NC0004961_Ash Pond Closure: Ash Removal Report_20170117

EXHIBIT 6
Grainger Generating Station
Ash Removal Report
January 17, 2017

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EXHIBIT 1
Plaintiff State of North Carolina
Complaint and Motion for Injunctive Relief
August 16, 2013

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STATE OF NORTH CAROLINA IN THE GENERAL COURT OF JUSTICE
SUPERIOR COURT DIVISION
COUNTY OF WAKE 13 CVS
STATE OF NORTH CAROLINA ex rel.
NORTH CAROLINA DEPARTMENT OF )
ENVIRONMENT AND NATURAL }
RESOURCES, )
Plaintiff, )
V. ) COMPLAINT
AND MOTION FOR
DUKE ENERGY PROGRESS, INC., ) INJUNCTIVE RELIEF
RULE 65 N.C.R.C.P.
Defendant. )
The Plaintiff State of North Carolina in accordance with Article 21 of Chapter 143 of the
North Carolina General Statutes, and N.C. Gen. Stat. § IA -1, Rule 65, complaining of the
Defendant alleges and says:
PARTIES
1. Plaintiff is the sovereign State of North Carolina. This action is being brought
upon the relation of the North Carolina Department of Environment and Natural Resources
("DENR") and its Division of Water Resources ("DWR" or "division"),' an agency of the State
established pursuant to the provisions of N.C. Gen. Stat. § 143B-279.1 et seg., and vested with
the statutory authority regarding protection of the environment and enforcement of
environmental laws pursuant to N.C. Gen. Stat. § 143-211 et seq.
2. Defendant, Dukd Energy Progress, Inc. (formerly Carolina Power & Light
Company d/b/a Progress Energy Carolinas, Inc., prior to April 29, 2013), is a corporation
I DENR's Division of Water Quality and Division of Water Resources have been
combined and are currently operating under the name of Division of Water Resources. All
actions taken by the DWQ are considered to have been taken by the DWR.

organized and existing under the laws of the State of North Carolina. Defendant's principal
place of business is in Wake County, North Carolina and is located at 410 South Wilmington
Street, PEB 17B5, Raleigh, North Carolina 27601. Defendant's Registered Agent is CT
Corporation System, 150 Fayetteville Street, Box 1011, Raleigh, North Carolina 27601
3. Defendant owns the following six (6) Facilities ("6 Facilities"):
(1) Mayo Steam Electric Generating Plant ("Mayo Steam Electric
Plant") in Person County,
(2) Roxboro Steam Electric Generating Plant ("Roxboro Steam
Electric Plant") in Person County;
(3) Cape Fear Steam Electric Generating Plant ("Cape Fear Steam
Electric Plant") in Chatham County;
(4) H.F. Lee Steam Electric Plant ("Lee Steam Electric Plant") in
Wayne County;
(5) Weatherspoon Steam Electric Plant in Robeson County; and
(6) L. Y. Sutton Electric Plant ("Sutton Electric Plant") in New
Hanover County.
4. Defendant or its predecessor was doing business in all of the counties set forth in
paragraph 3 above, at each of the 6 Facilities, at the time the violations or threatened violations
were committed that gave rise to this action.
JURISDICTION AND VENUE
5. The Superior Court has jurisdiction of this action for injunctive relief for existing
or threatened violations of various laws and rules and regulations governing the protection of the
State's water resources pursuant to N.C. Gen. Stat. