o a` a° a° as ae ae ae a° a° 0 az a° a` a° gz az a° az "' O� r-i ON N Om m d- d- O� Ln ODD O^ I"', COO CO 0 01 0
"1 O In O v1 O In O In O If O v1 O v1 O In o "1 a1
a1 a1 N N M M 7 7 In in l0 l0 N N CO CO 01 01
Solar PV —Off-Shore Wind —0—Solar PV --Off-Shore Wind
—a—Combustion Turbine-4E—Combined Cycle Combustion Turbine—)E—Combined Cycle
1
$/MWh vs Capacity Factor $/MWh vs Capacity Factor
30% ITC for Solar and Wind 30% ITC for Solar and Wind
3000 450
-
2500 400
2000 300
1500
5
1000 150 -
500 150
0 o 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 I
of 0 e 0 1 e ae e I C I C a° ae az ae a° off° C e'e oUi C e C e e e C 0 0 e. 0 0 0 a° o o
Lnc, u1 0 11 0 to O In O In O u1 O In O In O In O V1 O In O u1 O v1 O u1 O in O In O "1 O O in O
a1 a1 N N m m vt "1 In l0 l0 I� o0 00 01 01 O a--I a--I N N M M vt u1 in l0 l0 I� n 00 00 01 01 O
a--I ri
—0—Solar PV —0—Off-Shore Wind —0—Solar PV —E—Off-Shore Wind
—a—Combustion Turbine-44—Combined Cycle —a—Combustion Turbine-44—Combined Cycle
I
36

2. CO2 Emissions and Renewable Resources
The following table compares several types of generation to SCE&G's new nuclear
capacity in terms of CO2 output, both emitted and avoided, assuming that half gas and half coal
generation is being displaced.
Equivalent Avoided CO2 Emissions to SCE&G's New Nuclear Capacity
Avoided CO2 Output Capacity CO2 Emissions
Type Emissions MWh MW Tons
New Nuclear 6,756,327 10,564,560 1,340 0
Solar PV 6,756,327 10,564,560 7,354 0
Offshore Wind 6,756,327 10,564,560 3,260 0
Combined Cycle 6,756,327 25,316,685 3,613 9,434,389
To avoid the same number of tons of CO2 as 1,340 MWs of nuclear capacity, you would need
more than 5 times that capacity,in solar PV capacity or almost 2.5 times that capacity in off shore
wind capacity or more than 2.5 times that capacity in gas fired combined cycle capacity.
3.The Projected Cost of Distributed Solar Photovoltaic Energy
The National Renewable Energy Laboratory("NREL") has produced and made available
to the public a financial calculator to evaluate renewable technologies. The NREL model known
as the System Advisor Model ("SAM")was used to estimate the level cost of solar energy
("LCOE") in South Carolina under several scenarios. See https://sam.nrel.gov for more
information on the SAM model. The following table shows the LCOE for a commercial
customer seeking a power purchase agreement("PPA"). The LCOE is reduced by both a federal
and a state investment tax credit("ITC") and by the use of accelerated depreciation, in particular,
5 year MACRS. It assumes the project is financed with 80%debt at 7%interest with a target
internal rate of return("IRR")of 15%. Since the capital cost of a solar PV installation are size
and site specific and since the costs continue to change each year,the LCOE is shown for several
levels of capital cost.
37

Levelized Cost of Solar Energy for a Commercial Installation
Size 2000 KW Size 200 KW
Capital Cost$/watt L.C.O.E. $/MWh Capital Cost$/watt L.C.O.E. $/MWh
$3.00 $102.50 $4.00 $121.80
$2.50 $88.30 $3.00 $93.40
$2.00 $74.00 $2.50 $79.20
The following table shows similar results for a residential installation.
Levelized Cost of Solar Energy for a
Residential Installation
Size 5 KW
Capital Cost $/Watt L.C.O.E. $/MWh
$6.00 $193.70
$5.00 $155.00
$4.00 $116.30
$3.00 $77.50
4. Potential Impact of Solar PV on the Resource Plan
It is difficult to pinpoint how much and how fast solar photovoltaic energy resources will
develop in SCE&G's service territory,but it is evident that these resources will play a role in
SCE&G's energy supply in the coming years. The cost of solar panels and associated equipment
has been decreasing over the past years. Much of the ongoing and future cost reduction of solar
farms is likely to be driven by efficiencies in design and construction, and the pace of reductions
is likely to slow,but how far and how fast the costs will drop in the future is not certain. Federal
and state tax incentives encourage the installation of solar facilities, but the level of support is
likely to change in the future. Finally solar development is encouraged through the policy of net
energy metering("NEM")whereby all solar energy generated at a customer's site is valued at
the customer's retail rate. Since much of the utility's fixed costs are recovered through a
volumetric, per kWh charge,utilities generally claim that this policy is not sustainable.
Conversely,particular solar installations may bring value to the system that is unaccounted for
under current rate designs. SCE&G is working to better understand the costs and benefits of
solar energy resources on its system so that costs and value are appropriately accounted for. The
38

following table shows the impact of solar generation when its DC capacity is set to 2%of
SCE&G's firm system peak.Approximately 56%of the DC rating of solar capacity will be
generating on a summer afternoon and contribute to reducing the summer peak demand.There
will be no solar generation at the time of SCE&G's winter peak demand which usually occurs
between 7 and 8 am.
Impact When Solar DC Capacity Set to 2%of System Peak
Percent
System Solar Summer Winter Solar of
Peak DC MW Peak Peak Energy Retail
Year MW @1% Impact Impact MWH Sales
2014 4,786 96 54 0 134,161 0.6%
2015 4,849 97 54 0 135,927 0.6%
2016 4,968 99 56 0 139,263 0.6%
2017 5,074 101 57 0 142,234 0.6%
2018 5,166 103 58 0 144,813 0.6%
2019 5,246 105 59 0 147,056 0.6%
2020 5,319 106 60 0 149,102 0.6%
2021 5,385 108 60 0 150,952 0.6%
2022 5,458 109 61 0 152,999 0.6%
2023 5,540 111 62 0 155,297 0.6%
2024 5,623 112 63 0 157,624 0.6%
2025 5,704 114 64 0 159,895 0.6%
2026 5,790 116 65 0 162,305 0.6%
2027 5,867 117 66 0 164,464 0.6%
2028 5,942 119 67 0 166,566 0.6%
g.Projected Loads and Resources
SCE&G's resource plan for the next 15 years is shown in the table labeled "SCE&G
Forecast Loads and Resources -2014 IRP" on a subsequent page. The resource plan shows the
need for additional capacity and identifies, on a preliminary basis,whether the need is for
peaking/intermediate capacity or base load capacity.
On line 10 the resource plan shows decreases in capacity which relate to the retirement of
coal units as previously discussed. The resource plan shows the addition of peaking capacity on
line 8 and the need for any firm one year capacity purchases on line 12. The Company has
secured the purchase of 300MWs in the years 2014 through 2016. Capacity is added to maintain
the SCE&G's planning reserve margin within the target range of 14%to 20%. The resource plan
39

thus constructed represents one possible way to meet the increasing demand of our customers.
Before the Company commits to adding a new resource, it will perform a study to determine
what type resource will best serve our customers.
The Company believes that its supply plan, summarized in the following table,will be as
benign to the environment as possible because of the Company's continuing efforts to utilize
state-of-the-art emission reduction technology in compliance with state and federal laws and
regulations. The supply plan will also help SCE&G keep its cost of energy service at a minimum
since the generating units being added are competitive with alternatives in the market.
40

SCE&G Forecast of Summer Loads and Resources-2014 IRP
YEAR 20141 2015 2016 2017 20181 2019 2020 20211 2022! 2023! 20241 20251 2026 2027 2028
Load Forecast
11 {Base1Ine Trend 5046! 5113 5272 5407 55251 56321 5734! 58301 59211 60231 6125! 62271 6332 64301 6525
-------- -1031 � -1871 -2031 -2201 -236' -2531 -270
21
EE Impact -31 -4 371 -581 -80 -1291 -1561 -171 1
31 .
Gross Territorial Peak 50431 5109 5235_ 53491 5445! 5529' 5605! 56741 57501 58361 59221 60071 6096 61771 6255
41 !Demand Response -257 -260 -267 -275 -279' -283 -286; -2891 -292 -296 -2991 -3031 -306. -310; -313
5! ,Net Tentorial Peak 4786! 4849 4968. 5074 5166! 5246 5319! 5385 5458' 5540! 56231 57041 5790 5867' 5942
System Capacity
s Endstkng 5282 5287 5290 5293 5293 5918 6242 6288 ' 6288: 6288 63811 6474! 6567 6660 6753
Additions
71 1Solar Plant(20 MWs DC) 5 3 3
_
el (Peak glhtermedieate 931 9311_ 931 93 93' 93
9! IBasebad 625. 669 461
l01 [Retirements -345
11! !Total SSystem Capacity 5287' 5290 5293 5293 59181 6242 6288' 62881 6288, 6381' 6474 6567 6660 6753 6846
12! !Finn Annual Purchase 300 300 375' 500
13! 1Total Production Capabity 558i 5590 5668 57931 59181 6242 62881 62881 6288! 6381! 6474 6561 6660 6753. 6846
Reserves
141 Margin(L13-L5) 801! 741 700' 719 7521 996! 9691 903 830 8411 8511 8631 870 8861 904
15 1%Reserve Margin�4A.5) _16.7%1 15.3%, 14.1%: 14.2% 14.696 19.0%' 182%i 16.8%1 15.2%! 15.2%! 151%! 15.1% 15.0% 15.1% 15.2%
161 1%IARC Res.Mgn L141(L5-L4) 15.9%1 14.5% 13.4%j 13.4% 13.8%1 18.0%! 17.3%1 15.9%1 14.4%! 14.4%1 14.4%i 14.4%; 14.3%: 14.3%1 14.5%
Note: L17 shows the reserve margin calculated according to NERC's new definition. See the following link for details:
http://www.nerc.com/docs/Dc/ris/RIS Report on Reserve Margin Treatment of CCDR %2006.01.10.pdf
41

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42

III. Transmission System Assessment and Planning
SCE&G's transmission planning practices develop and coordinate a program that provides
for timely modifications to the SCE&G transmission system to ensure a reliable and economical
delivery of power. This program includes the determination of the current capability of the
electrical network and a ten-year schedule of future additions and modifications to the system.
These additions and modifications are required to support customer growth,provide emergency
assistance and maintain economic opportunities for our customers while meeting SCE&G and
industry transmission performance standards.
SCE&G has an ongoing process to determine the current and future performance level of
the SCE&G transmission system. Numerous internal studies are undertaken that address the
service needs of our customers. These needs include: 1)distributed load growth of existing
residential,commercial, industrial,and wholesale customers, 2) new residential, commercial,
industrial, and wholesale customers and 3)customers who use only transmission services on the
SCE&G system.
SCE&G has developed and adheres to a set of internal Long Range Planning Criteria
which can be summarized as follows:
•
The requirements of the SCE&G "LONG RANGE PLANNING CRITERIA"will be
satisfied if the system is designed so that during any of the following contingencies, only
short-time overloads, low voltages and local loss of load will occur and that after
appropriate switching and re-dispatching, all non-radial load can be served with
reasonable voltages and that lines and transformers are operating within acceptable
limits.
a. Loss of any bus and associated facilities operating at a voltage level of 115kV or
above
b. Loss of any line operating at a voltage level of 11 SkV or above
c. Loss of entire generating capability in any one plant
d. Loss of all circuits on a common structure
e. Loss of any transmission transformer
f Loss of any generating unit simultaneous with the loss of a single transmission line
Outages more severe are considered acceptable if they will not cause equipment damage
or result in uncontrolled cascading outside the local area.
Furthermore, SCE&G subscribes to the set of mandatory Electric Reliability Organization
("ERO"), also known as the North American Electric Reliability Corporation ("NERC"),
43

Reliability Standards for Transmission Planning, as approved by the NERC Board of Trustees and
the Federal Energy Regulatory Commission("FERC").
SCE&G assesses and designs its transmission system to be compliant with the
requirements as set forth in these standards. A copy of the NERC Reliability Standards is
available at the NERC website http://www.nerc.com/.
The SCE&G transmission system is interconnected with Duke Energy Progress, Duke
Energy Carolinas, South Carolina Public Service Authority("Santee Cooper"),Georgia Power
("Southern Company")and the Southeastern Electric Power Administration("SEPA") systems.
Because of these interconnections with neighboring systems, system conditions on other systems
can affect the capabilities of the SCE&G transmission system and also system conditions on the
SCE&G transmission system can affect other systems. SCE&G participates with other
transmission planners throughout the southeast to develop current and future power flow and
stability models of the integrated transmission grid for the NERC Eastern Interconnection. All
participants' models are merged together to produce current and future models of the integrated
electrical network. Using these models, SCE&G evaluates its current and future transmission
system for compliance with the SCE&G Long Range Planning Criteria and the NERC Reliability
Standards.
To ensure the reliability of the SCE&G transmission system while considering conditions
on other systems and to assess the reliability of the integrated transmission grid, SCE&G
participates in assessment studies with neighboring transmission planners in South Carolina,
North Carolina and Georgia. Also, SCE&G on a periodic and ongoing basis participates with
other transmission planners throughout the southeast to assess the reliability of the southeastern
integrated transmission grid for the long-term horizon (up to 10 years)and for upcoming
seasonal (summer and winter) system conditions.
The following is a list of joint studies with neighboring transmission owners completed
over the past year:
.1. SERC NTSG Reliability 2013 Summer Study
2. SERC NTSG Reliability 2013/2014 Winter Study
3. SERC LTSG 2017 Summer Peak Study
4. SERC NTSG OASIS 2013 January Studies(13Q1) •
5. SERC NTSG OASIS 2013 April Studies(13Q2)
6. SERC NTSG OASIS 2013 July Studies(13Q3)
7. SERC NTSG OASIS 2013 October Studies(13Q4)
8. SERC DSG 2014 Summer Peak/Shoulder/Light Load/Winter Peak, 2015 Summer
Peak,and 2019 Summer Peak/Light Load/Winter Peak Dynamics Studies
44

9. ERAG 2018 Summer Transmission System Assessment
10. CTCA 2019 Summer Study
11. CTCA 2024 Carolinas Wind Study
12. SCRTP 2014 Summer Peak,2013/2014 Winter Peak,2018 Summer Peak, and 2023
Summer Peak Transfer Studies
13. EIPC 2018 &2023 Roll-Up Integration Studies
where the acronyms used above have the following reference:
SERC - SERC Reliability Corporation
NTSG-Near Term Study Group of SERC
LTSG- Long Term Study Group of SERC
OASIS - Open Access Same-time Information System
DSG- Dynamics Study Group .
ERAG- Eastern Interconnection Reliability Assessment Group
CTCA-Carolinas Transmission Coordination Arrangement
SCRTP - South Carolina Regional Transmission Planning
EIPC - Eastern Interconnection Planning Collaborative
These activities, as discussed above,provide for a reliable and cost effective transmission
system for SCE&G customers.
Eastern Interconnection Planning Collaborative(EIPC)
The Eastern Interconnection Planning Collaborative ("EIPC")was initiated by a coalition
of regional Planning Authorities. These Planning Authorities are entities listed on the NERC
compliance registry as Planning Authorities and represent the entire Eastern Interconnection.
The EIPC was founded to be a broad-based, transparent collaborative process among all
interested stakeholders:
- State and Federal policy makers
- Consumer and environmental interests
- Transmission Planning Authorities
- Market participants generating,transmitting or consuming electricity within the
Eastern Interconnection
The EIPC provides a grass-roots approach which builds upon the regional expansion
plans developed each year by regional stakeholders in collaboration with their respective NERC
Planning Authorities. This approach provides coordinated interregional analysis for the entire
45

Eastern Interconnection guided by the consensus input of an open and transparent stakeholder
process.
The EIPC purpose is to model the impact on the grid of various policy options
determined to be of interest by state, provincial and federal policy makers and other stakeholders.
This work builds upon, rather than replaces,the current local and regional transmission planning
processes developed by the Planning Authorities and associated regional stakeholder groups
within the entire Eastern Interconnection. Those processes are informed by the EIPC analysis •
efforts including the interconnection-wide review of the existing regional plans and development
of transmission options associated with the various policy options.
FERC Order 1000—Transmission Planning and Cost Allocation
On July 21, 2011,the FERC issued Order 1000-Transmission Planning and Cost
Allocation by Transmission Owning and Operating Utilities. With respect to transmission
planning,this Final Rule: (1)requires that each public utility transmission provider participate in
a regional transmission planning process that produces a regional transmission plan; (2) requires
that each public utility transmission provider amend its OATT to describe procedures that
provide for the consideration of transmission needs driven by public policy requirements in the
local and regional transmission planning processes; (3) removes from FERC-approved tariffs and
agreements a federal right of first refusal for certain new transmission facilities;and(4) improves
coordination between neighboring transmission planning regions for new interregional
transmission facilities. Also,this Final Rule requires that each public utility transmission
provider participate in a regional transmission planning process that has: (1)a regional cost
allocation method for the cost of new transmission facilities selected in a regional transmission
plan for purposes of cost allocation; and (2)an interregional cost allocation method for the cost
of certain new transmission facilities that are located in two or more neighboring transmission
planning regions and are jointly evaluated by the regions in the interregional transmission
coordination procedures required by this Final Rule. Each cost allocation method must satisfy
six cost allocation principles.
On October 11, 2012, SCE&G filed with the FERC its proposed actions to achieve
compliance with the Regional requirements of Order 1000. On April 18, 2013, FERC
conditionally accepted SCE&G's filing subject to SCE&G providing more clarity and adding
greater detail to SCE&G's compliance plans. On October 15,2013, SCE&G submitted a second
46

filing addressing these points. FERC is currently reviewing SCE&G's second filing. SCE&G
worked with its neighboring planning region(Southeastern Regional Transmission Planning
"SERTP")to develop actions to achieve compliance with the interregional requirements of Order
1000. On July 10, 2013, SCE&G filed with the FERC its proposed actions to achieve
compliance with the Interregional requirements of Order 1000. FERC is currently reviewing
SCE&G's Interregional compliance filing.
•
47

Appendix A

Short Range Methodology
This section presents the development of the short-range electric sales forecasts for the
Company. Two years of monthly forecasts for electric customers, average usage, and total usage
were developed according to Company class and rate structures, with industrial customers
further classified into SIC (Standard Industrial Classification)codes. Residential customers were
classified by housing type(single family, multi-family, and mobile homes), rate, and by a
statistical estimate of weather sensitivity. For each forecasting group,the number of customers
and either total usage or average usage was estimated for each month of the forecast period.
The short-range methodologies used to develop these models were determined primarily
by available data,both historical and forecast. Monthly sales data by class and rate are generally
available historically. Daily heating and cooling degree data for Columbia and Charleston are
also available historically, and were projected using a 15-year average of the daily values.
Industrial production indices are also available by SIC on a quarterly basis,and can be
transformed to a monthly series. Therefore, sales, weather, industrial production indices,and
time dependent variables were used in the short range forecast. In general,the forecast groups
fall into two classifications,weather sensitive and non-weather sensitive. For the weather
sensitive classes, regression analysis was the methodology used,while for the non-weather
sensitive classes regression analysis or time series models based on the autoregressive integrated
moving average (ARIMA)approach of Box-Jenkins were used.
The short range forecast developed from these methodologies was also adjusted for
federally mandated lighting programs, new industrial loads,terminated contracts,or economic
factors as discussed in Section 3.
A-1

Regression Models
Regression analysis is a method of developing an equation which relates one variable,
such as usage,to one or more other variables which help explain fluctuations and trends in the
first. This method is mathematically constructed so that the resulting combination of explanatory
variables produces the smallest squared error between the historic actual values and those
estimated by the regression. The output of the regression analysis provides an equation for the
variable being explained. Several statistics which indicate the success of the regression analysis
fit are shown for each model. Several of these indicators are R2,Root Mean Squared Error,
Durbin-Watson Statistic, F-Statistic, and the T-Statistics of the Coefficient. PROC REG of SAS'
was used to estimate all regression models. PROC AUTOREG of SAS was used if significant
autocorrelation, as indicated by the Durbin-Watson statistic, was present in the model.
Two variables were used extensively in developing weather sensitive average use
models: heating degree days ("HDD")and cooling degree days("CDD"). The values for HDD
and CDD are the average of the values for Charleston and Columbia. The base for HDD was 60°
and for CDD was 75°. In order to account for cycle billing,the degree day values for each day
were weighted by the number of billing cycles which included that day for the current month's
billing. The daily weighted degree day values were summed to obtain monthly degree day
values. Billing sales for a calendar month may actually reflect consumption that occurred in the
previous month based on weather conditions in that period and also consumption occurring in the
current month. Therefore,this method more accurately reflects the impact of weather variations
on the consumption data.
The development of average use models began with plots of the HDD and CDD data
versus average use by month. This process led to the grouping of months with similar average
use patterns. Summer and winter groups were chosen,with the summer models including the
A-2

months of May through October, and the winter models including the months of November
through April. For each of the groups,an average use model was developed. Total usage
models were developed with a similar methodology for the municipal customers. For these
customers,HDD and CDD were weighted based on Cycle 20 distributions. This is the last
reading date for bills in any given month, and is generally used for larger customers.
Simple plots of average use-over time revealed significant changes in average use for
some customer groups. Three types of variables were used to measure the effect of time on
average use:
1. Number of months since a base period;
2. Dummy variable indicating before or after a specific point in time; and,
3. Dummy variable for a specific month or months.
Some models revealed a decreasing trend in average use,which is consistent with
conservation efforts and improvements in energy efficiency. However,other models showed an
increasing average use over time. This could be the result of larger houses, increasing appliance
saturations, lower real electricity prices, and/or higher real incomes.
ARIMA Models
Autoregressive integrated moving average ("ARIMA")procedures were used in
developing the short range forecasts. For various class/rate groups,they were used to develop
customer estimates,average use estimates,or total use estimates.
ARIMA procedures were developed for the analysis of time series data, i.e., sets of
observations generated sequentially in time. This Box-Jenkins approach is based on the
assumption that the behavior of a time series is due to one or more identifiable influences. This
method recognizes three effects that a particular observation may have on subsequent values in
the series:
A-3

1. A decaying effect leads to the inclusion of autoregressive (AR)terms;
2. A long-term or permanent effect leads to integrated (I)terms;and, •
3. A temporary or limited effect leads to moving average(MA)terms.
Seasonal effects may also be explained by adding additional terms of each type(AR, I, or MA).
The ARIMA procedure models the behavior of a variable that forms an equally spaced
time series with no missing values. The mathematical model is written:
Zt=u+Y; (B)X;,t + q(B)/f(B)at
This model expresses the data as a combination of past values of the random shocks and
past values of the other series, where:
t indexes time
B is the backshift operator,that is B (Xt)=Xt_1
Zt is the original data or a difference of the original data
f(B) is the autoregressive operator, f(B)= 1 —f1 B - ... - fl BP
u is the constant term
q(B) is the moving average operator, q(B)= 1 -qt B - ... -qq Bq
at is the independent disturbance, also called the random error
X;t is the ith input time series
y;(B) is the transfer function weights for the ith input series(modeled as a ratio of polynomials)
y;(B) is equal to w;(B)/d;(B), where w;(B)and d;(B)are polynomials in B.
The Box-Jenkins approach is most noted for its three-step iterative process of
identification, estimation,and diagnostic checking to determine the order of a time series. The
autocorrelation and partial autocorrelation functions are used to identify a tentative model for
univariate time series. This tentative model is estimated. After the tentative model has been
A-4

fitted to the data,various checks are performed to see if the model is appropriate. These checks
involve analysis of the residual series created by the estimation process and often lead to
refinements in the tentative model. The iterative process is repeated until a satisfactory model is
found.
Many computer packages perform this iterative analysis. PROC ARIMA of(SAS/ETS)2
was used in developing the ARIMA models contained herein. The attractiveness of ARIMA
models comes from data requirements. ARIMA models utilize data about past energy use or
customers to forecast future energy use or customers. Past history on energy use and customers
serves as a proxy for all the measures of factors underlying energy use and customers when other
variables were not available. Univariate ARIMA models were used to forecast average use or
total usage when weather-related variables did not significantly affect energy use or alternative
independent explanatory variables were not available.
Footnotes
1. SAS Institute, Inc., SAS/STATtm Guide for Personal Computers, Version 6 Edition.
Cary,NC: SAS Institute, Inc., 1987.
2. SAS Institute, Inc., SAS/ETS User's Guide, Version 6, First Edition. Cary,NC: SAS
Institute, Inc., 1988.
A-5

Electric Sales Assumptions
For short-term forecasting, over 30 forecasting groups were defined using the Company's
customer class and rate structures. Industrial (Class 30) Rate 23 was further divided using SIC
codes. In addition,twenty-eight large industrial customers were individually projected. The
residential class was disaggregated into several sub-groups, starting first with rate. Next, a
regression analysis was done to separate customers into two categories,"more weather-sensitive"
and"less weather sensitive". Generally speaking,the former group is associated with higher
average use per customer in winter months relative to the latter group. Finally,these categories
were divided by housing type(single family, multi-family, and mobile homes). Each municipal
account represents a forecasting group and was also individually forecast. Discussions were held
with Industrial Marketing and Economic Development representatives within the Company
regarding prospects for industrial expansions or new customers, and adjustments made to
customer,rate, or account projections where appropriate. Table 1 contains the definition for
each group and Table 2 identifies the methodology used and the values forecasted by forecasting
groups.
The forecast for Company Use is based on historic trends and adjusted for Summer 1
nuclear plant outages. Unaccounted energy, which is the difference between generation and
sales and represents for the most part system losses, is usually between 4-5%of total territorial
sales. The average annual loss for the three previous years was 4.6%, and this value was
assumed throughout the forecast. The monthly allocations for unaccounted use were based on a
regression model using normal total degree-days for the calendar month and total degree-days
weighted by cycle billing. Adding Company Use and unaccounted energy to monthly territorial
sales produces electric generation requirements.
A-6

TABLE 1
Short-Term Forecasting Groups
Class Rate/SIC
Number Class Name Designation Comment
10 Residential Less Weather- Single Family Rates 1,2, 5,6,8, 18,25,26,62,64
Sensitive Multi Family 67,68,69
910 Residential More Weather- Mobile Homes
Sensitive
20 Commercial Less Weather- Rate 9 Small General Service
Sensitive Rate 12 Churches
Rate 20,21 Medium General Service
Rate 22 Schools
Rate 24 Large General Service
Other Rates 3, 10, 11, 14, 16, 18,25,26
29,62,67,69
920 Commercial Space Heating Rate 9 small General Service
More Weather-
Sensitive
30 Industrial Non-Space Heating Rate 9 Small General Service
Rate 20,21 Medium General Service
Rate 23,SIC 22 Textile Mill Products
Rate 23,SIC 24 Lumber,Wood Products,Furniture and
Fixtures(SIC Codes 24 and 25)
Rate 23, SIC 26 Paper and Allied Products
Rate 23,SIC 28 Chemical and Allied Products
Rate 23,SIC 30 Rubber and Miscellaneous Products
Rate 23,SIC 32 Stone,Clay,Glass,and Concrete
Rate 23, SIC 33 Primary Metal Industries;Fabricated Metal
Products;Machinery; Electric and
Electronic Machinery,Equipment and
Supplies;and Transportation Equipment
(SIC Codes 33-37)
Rate 23,SIC 99 Other or Unknown SIC Code*
Rate 27,60 Large General Service
Other Rates 18,25,and 26
60 Street Lighting Rates 3,9, 13, 17, 18,25,26,29,and 69
70 Other Public Authority Rates 3,9,20,21,25,26,29,65 and 66
92 Municipal Rate 60,61 Three Individual Accounts
*Includes small industrial customers from all SIC classifications that were not previously forecasted
individually. Industrial Rate 23 also includes Rate 24. Commercial Rate 24 also includes Rate 23.

TABLE 2
Summary of Methodologies Used To Produce
The Short Range Forecast
Value Forecasted Methodology Forecasting Groups
Average Use Regression Class 10,All Groups
Class 910,All Groups
Class 20,Rates 9, 12,20,22,24,99
Class 920,Rate 9
Class 70,Rate 3
Total Usage ARIMA/ Class 30,Rates 9,20,99,and 23,
Regression for SIC=91 and 99
Class 930,Rate 9
Class 60
Class 70,Rates 65,66
Regression Class 92,All Accounts
Class 97,One Account
Customers ARIMA Class 10,All Groups
Class 910,All Groups
Class 20,All Rates
Class 920,Rate 9
Class 30,All Rates Except 60,99,and 23
for SIC=22,24,26,28,30,32,33,and 91
Class 930,Rate 9
Class 60
Class 70,Rate 3

Appendix B

Long Range Sales Forecast
Electric Sales Forecast
This section presents the development of the long-range electric sales forecast for the
Company. The long-range electric sales forecast was developed for six classes of service:
residential,commercial,industrial, street lighting,other public authorities,and municipals. These
classes were disaggregated into appropriate subgroups where data was available and there were
notable differences in the data patterns. The residential,commercial,and industrial classes are
considered the major classes of service and account for over 93%of total territorial sales. A
customer forecast was developed for each major class of service. For the residential class,forecasts
were also produced for those customers categorized into two groups,more and less weather-
sensitive. They were further disaggregated into housing types of single family,multi-family and
mobile homes. In addition,two residential classes and residential street lighting were evaluated
separately. These subgroups were chosen based on available data and differences in the average
usage levels and/or data patterns. The industrial class was disaggregated into two digit SIC code
classification for the large general service customers,while smaller industrial customers were
grouped into an"other"category. These subgroups were chosen to account for the differences in
the industrial mix in the service territory. With the exception of the residential group,the forecast
for sales was estimated based on total usage in that class of service. The number of residential
customers and average usage per customer were estimated separately and total sales were calculated
as a product of the two.
The forecast for each class of service was developed utilizing an econometric approach.
The structure of the econometric model was based upon the relationship between the variable to be
forecasted and the economic environment,weather,conservation,and/or price.
B-1

Forecast Methodology
Development of the models for long-term forecasting was econometric in approach and used
the technique of regression analysis. Regression analysis is a method of developing an equation
which relates one variable, such as sales or customers,to one or more other variables that are
statistically correlated with the first,such as weather,personal income or population growth.
Generally,the goal is to find the combination of explanatory variables producing the smallest error
between the historic actual values and those estimated by the regression. The output of the
regression analysis provides an equation for the variable being explained. In the equation,the
variable being explained equals the sum of the explanatory variables each multiplied by an
estimated coefficient. Various statistics,which indicate the success of the regression analysis fit,
were used to evaluate each model. The indicators were R2,mean squared Error of the Regression,
Durbin-Watson Statistic and the T-Statistics of the Coefficient. PROC REG and PROC
AUTOREG of SAS were used to estimate all regression models. PROC REG was used for
preliminary model specification,elimination of insignificant variables,and also for the final model
specifications. Model development also included residual analysis for incorporating dummy
variables and an analysis of how well the models fit the historical data,plus checks for any
statistical problems such as autocorrelation or multicollinearity. PROC AUTOREG was used if
autocorrelation was present as indicated by the Durbin-Watson statistic.
Prior to developing the long-range models,certain design decisions were made:
• The multiplicative or double log model form was chosen. This form allows forecasting
based on growth rates, since elasticities with respect to each explanatory variable are given
directly by their respective regression coefficients. Elasticity explains the responsiveness of
changes in one variable(e.g. sales)to changes in any other variable(e.g.price). Thus,the
elasticity coefficient can be applied to the forecasted growth rate of the explanatory variable
B-2

to obtain a forecasted growth rate for a dependent variable. These projected growth rates
were then applied to the last year of the short range forecast to obtain the forecast level for
customers or sales for the long range forecast. This is a constant elasticity model,therefore,
it is important to evaluate the reasonableness of the model coefficients.
• One way to incorporate conservation effects on electricity is through real prices or time
trend variables. Models selected for the major classes would include these variables, if they
were statistically significant.
• The remaining variables to be included in the models for the major classes would come
from four categories:
1. Demographic variables-Population.
2. Measures of economic well-being or activity: real personal income,real per capita
income,employment variables,and industrial production indices.
3. Weather variables-average summer/winter temperature or heating and cooling degree-
days.
4. Variables identified throughresidual analysis or knowledge of political
changes,major
economics events,etc. (e.g.,the gas price spike in 2005 attributable to Hurricane Katrina
and recession versus non-recession years).
Standard statistical procedures were used to obtain preliminary specifications for the
models. Model parameters were then estimated using historical data and competitive models were
evaluated on the basis of:
• Residual analysis and traditional "goodness of fit"measures to determine how well these
models fit the historical data and whether there were any statistical problems such as
autocorrelation or multicollinearity.
• An examination of the model results for the most recently completed full year.
B-3

• An analysis of the reasonableness of the long-term trend generated by the models. The
major criteria here was the presence of any obvious problems,such as the forecasts
exceeding all rational expectations based on historical trends and current industry
expectations.
• An analysis of the reasonableness of the elasticity coefficient for each explanatory variable.
Over the years a host of studies have been conducted on various elasticities relating to
electricity sales. Therefore,one check was to see if the estimated coefficients from
Company models were in-line with others. As a result of the evaluative procedure,final
models were obtained for each class.
• The drivers for the long-range electric forecast included the following variables.
Service Area Housing Starts
Service Area Real Per Capita Income
Service Area Real Personal Income
State Industrial Production Indices
Real Price of Electricity
Average Summer Temperature
Average Winter Temperature
Heating Degree Days
Cooling Degree Days
The service area data included Richland, Lexington,Berkeley,Dorchester,Charleston,
Aiken and Beaufort counties,which account for the vast majority of total territorial electric sales.
Service area historic data and projections were used for all classes with the exception of the
industrial class. Industrial productions indices were only available on a statewide basis,so
forecasting relationships were developed using that data. Since industry patterns are generally
B-4

. based on regional and national economic patterns,this linking of Company industrial sales to a
larger geographic index was appropriate.
Economic Assumptions
In order to generate the electric sales forecast,forecasts must be available for the
independent variables. The forecasts for the economic and demographic variables were obtained
from Global Insight,Inc.and the forecasts for the price and weather variables were based on
historical data. The trend projection developed by Global Insight is characterized by slow,steady
growth,representing the mean of all possible paths that the economy could follow if subject to no
major disruptions, such as substantial oil price shocks,untoward swings in policy, or excessively
rapid increases in demand.
Average summer temperature or CDD(Average of June,July,and August temperature)and
average winter temperature or HDD(Average of December(previous year),January and February
temperature)were assumed to be equal to the normal values used in the short range forecast.
After the trend econometric forecasts were completed,reductions were made to account for
higher air-conditioning efficiencies,DSM programs,and the replacement of incandescent light
bulbs with more efficient CFL or LED light bulbs. Industrial sales were increased if new customers
are anticipated or if there are expansions among existing customers not contained in the short-term
projections.
Peak Demand Forecast
This section describes the procedures used to create the long-range summer and winter peak
demand forecasts. It also describes the methodology used to forecast monthly peak demands.
Development of summer peak demands will be discussed initially,followed by the construction of
winter peaks.
B-5

Summer Peak Demand
The forecast of summer peak demands was developed with a load factor methodology. This
methodology may be characterized as a building-block approach because class, rate,and some
individual customer peaks are separately determined and then summed to derive the territorial peak.
Briefly,the following steps were used to develop the summer peak demand projections.
Load factors for selected classes and rates were first calculated from historical data and then used to
estimate peak demands from the projected energy consumption among these categories. Next,
planning peaks were determined for a number of large industrial customers. The demands of these
customers were forecasted individually. Summing these class,rate,and individual customer
demands provided the forecast of summer territorial peak demand. Next, savings identified from
SCE&G's demand-side management programs were removed. Finally,the incremental reductions
in demand resulting from the Company's standby generator and interruptible programs were
subtracted from the peak demand forecast. This calculation gave the firm summer territorial peak
demand,which was used for planning purposes.
Load Factor Development
As mentioned above, load factors are required to calculate KW demands from KWH energy.
This can be seen from the following equation,which shows the relationship between annual load
factors,energy,and demand:
Load Factor=Energy/(Demand x 8760)
The load factor is thus seen to be a ratio of total energy consumption relative to what it
might have been if the customer had maintained demand at its peak level throughout the year. The
value of a system coincident load factor will usually range between 0 and 1,with lower values
indicating more variation in a customer's consumption patterns,as typified by residential users with
B-6

relatively large space-conditioning loads. Conversely,higher values result from more level demand
patterns throughout the year,such as those seen in the industrial sector.
Rearrangement of the above equation makes it possible to calculate peak demand,given
energy and a corresponding load factor. This form of the equation is used to project peak demand
herein. The question then becomes one of determining an appropriate load factor to apply to
projected energy sales.
The load factors used for the peak demand forecast were not based on one-hour coincident
peaks. Instead, it was determined that use of a 4-hour average class peak was more appropriate for
forecasting purposes. This was true for two primary reasons. First,analysis of territorial peaks
showed that all of the summer peaks had occurred between the hours of 2 and 6 PM. However,the
distribution of these peaks between those four hours was fairly evenly spread. It was thus
concluded that while the annual peak would occur during the 4-hour band, it would not be possible
to say with a high degree of confidence during which hour it would happen.
Second,the coincident peak demand of the residential and commercial classes depended on
the hour of the peak's occurrence. This was due to the former tending to increase over the 4-hour
band,while the latter declined. Thus, load factors based on peaks occurring at,say,2 PM,would be
quite different from those developed for a 5 PM peak. It should also be noted that the class
contribution to peak is quite stable for groups other than residential and commercial. This means
that the 4-hour average class demand,for say,municipals,was within 2%of the 1-hour coincident
peak. Consequently,since the hourly probability of occurrence was roughly equal for peak demand,
it was decided that a 4-hour average demand was most appropriate for forecasting purposes.
The effect of system line losses were embedded into the class load factors so they could be
applied directly to customer level sales and produce generation level demands. This was a
convenient way of incorporating line losses into the peak demand projections.
B-7

Energy Projections
For those categories whose peak demand was to be projected from KWH sales,the next
requirement was a forecast of applicable sales on an annual basis. These projections were utilized
in the peak demand forecast construction. In addition,street light sales were excluded from forecast
sales levels when required,since there is no contribution to peak demand from this type of sale.
Combining load factors and energy sales resulted in a preliminary,or unadjusted peak
demand forecast by class and/or rate. The large industrial customers whose peak demands were
developed separately were also added to this forecast.
Derivation of the planning peak required that the impact of demand reduction programs be
subtracted from the unadjusted peak demand forecast. This is true because the capacity expansion
plan is sized to meet the firm peak demand,which includes the reductions attributable to such
programs.
Winter Peak Demand
To project winter peaks actual winter peak demands were correlated with three primary
explanatory factors: total territorial energy,customers,and weather during the day of the winter
peak's occurrence. Other dummy variables were also included in the model to account for unusual
events,such as recessions or extremely cold winters. •
The logic behind the choice of these variables as determinants of winter peak demand is
straightforward. Over time,growth in total territorial load is correlated with economic growth and
activity in SCE&G's service area,and as such may be used as a proxy variable for those economic
factors,which cause winter peak demand to change. It should be noted that the winter peak for any
given year by industry convention is defined as occurring after the summer peak for that year. The
winter period for each year is December of that year,along with January and February of the
following year. For example,the winter peak in 1968 of 962 MW occurred on December 11, 1968,
B-8

while the winter peak for 1969 of 1,126 MW took place on January 8, 1970. In addition to
economic factors,weather also causes winter peak demand to fluctuate, so the impact of this
element was measured by two variables: the average of heating degree days(HDD)experienced on
the winter peak day in Columbia and Charleston and the minimum temperature on the peak day.
The presence of a weather variable reduces the bias which would exist in the other explanatory
variables'coefficients if weather were excluded from the regression model,given that the weather
variable should be included. When the actual forecast of winter peak demand was calculated,the
normal value of heating degree-days over the sample period was used. Although the ratio of winter
to summer peak demands fluctuated over the sample period, it did show an increase over time. A
primary cause for this increasing ratio was growth in the number of electric space heating
customers. Due to the introduction and rapid acceptance of heat pumps over the past three decades,
space-heating residential customers increased from less than 5,000 in 1965 to almost 217,000 in
2004,a 10.2%annual growth rate. However,this growth slowed dramatically in the 1990's,so the
expectation is that the ratio of summer to winter peaks will change slowly in the future.
B-9

Attachment E
Santee Cooper Press Release
(November 19, 2013)

5/5/2015 https://www.santeecooper.com/about-santee-cooper/news-releases/news-items/santee-cooper-announces-plans-to-recycle-ash-for-beneficial-use.aspx
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santee cooper 111
RESIDENTIAL BUSINESS COMMITTED to SOUTH CAROLINA ABOUT SANTEE COOPER
Home>About Santee Cooper>News Releases E
Leadership
Santee Cooper announces plans to recycle ash for
Investors
beneficial use
Communications
Newsroom
Energy Matters Santee Cooper announced today plans to use all of the ash in ponds at its Jefferies, Winyah
and Grainger generating stations for beneficial purposes. Beneficial use provides economic,
environmental and customer benefits.
Santee Cooper has recycled fly ash, bottom ash and gypsum since the 1970s. Prior to the
recent recession, Santee Cooper was using about 90 percent of those materials for beneficial
purposes. Its gypsum recycling program actually brought American Gypsum and about 100
new jobs to Georgetown County in 2008, where that company makes wallboard. The utility's
ash is used by the cement and concrete block industries and has helped build projects
including Charleston's Ravenel Bridge.
Santee Cooper has worked to recycle as much of its ash as possible through the decades.
EPA regulations spurring the closure of coal-fired generating stations around the country have
resulted in greater demand for ash and the development of new technology that increases the
viability of pond ash.
"As we continue working to close units at Jefferies and Grainger and consider long-term
needs for Winyah, Santee Cooper is focused on solutions that are cost-effective and
beneficial to the environment and the economy," said R.M. Singletary, executive vice
president of corporate services. "This is a triple win. It is cost-effective, which means it is
responsive to our customers' best interests. It utilizes innovative technology to help an
important South Carolina industry be sustainable. And it is an EPA-approved use of ash."
"This plan also addresses comments by our neighbors, the City of Conway, and DHEC about
long-term placement of the ash, and it does so in a manner that is responsible to customers,"
Singletary added. "It's a solution that really does have something favorable for all involved."
The plans announced today will empty the ash ponds at the three stations over the next 10 to
15 years. Santee Cooper will provide excavation, loading and transportation of the ash to the
plants where it will be used.
Santee Cooper is South Carolina's largest power producer, the largest Green Power
generator and the ultimate source of electricity for 2 million people across the state. Through
its low-cost, reliable and environmentally responsible electricity and water services, and
through innovative partnerships and initiatives that attract and retain industry and jobs, Santee
Cooper powers South Carolina. To learn more, visit www.santeecooper.com
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Attachment F
Grainger Generating Station
Ash Pond Closure: Ash Removal Report
(January-December 2014)

Santee cooper
FEDEX
January 14, 2015
Jeffrey P. deBessonet, Director
South Carolina Department of Health
and Environmental Control
Water Facilities Permitting Division
2600 Bull Street
Columbia, South Carolina 29201
RE: Grainger Generating Station
Ash Pond Closure: Ash Removal Report
Santee Cooper's annual closure plan states that Santee Cooper will provide status
reports to DHEC every six months regarding the amount of ash and underlying soil
removed from Grainger Generating Station.
Removal of ash for beneficial use began at Grainger on March 17, 2014. The following
table provides tons of ash and soil removed for 2014.
Yea" ¢, ' 'i:Mointh- • Ash(tains) .' r oil(t "sj:
2014 January 0 0
2014 February 0 0
2014 March 4,700 0
2014 April 6,018 0
2014 May 11,906 0
2014 June 20,264 0
2014 July 14,886 0
2014 August 19,711 0
2014 September 25,862 0
2014 October 25,453 0
2014 November 23,022 0
2014 December 12,894 0
Onc Ri'.rvocJ Drive I Monk;Corner.SC 291G1-2901 I (84;1)761-8000 I P.O.Box 2946101 I Moncks Corner,SC 29461-6101

Jeffrey P. deBessonet, Director
SCDHEC
January 14, 2015
Page 2
Sincerely,
Thomas L. Kiersp ,
Vice President
Environmental, Property and Water Systems Management
TLK:SI :A9,t ;cgb
cc: Frank Holleman
T

pc
34
Attachment G
W.S. Lee Steam Station
Settlement Agreement
(April 23, 2015)
4.:• t - Jct. k LAJMARPArl,d VISA.iribt)'Z'ALni

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
3

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

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
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.
6

(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. Warranty of 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
8

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 persons 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
9

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 1 s day of Awn 1,Leis by:
DUKE :GY CAR IN , LC
i
By.
•. Lt..sYSFL f
1 nior Vise President,Ash Basin Str4tegv
II

a . .
•
•4
.
• u :M:' A
• - ...-1?:::-:...•.. '''' W. • .. '•...,:...._." .:
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• Executed this S day of Aril_by:
SAVE OUR SALUD 4
By: V\ I
Its:
pre..s., cLJ- , S&.i OL)/ JQ_t LCk
13

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` Secondary Ash Pond _ ,---..t,
�i4�d I''±~
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Area
Structural Fill f '
}
r3 .`,i Inactive Ash Basin
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" Ash Fill
"'� Area

tDUKE CONFIDENTIAL
ENERGY.
David B.Fountain
Senior Vice President
Enterprise Legal Support
Duke Energy
411 Fayetteville Street,NC20
Raleigh,NC 27601
919-546-6164
September 23, 2014
Mr. Frank Holleman
Southern Environmental Law Center
601 West Rosemary Street, Suite 220
Chapel Hill, NC 27516-2356
Dear Mr. Holleman:
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 Fill 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).

Mr. Frank Holleman
September 23, 2014 CONFIDENTIAL
Page 2
• 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 Fill 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,
e •1:56—
David B. Fountain
Senior Vice President,Enterprise Legal Support
On behalf of Duke Energy
Attachment

Mr. Frank Holleman
September 23,2014 CONFIDENTIAL
Page 3
We Agree:
I
iNeY- L.01.4
F leman
Senior Attorney,Southern Environmental Law Center
On Behalf of Upstate Forever and Save Our Saluda

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

V
THE STATE OF SOUTH CAROLINA
BEFORE THE DEPARTMENT OF HEALTH AND ENVIRONMENTAL CONTROL
1N 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

I
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.
' I
2

I
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

V
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

I
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

f
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
9

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

I
FOR THE SOUTH CAROLINA DEPARTMENT
OF HEALTH AND ENVIRONMENTAL CONTROL
iLja L__../2_s Date: ! 1.29 11 x"
Elizabeth-N.Dieck
Director of Environmental Affairs
Date: /.zq
Daphne G. e ,Chief
Bureau of Land and Waste Management
Gam.+ Date:
Q'?f'4`4
Van Keisler,P. .,Director
Division of Compliance and Enforcement
Reviewed By:
.0 , C1, /e4 Date: IA 1/i 40
Attorney
Office of General Counsel
WE CONSENT:
DUKE ENERGY CAROLINA,LLC
'/
/� Y
Date: 7/zs/
i ture)
John Elnitsky,Senior Vice President,Ash Basin Strategy
(Please clearly print name and title)
11

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40.1% '� UNITED STATES ENVIRONMENTAL.PROTECTION AGENCY
VZNksil Y WASHINGTON,D.C. 20460
41 pAto.
JUN 7 2010
OFFICE OF
WATER
MEMORANDUM
SUBJECT: National Pollutant Discharge Elimination System(NPDES)Permitting of
Wastewater Discharges from Flue Gas Desulfurization(FGD)and Coal
Combustion Residuals(CCR)Impoundments at Steam Electric Power
Plants
FROM: James A. Hanlon, Direct
Office of Wastewater anage t
TO: Water Division Directors egions 1 - 1 0
The purpose of this memorandum is to provide you with interim guidance to
assist National Pollutant Discharge Elimination System(NPDES)permitting authorities
establish appropriate permit requirements for wastewater discharges from Flue Gas
Desulfurization(FGD)systems and coal combustion residual(CCR)impoundments at
Steam Electric Power Plants.
In October 2009,the Environmental Protection Agency(EPA) completed a study
of wastewater discharges from the steam electric power generating industry. EPA's
Office of Water evaluated wastewater characteristics and treatment technologies,
focusing to a large extent on wastewater from flue gas desulfurization(FGD)air
pollution control systems and CCR impoundments because these sources comprise a
significant fraction of the pollutants discharged by steam electric power plants.' Based
on this study,EPA decided to begin a rulemaking to address pollutants and wastestreams
not covered by existing Effluent Limitations Guidelines(40 CFR Part 423).2 EPA
expects to complete this rulemaking and promulgate revised effluent guidelines in late
2013. The attached technology-based permitting guidance(Attachment A)provides State
and EPA permitting authorities with information on how to establish technology-based
effluent limits for flue gas desulfurization(FGD)wastewater at steam electric facilities in
NPDES permits issued between now and the effective date of revised effluent guidelines.
l U.S.EPA.Steam Electric Power Generating Point Source Category:Final Derailed Study Report(EPA
821-R-09-008).October 2009,Available at http://epa.gov/waterscience/guide/steam/finalreport.pdf.
2 The Steam Electric Power Generating effluent limitations guidelines and standards(referred to in this
report as"effluent guidelines")apply to a subset of the electric power industry,namely those plants
"primarily engaged in the generation of electricity for distribution and sale which results primarily from a
process utilizing fossil-type fuel(coal,oil,or gas)or nuclear fuel in conjunction with a thermal cycle
employing the steam water system as the thermodynamic medium."The effluent guidelines are codified in
the Code of Federal Regulations(CFR)at Title 40,Part 423(40 CFR Part 423).
interne!Address(URL)• http://www.spe.gov
RecyeledlReeycleble•Printed with Vegetable OH Based Inks on 1009E Postconsumer,Process Chlorine Free Recycled Paper

In December 2008,an impoundment failure released 5.4 million cubic yards of
coal ash at the Tennessee Valley Authority's(TVA)Kingston Fossil Plant in Tennessee
and a subsequent release at TVA's Widow Creek Fossil Plant in Alabama brought CCR
storage and disposal into the national spotlight. These spills,as well as others that have
occurred,highlight an area that has received little attention in the NPDES program and
made us aware of the need to better protect water quality and human health from
impoundment discharges. In response to the TVA spills,we also examined existing
discharges from impoundments that manage CCRs and found that they have a potential to
impact water quality. Many NPDES permits do not fully address water quality impacts
of the discharges,and some pollutants of concern are not required to be reported in
current permit applications. A detailed description of the reasonable potential analysis
and development of limits necessary to ensure compliance with applicable water quality
standards is an important component of all NPDES permit Fact Sheets. While a detailed
and well documented reasonable potential analysis helps to demonstrate that permits are
consistent with the requirements of State and Federal law,it also makes the permitting
process transparent to the regulated community and the public. The attached water
quality permitting guidance(Attachment B)is intended to assist State and EPA
permitting authorities to better address water quality impacts associated with discharges
from impoundments that manage CCRs.
The establishment of appropriate NPDES permitting requirements for these
discharges is an important effort to better protect the environment and human health.
You should work with authorized state programs to encourage them to utilize this
guidance in their permit decision making process. In cases where State permitting
authorities do not consider the attached guidance in developing permit conditions,you
should work with the States to make appropriate changes. After working with States you
should consider using objection authorities in cases where permits do not address
appropriate technology-based or water quality-based permit limits to address FGD or
CCR discharges consistent with 40 CFR 122.44. In accordance with the principles of
good guidance,the public can provide comments to EPA for the Agency's benefit and
consideration.
If you have questions concerning this memorandum or the permit language,
please contact Linda Boornazian,Director of the Water Permits Division,at 202-564-
0221 or have your staff contact Scott Wilson of the Industrial Permit Branch at 202-564-
6087 or Wilson jsQepa.gov.
cc: NPDES Branch Chiefs Regions 1 - 10
Attachments
2

r
Attachment B
Water Quality-Based Effluent Limits
Coal Combustion Waste Impoundments
I. Background
Recent Coal Combustion Residual Impoundment Spills
On December 22,2008,a coal combustion residual (CCR)ash impoundment dam
collapsed at the TVA Fossil plant located at Kingston, Tennessee. The breach released 5.4
million cubic yards of coal combustion residuals into tributaries of the Tennessee River,the
Clinch and Emory Rivers,as well as surrounding areas. A second incident at a CCR
impoundment at the TVA Widows Creek plant on January 9, 2009,added further attention to this
issue. At 10,000 gallons,that second spill was dwarfed by the Kingston spill; however,the two
incidents,as well as others that have occurred,highlighted the need for better management of
CCR impoundments and the potential water quality impacts associated with the discharges. This
document discusses potential water quality impacts associated with discharges from CCR
impoundments and provides guidance on the methods to control them through water quality
analysis and permit conditions.
Waste Streams and Wastewater Discharges
The Steam Electric Power Generating Category Effluent Limitations Guidelines(ELGs)
found at 40 CFR Part 423 contain technology-based limits for most wastewater streams expected
at facilities subject to that guideline. The ELGs apply to discharges from generating units
located at establishments primarily engaged in the generation of electrical power for distribution
and sale. The ELGs do not address discharges from steam electric generating units at facilities
that are not primarily engaged in the production of electricity for distribution or sale. Steam
electric facilities not covered by the ELGs typically supply electricity to industrial facilities such
as paper mills. The waste streams discharged by either type of coal-fired steam electric plant
include: fly ash and bottom ash transport water, metal cleaning wastes,once through cooling
water, cooling tower blowdown,coal pile runoff,and low volume waste(a broadly-defined term
that includes wastes such as boiler feedwater treatment waste water and flue gas desulfurization
(FGD)wastewater). Discharges from both types of coal fired steam electric facilities are
covered by this guidance. This guidance does not address other process related pollutants that
are discharged from the industrial generating facilities described above. For those industrial
facilities,permit writers must examine the specific process related waste streams and determine
the need for permit limits applicable to the industry being regulated.
Treatment of wastewater at coal fired steam electric facilities varies significantly from
plant to plant. Coal pile runoff is typically treated in settling ponds and is often segregated from
other waste streams. In addition to fly ash and/or bottom ash,ash ponds often contain comingled
wastes such as cooling tower blowdown, metal cleaning wastes, coal pile runoff, and low volume
waste(including treated or untreated FGD wastewater).

Point Source Discharges of Seepage
In addition to traditional coal combustion effluent discharges, facilities with combustion
waste impoundments are likely to discharge wastewater via seepage. Seepage can be collected
via seepage interception systems that may be built into impoundments and are intended to
manage seepage and prevent internal erosion of the structure. Wastewater from these systems is
either pumped back into the impoundment or discharged. If the seepage is discharged directly to
waters of the U.S., it is likely discharged via a discrete conveyance and thus is a point source
discharge. Seepage discharges are expected to be relatively minor in volume compared to other
discharges at a facility and could be inadvertently overlooked by permitting authorities.
Although little data are available,seepage consists of CCRs including fly ash and bottom ash
transport water and FGD wastewater and is likely to contain the same pollutants found in bottom
ash and fly ash transport water and FGD wastewater. If seepage is discharged directly via a
point source to a water of the U.S.,the discharge must be addressed under the NPDES permit for
the facility.
Permitting authorities will need to conduct a reasonable potential analysis and develop
appropriate permit limits and other conditions similar to discharges from the ash pond and other
sources at the facility as discussed below. Seepage discharges to surface water through a shallow
ground water hydrologic connection have been controlled in a number of cases through NPDES
permit requirements to either use lined impoundments to prevent seepage or to install seepage
interception systems. Permitting authorities should examine the need for these types of
requirements for hydrologically connected discharges that cannot be regulated through
traditional NPDES outfalls. If effluent pollutant data for point source discharges of seepage are
not included in the permit application,permitting authorities will need to request information
from permittees.
II. Pollutants Present in CCR Impoundments
Application reporting requirements
The current NPDES application form 2C requires permittees to submit data for metals,
GC/MS volatile and acid fraction compounds, and other parameters, such as nitrogen compounds
that could be present in coal combustion effluent. Permittees typically submit this required data
once every five years when they apply for permit renewal. For most parameters only one sample
is collected and analyzed. However,permittees are required to provide daily maximum, monthly
average and long term average data in the application for pollutants required to be monitored in
the permit. Long term monitoring data for CCR discharges are required for pollutants including
Total Suspended Solids(TSS)and Oil and Grease,which are limited by the ELG. Other long
term monitoring data are required in the application if water quality based limits and/or
monitoring requirements were included in the previous permit.
2

Effluent data
Effluent data shown below in Appendix A were collected by EPA as part of the ELG
detailed study of steam electric plants. EPA began a detailed review of steam electric facilities
in 2005 as a result of the Clean Water Act section 304(m)review process.
Effluent Variability and Pollutants of Concern
As shown below in Appendix A, effluent pollutant concentrations vary significantly
between dischargers. The pollutant concentration variability is the result of factors such as the
type of coal used. Note that none of the plants listed in Table 1 utilizes air emissions controls
specific for mercury. Implementation of additional emissions controls for mercury or other
pollutants would likely result in increased concentrations of those pollutants in CCR and the
associated discharges. The current degree of effluent variability and the increasing use of
emissions controls provide additional evidence supporting the need for permitting authorities to
require site specific effluent data as part of permit applications.
III. Water Quality Permitting Issues
Pollutants Potentially Exceeding Water Quality Criteria
Appendix A shows that metals in CCR effluent are variable and have the potential to
exist in relatively high concentrations. For reference, selected national recommended water
quality criteria are shown in Appendix A. Based on information presented in Table 1,the
following pollutants may be expected to be found in CCR effluent at concentrations that are
greater than water quality criteria: Aluminum, Arsenic, Cadmium, Chromium, Copper, Iron,
Manganese,Nickel, Selenium, Thallium, Chloride,and Nitrate/Nitrite. Barium,Lead, Mercury,
and Silver also can exceed water quality criteria as measured at internal outfalls;however, due to
dilution received through mixing the CCR waste stream with other effluents,they do not appear
to exceed the criteria at the final outfall. Although water quality criteria were shown to be
exceeded,the reasonable potential for a discharge to cause or contribute to an excursion of
applicable Water Quality Standards in the receiving water will depend on site-specific
conditions,the amount of in-stream dilution available, and the in-stream ambient pollutant
concentration,as discussed below. While this comparison does not indicate that there is
reasonable potential to exceed applicable water quality standards for each such discharge, it does
demonstrate the need to collect data required by the application form 2C and to conduct a
reasonable potential analysis for such discharges and establish water quality-based effluent limits
where appropriate.
Other parameters shown in Table 1, such as Total Dissolved Solids and Sulfate are
present in concentrations which could potentially cause or contribute to water quality impacts.
Those parameters are not required to be monitored for the permit application Form 2C. Many
states have not established numeric water quality criteria for parameters such as Total Dissolved
Solids or Sulfate. Permit writers should be aware of this potential impact on the achievement of
applicable narrative water quality criteria and may need to require that effluent data are
submitted so that such impacts can be appropriately addressed by the permit. While permitting
3

authorities have the option of requiring monitoring in the permit to obtain such data, it is
preferable to request the information during the permit reissuance process. In cases where the
reissued permit requires data to be collected, actions to address impairments may be
unnecessarily delayed until the subsequent permit is issued. In cases where the previous permit
did not require whole effluent toxicity testing,the permitting authority should consider
requesting that data also be submitted with the application.
Determining the Need for Water Quality Based Permit Limits
Permitting authorities need to examine the impacts of a discharge relative to both
numeric and narrative criteria. Most States have adopted implementation guidance to address the
reasonable potential(RP)for a discharge to cause or contribute to an exceedance of numeric
criteria. That guidance includes statistical tools and methods for permit writers to determine the
RP for a discharge to exceed Water Quality Standards(WQS). A reasonable potential
determination as to whether a discharge causes or contributes to an excursion of applicable water
quality criteria is required for every discharge(see 40 CFR 122.44(d)).
Most State permitting authorities derived their specific implementation plan for
determining RP and establishing water quality based permit limits using EPA's Technical
Support Document for Water Quality Based Toxics Control(TSD) (EPA 1991). In general, RP
analysis compares the reasonable maximum in-stream pollutant concentration with water quality
criteria to determine the need for effluent limits.
An initial part of the RP process is the determination of available in-stream dilution.
Methods used to determine dilution in the mixing zone vary by state and are prescribed by WQS
and the State's mixing zone policy.
Using the available dilution,permitting authorities make a statistical comparison of in-
stream effluent pollutant concentrations after mixing and water quality criteria to determine
whether there is a reasonable potential to exceed the criteria. This is typically done by
comparing the calculated 95th or 99th percentile of the effluent data with criteria. The TSD
includes methodology that can be used to conduct that analysis and to derive the resulting permit
limits.
Examination of the potential for a discharge to exceed the narrative criteria is a more
difficult task that is complicated by a lack of clearly prescribed implementation guidance. CCR
can contain fairly high concentrations of parameters that have the potential to impact water
quality, such as Total Dissolved Solids, Sulfate,and Calcium that can cause excursions of
narrative water quality standards. Since most states have not established numeric criteria for
those parameters, permit writers must rely on narrative criteria when addressing potential water
quality impacts. One tool states commonly use to address narrative criteria is whole effluent
toxicity (WET)monitoring and limits. Chronic WET testing,which include measurement of
sub-lethal effects of growth and fecundity, is used in most cases. However, in situations where a
discharge is made to a larger waterbody permitting authorities often require acute WET testing
based on an acute to chronic ratio. Most states have adopted procedures to determine which test
methods and species are used as part of their implementation plans. The TSD also includes
4

guidance that is intended to assist with implementation of water quality based permit limits.
WET testing measures the toxic effects of the complete mix of pollutants in a discharge and is a
useful tool for measuring the impacts to aquatic life. Permit writers also have the option of
requiring bioassessments to determine whether discharges are causing impacts and understand
the specific causes. Another option is for the permitting authority to target CCR discharges in
their stream surveillance activities and address impacts under the Total Maximum Daily Load
program. State stream assessment programs may also utilize other tools to analyze the water
quality of surface waters. State established tools that are used to translate narrative standards
based on numeric data may be useful to permit writers attempting to protect water quality.
Use of Ambient Pollutant Data
Permit limits that fully protect water quality cannot be developed without taking into
account the ambient pollutant concentration, also known as the background concentration.
However,permit writers typically do not have access to defensible ambient pollutant data. In the
absence of data,permit writers have often established water quality based permit limits using the
assumption that the background concentration is zero.
The equation used to calculate waste load allocations for water quality based limits
follows,as shown in the NPDES permit Writers Manual (EPA 1996)
(QdCd+QsCs)/Qr=Cr
Where:
Qd=waste discharge flow in million gallons per day (mgd) or cubic feet per second
(cfs)
Cd=pollutant concentration in waste discharge in milligrams per liter(mg/1)
Qs=background stream flow in mgd or cfs above point of discharge
Cs=background in-stream pollutant concentration in mg/1
Qr=resultant in-stream flow, after discharge in mgd or cfs
Cr=resultant in-stream pollutant concentration in mg/I in the stream reach(after
complete mixing occurs)
This equation or a variation thereof is used by permitting authorities as part of the process
to derive water quality based limits. If a value of zero is used for the ambient concentration for a
pollutant(Cs)in the equation,the permit writer would be able to establish a limit that would give
the entire pollutant allocation to the discharger. The resulting limit would not account for any
upstream discharges or any natural background concentration of the pollutant,and it would not
protect the Water Quality Standard. Since it is highly unlikely that the background concentration
is ever zero,the limit would not prevent an in-stream excursion of criteria.
Since it is not realistic to assume that the ambient pollutant concentration is zero,permit
writers must develop a method to adequately protect water quality. A number of options exist
for that task. Some states have adopted a policy of assuming that the ambient concentration is
equal to one half of the water quality criteria when no ambient data exist. While this is a
5

somewhat conservative approach,the permittee could be given the opportunity to collect data
during the comment period for the permit if they believed that the approach resulted in an overly
stringent limit. Other options available to the permitting authority include requiring submittal of
ambient data with permit applications,developing permit requirements to collect data,or
establishing default ambient concentrations using literature values. Any approach chosen by the
permitting authority to estimate background pollutant concentrations will result in more realistic
water quality based limits and improved compliance with state standards.
IV. Use of Sufficiently Sensitive Analytical Test Methods
The use of sufficiently sensitive analytical methods is critically important to detecting,
identifying and measuring the concentrations of pollutants in CCW wastestreams. For further
discussion of sufficiently sensitive methods, see Part V of Attachment A of this memo,and the
memo on Analytical Methods for Mercury in NPDES Permit, dated August 23,2007 in
Appendix C.
V. Disclaimer
This guidance document does not change or substitute for any legal requirements,though it
does provide clarification of some regulatory requirements. While EPA has made every effort to
ensure the accuracy of the discussion in this document,the obligations of the regulated community
are determined by the relevant statutes, regulations,or other legally binding requirements.This
guidance document is not legally enforceable and does not confer legal rights or impose legal
obligations upon any member of the public,EPA, states,or any other agency. In the event of a
conflict between the discussion in this document and any statute or regulation,this document would
not be controlling. The word"should"as used in this guidance document does not connote a
requirement, but does indicate EPA's strongly preferred approach to assure effective implementation
of legal requirements. This guidance may not apply in a particular situation based upon the
circumstances,and EPA, states and Tribes retain the discretion to adopt approaches on a case-by-
case basis that differ from the recommendations of this guidance document where appropriate.
Permitting authorities will make each permitting decision on a case-by-case basis and will be guided
by the applicable requirements of the CWA and implementing regulations,taking into account
comments and information presented at that time by interested persons regarding the appropriateness
of applying these recommendations to the particular situation. In addition,EPA may decide to revise
this guidance document to reflect changes in EPA's approach to implementing the regulations or to
clarify and update text.
VI. References
USEPA.2009.Steam Electric Power Generating Point Source Category: Final Detailed Study
Report. USEPA Engineering and Analysis Division, Office of Water. EPA 821-R-09-008.
Washington,DC. October, 2009.Available online at:
http://www.epa.gov/waterscience/guide/steam/finalreport.pdf
USEPA. 1996. USEPA NPDES Permit Writers Manual. USEPA Office of Water. EPA 833-B-
96-003. Washington, DC. December, 1996. Available online at:
http://cfpub.epa.gov/npdes/writermanual.cfm?program id=45
6

USEPA. 1991. Technical Support Document for Water Quality Based Toxics Control.USEPA
Office of Water Enforcement and Permits.Washington,DC.March, 1991. Available online at:
http://www.epa.gov/npdes/pubs/owm0264 pdf
7

Appendix A: Steam Electric 2007/2008 Detailed Study Report. Ash Pond Effluent Concentrations,USEPA 2009)
Analyte Method Unit Homer City-Effluent Widows Creek- Mitchell-Effluent Cardinal-
from Bottom Ash Effluent from from Fly Ash Pond. Effluent from Fly
Pond. Combined Ash Pond. Ash Pond..b
Routine Metals-Total
Aluminum 200.7 ugh 323 1,070 404 344
Antimony 200.7 ugh ND(20.0) ND(20.0) 24.6 21.2
Arsenic 200.7 ugh ND(10.0) 38.2 150 77.6
Barium 200.7 ugh 101 227 133 165
Beryllium 200.7 ugh ND(5.00) ND(5.00) ND(5.00) ND(5.00)
Boron 200.7 ugh 396 2,210 2,350 1,100
Cadmium 200.7 ugh ND(5.00) ND(5.00) ND(5.00) ND(5.00)
Calcium 200.7 ug/l 186,000 58,500 115,000 88,400
Chromium 200.7 ugh ND(10.0) 13.5 15.9 ND(10.0)
Cobalt 200.7 ugh ND(50.0) ND(50.0) ND(50.0) ND(50.0)
Copper 200.7 ugh ND(10.0) ND(10.0) ND(10.0) ND(10.0)
Iron 200.7 ugh 355 144 ND(100) ND(100)
Lead 200.7 ugh ND(50.0) ND(50.0) ND(50.0) ND(50.0)
Magnesium 200.7 ugh 31,800 6,680 21,000 17,900
Manganese 200.7 ugh 128 ND(15.0) ND(15.0) 64.7
Mercury 245.1 ugh ND(0.200) ND(0.200) ND(0.200) ND(0.200)
Molybdenum 200.7 ugh 19.7 143 359 361
Nickel 200.7 ugh ND(50.0) ND(50.0) ND(50.0) ND(50.0)
Selenium 200.7 ugh 6.02 16.2 177 44.5
Sodium 200.7 ugh 106,000 21,300 526,000 70,800
Thallium 200.7 ugh ND(10.0) ND(10.0) ND(10.0) ND(10.0)
Titanium 200.7 ugh ND(10.0) 14.5 ND(10.0) 12.6
Vanadium 200.7 ugh ND(20.0) 68.5 110 104
Yttrium 200.7 ugh ND(5.00) ND(5.00) ND(5.00) ND(5.00)
Zinc 200.7 ugh 21.6 ND(10.0) ND(10.0) ND(10.0)

Analyte Method Unit Homer City-Effluent Widows Creek- Mitchell-Effluent Cardinal-
from Bottom Ash Effluent from from Fly Ash Pond. Effluent from Fly
Pond. Combined Ash Pond. Ash Pond.,
Routine Metals-Dissolved
Aluminum 200.7 ugh 231 357 241 1301,
Antimony 200.7 ugh ND(20.0) ND(20.0) 23.9 20.9
Arsenic 200.7 ug/l ND(10.0) 30.1 138 74.6
Barium 200.7 ugh 106 206 128 157
Beryllium 200.7 ugh ND(5.00) ND(5.00) ND(5.00) ND(5.00)
Boron 200.7 ugh 397 2,200 2,290 1,090
Cadmium 200.7 ugh ND(5.00) ND(5.00) ND(5.00) ND(5.00)
Calcium 200.7 ugh 192,000 55,400 113,000 87,200
Chromium 200.7 ugh ND(10.0) 11.9 14.1 ND(10.0)
Hex.Chromium D1687-92 ug/1 ND(2.00) 12.0 7.00 <3.50
Cobalt 200.7 ugh ND(50.0) ND(50.0) ND(50.0) ND(50.0)
Copper 200.7 ugh ND(10.0) ND(10.0) ND(10.0) ND(10.0)
Iron 200.7 ugh 106 ND(100) ND(100) ND(100)
Lead 200.7 ugh ND(50.0) ND(50.0) ND(50.0) ND(50.0)
Magnesium 200.7 ugh 32,600 6,430 20,300 17,700
Manganese 200.7 ugh 129 ND(15.0) ND(15.0) 42.9
Mercury 245.1 ugh ND(0.200) ND(0.200) ND(0.200) ND(0.200)
Molybdenum 200.7 ug/1 20.2 136 330 352
Nickel 200.7 ugh ND(50.0) ND(50.0) ND(50.0) ND(50.0)
Selenium 200.7 ugh 6.10 1_ 15.3 162 43.8
Sodium 200.7 ugh 106,000 20,000 514,000 70,300
Thallium 200.7 ugh ND(10.0) ND(10.0) ND(10.0) ND(10.0)
Titanium 200.7 ugh ND(10.0) ND(10.0) ND(10.0) ND(10.0)
Vanadium 200.7 ugh ND(20.0) 64.7 108 99.9
Yttrium 200.7 ug/1 ND(5.00) ND(5.00) ND(5.00) ND(5.00)
Zinc 200.7 ugh 35.2 ND(10.0) ND(10.0) ND(I0.0)
9

Analyte Method Unit Homer City-Effluent Widows Creek- Mitchell-Effluent Cardinal-
from Bottom Ash Effluent from from Fly Ash Pond a Effluent from Fly
Pond. Combined Ash Pond a Ash Pond..b
Low-Level Metals-Total
Antimony 1638 ugh 1.09 4.39 25.8 21.9
Arsenic 1638 ugh 6.52 34.9 142 69.8
Cadmium 1638 ugh ND(0.500) ND(0.500) 1.32 1.14
Chromium 1638 ugh ND(4.00) 13.5 L 20.4 4.64 L
Copper 1638 ugh 2.37 1.49 5.47 2.98
Lead 1638 ugh ND(0.250) 0.490 0.580 0.420
Mercury 1631E ugh 0.00511 0.00157 0.00212 0.00125
Nickel 1638 ugh 10.7 ND(5.00) 11.0 10.7
Selenium 1638 ugh 5.74 17.1 191 45.8
Thallium 1638 ugh 1.32 1.46 1.72 2.84
Zinc 1638 ugh 24.2 ND(2.50) 10.1 5.98
Low-Level Metals-Dissolved
Antimony 1638 ug/1 0.990 4.45 22.5 22.4
Arsenic 1638 ugh 5.00 29.0 131 68.9
Cadmium 1638 ugh ND(0.500) ND(0.500) 1.17 1.11
Chromium 1638 ugh ND(4.00) 12.6 L 16.0 4.49 L
Hex.Chromium 1636 ugh 3.01 14.7 17.4 3.96
Copper 1638 ug/1 2.08 ND(1.00) 4.54 2.27
Lead 1638 ugh ND(0.250) ND(0.250) ND(0.250) ND(0.250)
Mercury 1631E ugh 0.00141 ND(0.000500) ND(0.000500) ND(0.000500)
Nickel 1638 ugh 10.4 ND(5.00) 9.57 10.6
Selenium 1638 ugh 5.16 15.6 161 45.0
Thallium 1638 ugh 1.31 1.49 1.42 2.87
Zinc 1638 ugh 15.0 ND(2.50) 9.51 4.15
10

Analyte Method Units Homer City— Widows Creek— Mitchell— Cardinal—
Effluent from Effluent from Effluent from Effluent from Fly
Bottom Ash Pond. Combined Ash Pond. Fly Ash Pond. Ash Pond.,s
Ammonia As Nitrogen(N}13-N) 4500-NH3F mg/I , 0.340 0.160 0.150 0.205
Nitrate/Nitrite(NO3-N+NO2-N) 353.2 mg/I 37.0 0.230 0.730 4.73 E
Total Kjeldahl Nitrogen(TKN) 4500-N,C mg/I 1.36 3.39 ND(0.100) <0.785 1,
Biochemical Oxygen Demand(BOD) 5210B mg/I ND(2.00) 4.00 2.00 ND(2.00)
Chloride 4500-CL-C mg/I 90.0 20.0 240 60.0
Hexane Extractable Material(HEM) 1664A mg/I ND(5.00) 6.00 ND(5.00) 10.0
Silica Gel Treated HEM(SGT-HEM) 1664A mg/I NA ND(5.00) NA ND(4.00)
Sulfate D516-90 mg/I 1,290 80.7 1,110 494
Total Dissolved Solids(TDS) 2540 C mg/I 1,250 281 2,050 673
Total Phosphorus 365.3 mg/I 1.09 0.250E 0.200 0.0870
Total Suspended Solids(TSS) 2540 D mg/I 5.00 12.0 E 15.0 6.00
Source:[ERG,20081;ERG,2008m;ERG,2008k;ERG,20080].
Note:EPA used several analytical methods to analyze for metals during the sampling program.For the purposes of sampling program,EPA designated some of
the analytical methods as"routine"and some of them as"low-level."EPA designated all of the methods that require the use of clean hands/dirty hands sample
collection techniques(i.e.,EPA Method 1669 sample collection techniques)as"low-level"methods.Note that although not required by the analytical method,
EPA used clean hands/dirty hands collection techniques for all low-level and routine metals samples.]
a—The concentrations presented have been rounded to three significant figures.
b—The ash pond effluent results represent the average of the ash pond effluent and the duplicate of the ash pond effluent analytical measurements.
<—Average result includes at least one non-detect value.(Calculation uses the report limit for non-detected results).
E—Sample analyzed outside holding time.
L—Sample result between 5x and 10x blank result.
NA—Not analyzed.
ND—Not detected(number in parenthesis is the report limit).The sampling episode reports for each of the individual plants contains additional sampling
information,including analytical results for analytes measured above the detection limit,but below the reporting limit(i.e.,J-values).
11

Appendix B: National Recommended Water Quality Criteria
EPA National Recommended Water Quality Criteria t
2006 National Recommended Water Quality Criteria
Freshwater Freshwater Human Human
Analyte Acute(ugh) Chronic Health (Water Health
(ug/1) +Organism) (Organism
(ugh) only) (ug/l)
Aluminum 750 87
Antimony 5.6 640
Arsenic 340 150 0.018 0.14
Barium 1000
Cadmium 2 0.25
Hexavalent 16 11
Chromium
Copper 13 _ 9 1,300
Lead 65 2.5
Manganese 50 100
Mercury 1.4 0.77
•
Nickel 470 52 610 4,600
Selenium _ 5 170 4,200
•
Silver 3.2
Thallium 0.24 0.47
Zinc 120 120 7,400 26,000
Nitrate/Nitrite 10,000
http://www.epa.gov/waterscience/criteria/wqctable/index.html

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,ito aro
srilk I UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON,D.C. 20460
+r.aoz#
OFFICE OF
WATER
signed: August 23,2007
MEMORANDUM
SUBJECT: Analytical Methods for Mercury in National Pollutant Discharge EIimination
System(NPDES)Permits
FROM: James A.Hanlon,Director
Office of Wastewater Management
TO: Water Division Directors,Regions 1 - 10
The purpose of this memorandum is to inform you of EPA's March 12,2007,approval of
Method 245.7 for measurement of mercury and modified versions of approved analytical
methods for mercury as well as the impact of their approval on the NPDES permitting process.
While several different methods are currently approved under 40 CFR Part 136 for the analysis
of mercury,sonic of these methods have much greater sensitivities and lower quantitation levels
than others. This memorandum clarifies and explains that,in light of existing regulatory
requirements for NPDES permitting,' only the most sensitive methods such as Methods 1631E
and 245.7 arc appropriate in most instances for use in deciding whether to set a permit limitation
for mercury and for sampling and analysis of mercury pursuant to the monitoring requirements
within a permit.
BACKGROUND
Section 301 of the Clean Water Act(CWA)requires NPDFS permits to include effluent
limitations that arc as stringent as necessary to meet water quality standards.Thus,under the Act
and EPA regulations,each permit must include,as necessary,requirements in addition to or
more stringent than technology-based effluent limitations established under section 301 of the
CWA in order to achieve water quality standards.40 C.F.R.§ 122.44(dXl). The regulations
require limitations to control all pollutants that the NPDES program director determines are or
may be discharged at a level that"will cause,have the reasonable potential to cause,or
contribute to an excursion above any state water quality standard,"including both narrative and
This memorandum is based on existing legal requirements and authorities.It does not impose any new,
legally binding requirements on EPA,states,or the regulated community.
Internee address'URL)•httpJ/www.epa.gov
RecYdedlReaydUNe•Printed with Vegetable Oil Based Inks on Recycled Paper(minium 30%Posloonsumerl

numeric criteria.40 C.F.R. § 122.44(dxl)(i). If the program director determines that a discharge
has the reasonable potential to cause or contribute to such an excursion,the permit must contain
water quality-based effluent limitations for the pollutant.40 C.F.R. § 122.44(d)(lxiii).Thus,a
prospective permittee may need to measure various pollutants in its effluent at two stages:first,
at the permit application stage so that the program director can determine whether"reasonable
potential"exists and establish appropriate permit limits;and second,where a permit limit has
been established,to meet the monitoring requirements within the permit. The following
discussion explains which analytical methods permit applicants and permittees should use to
make these measurements when mercury is the pollutant at issue.
Approved Analytical Methods
Measurements included on NPDES permit applications and on reports required to be submitted
under the permit must generally be made using analytical methods approved by EPA under 40
CFR Part 136. See 40 CFR 136.1, 136.4, 136.5, 122.21(g)(7),and 122.41(j).For mercury,there
are three methods commonly used in the NPDES program that EPA has approved under Part
136: Method 245.1,Method 245.2,and Method 1631E. Methods 245.1 and 245.2 were approved
by EPA in 1974 and can achieve measurement of mercury down to 200 parts per trillion(ppt).
Additionally,EPA approved Method 1631 Revision E in 2002. Method 1631E has a quantitation
level of 0.5 ppt,making it 400 times more sensitive than Methods 245.1 and 245.2.In fact,the
sensitivity of Methods 245.1 and 245.2 are well above the water quality criteria now adopted in
most states(as well as the criteria included by EPA in the Final Water Quality Guidance for the
Great Lakes System)for the protection of aquatic life and human health,which generally fall in
the range of 1 to 50 ppt.2 In contrast,Method 1631E,with a quantitation level of 0.5 ppt,does
support the measurement of mercury at these low levels.
In addition to Methods 245.1, 245.2, and 1631E listed above,EPA approved Method 245.7 as
well as modified versions of other EPA-approved methods on March 12,2007. See 72 FR
11200. Method 245.7 has a quantitation level of 5.0 ppt,making it 40 times more sensitive than
Methods 245.1 and 245.2. Additionally,modified versions of EPA-approved methods may also
be used for the measurement of mercury. Methods approved under Part 136,such as 245.1 and
245.2,may be modified to achieve lower quantitation levels than can be achieved by the method
as written.'Modifications to an EPA-approved method for mercury that meet the method
2 Many states have adopted mercury water quality criteria of 12 ppt for protection of aquatic life and 50 ppt
for the protection of human health,and for discharges to the Great Lakes Basin,the applicable water quality criteria
for mercury are 1.3 ppt for the protection of wildlife and 1.8 ppt for the protection of human health.In 2001,EPA
issued new recommended water quality criteria guidance fir the protection of human health.This new guidance
recommends adoption of a methylmercury water quality criterion of 0.3 milligrams of methylmercury per kilogram
(mg/kg)in fish tissue.EPA is currently developing implementation guidance to assist states in implementing the
criterion,and Draft Guidance for Implementing the January 2001 Methylmercury Water Quality Criterion(EPA-
823-B-04-001)was released for public comment in August 2006.
3 Examples of such modification may include changes in the sample preparation digestion procedures such as
the use of reagents similar in properties to ones used in the approved method,changes in the equipment operating
parameters such as the use of an alternate more sensitive wavelength,adjusting the sample volume to optimize
method performance,and changes in the calibration ranges(provided that the modified range covers any relevant
regulatory limit).
2
15

performance requirements of Part 136.6 are considered to be approved methods and require no
further EPA approval. See 72 FR 11239-40(March 12,2007). For analytical method
modifications that do not fall within the flexibility of Part 136.6,the modified methods may be
approved under the alternate test procedure program as defined by Parts 136.4 and 136.5.
ACTIONS RESULTING FROM THE MARCH 12,2007,RULEMAKING
To implement the March 12,2007, rule,the Office of Wastewater Management(OWM)provides
the following guidance:
Monitoring Data Submitted as Part of NPDES Permit Applications
As noted,most states have adopted water quality criteria for the protection of aquatic life and
human health that fall in the range of 1 to 50 ppt,and Methods 245.1 and 245.2,as written, do
not detect or quantify mercury in this range. A"did not detect"result using Method 245.1 or
Method 245.2 would show only that mercury levels are below 200 ppt but would not establish
that they are at or below the applicable water quality criterion.Therefore,when a permit writer
receives a permit application reporting mercury data analyzed with Method 245.1 or Method
245.2 as "did not detect"results,the permit writer in reality may lack the information needed to
make a"reasonable potential"determination. In contrast,Method 1631E is able to detect and
quantify mercury concentrations at these low levels.
EPA therefore expects,in general,that all facilities with the potential to discharge mercury will
provide with their NPDES permit applications monitoring data for mercury using Method 1631E
or another sufficiently sensitive EPA-approved method. For purposes of permit applications,a
method for mercury is"sufficiently sensitive"when(1)its method quantitation level is at or
below the level of the applicable water quality criterion for mercury or(2)its method
quantitation level is above the applicable water quality criterion,but the amount of mercury in a
facility's discharge is high enough that the method detects and quantifies the level of mercury in
the discharge.4 Accordingly,EPA strongly recommends that the permitting authority determine
that a permit application that lacks effluent data analyzed with a sufficiently sensitive EPA-
approved method such as Method 1631E is incomplete unless and until the facility supplements
the original application with data analyzed with such a method. See 40 CFR 122.21(e)(a permit
application is determined to be complete at the discretion of the permitting authority)and 40
CFR 122.21(g)(13)(the applicant shall provide to the Director,upon request,such other
information as the Director may reasonably require to assess the discharge). Such data would
allow the permitting authority to characterize the effluent to determine whether the discharge
causes,has the reasonable potential to cause,or contributes to an excursion of state water quality
standards for mercury and would consequently allow the permitting authority to determine
whether a water quality-based effluent limit for mercury is necessary in the permit.
To illustrate the latter,if the water quality criterion for mercury in a particular state is 2.0 ppt,Method 245.7
(with a quantitation level of 5.0 ppt)would be sufficiently sensitive where it reveals that the level of mercury in a
facility's discharge is 5.0 ppt or greater.In contrast,Method 245.7 would not be sufficiently sensitive if it resulted in
a level of non-detect for that discharge because it could not be known whether mercury existed in the discharge at a
level between 2.0 and 5.0(less than the quantitation level but exceeding the water quality criterion).
3

Monitoring Requirements in Permits
Where a permit authority establishes a permit limit for mercury,it also needs to consider
specifying an analytical method that the permittee must use to monitor for mercury during the
term of the permit.Methods 245.1 and 245.2,as written,are not likely to be sensitive enough to
detect or quantify the concentration of mercury in the discharge at a level that matches the
limitation for mercury in the permit. EPA therefore expects the permitting authority to require
the use of a sufficiently sensitive EPA-approved method for monitoring under the permit in order
to ensure that the sampling and measurements required are"representative of the monitored
activity"(as required by 40 CFR 122.41(j X1)), For purposes of monitoring under a permit,a
method for mercury is"sufficiently sensitive"when(1)its method quantitation level is at or
below the level of the mercury limit established in the permit or(2)its method quantitation level
is above the mercury limit in the permit,but the amount of mercury in a facility's discharge is
high enough that the method detects and quantifies the level of mercury in the discharge.
EPA Permit Review and Objection to State Issued Permits
For NPDES-authorized states,EPA regions are expected to review state permits and should
strongly consider objecting to permits that are issued based on analytical data collected and
analyzed using an EPA-approved method that is not sufficiently sensitive or that do not require
use of a sufficiently sensitive EPA-approved method for monitoring when the permit includes a
limit for mercury. OWM is expecting to undertake a permit quality review of a small
representative number of permits with respect to mercury limitations and other conditions.
If you have questions concerning the content of this memorandum,please contact Linda
Boomazian,Director of the Water Permits Division,at 202-564-0221 or have your staff contact
Marcus Zobrist of the State and Regional Branch at 202-564-8311 or [e-mail].
cc: NPDES Branch Chiefs Regions 1— 10
3 See footnote 4.
4
17

,. •
r.
. Arc n •
EPA Merrimack TB , Determination
(September i)
1
.. we ,�

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
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 PHYSICAL/CHEMICAL TREATMENT 22
3.11 PHYSICAL/CHEMICAL WITH ADDED BIOLOGICAL TREATMENT 23
4.0 BAT FOR FGD WASTEWATER AT MERRIMACK STATION 27
5.0 BPJ-BASED BAT EFFLUENT LIMITS 80
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
1

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(I), (II) and (III); RSA 125-0:12(V); 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(I) and (III); 125-
0:13(I) and (II). But see also RSA 125-0:13(V), (VII) and (VIII); RSA 125-
0:17(II) (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(I). 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(1II); 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 http://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
flue 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.
3 of 52

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 "polishing 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
5 of 52

Determination of Technology-Based Effluent Limits for the Flue Gas
Desulfurization Wastewater at Merrimack Station in Bow, New Hampshire
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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Determination of Technology-Based Effluent Limits for the Flue Gas
Desulfurization Wastewater at Merrimack Station in Bow, New Hampshire
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 Ass'n 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. Ass'n 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).
6 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 Ass'n 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:
Din 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 Ass'n, 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 Ass'n, 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.8 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
8 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 Ass'n 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 http://digitalcommons.pace.edu/pelevoll4/iss1/16/or
http://diaitalcommons.pace.edu/cgi/viewcontent.cai?article=1375&context=pelr&seiredir=1#s
earch="htto://+digitalcommons.pace.edu/oelr/voll4/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: N110001465," 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:
blower 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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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.
11 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 AM) 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"), Attachment A, 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 fixed-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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mmimi
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 2008.13 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 physicallchemical 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 AM) 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 $430 million.
The additional cost for adding biological treatment would represent a small fraction
of this total.'$
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 physicallchemical 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.is
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).
19 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 anoxidanerobic 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
E1 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
conditions may cause other coal combustion wastewater constituents to dissolve,
pH
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
eutrophication 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
levels can be a stress on aquatic organisms with potential toxic effects;elevated
solids levels can have impacts on agriculture griculture &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 to maintain
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 httn://scholarworks.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 BOD
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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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
physicaUchemical 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.
48 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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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.3) 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."
(http://water.ena.gov/scitech/wastetech/guide/treatment/upload/2000 10 19 guide cwt fina develop
ch7.pdf) 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/upload/2003 05 27 guide ironsteel reg tdd s
ections12-17.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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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 (NO3/NO2-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.ipthouahts.comlpublicationl09102010/US7790034)
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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 to suggest 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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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 Repot 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
no BCT numerical effluent
BOD (mg/L) Report Report 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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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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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.epa.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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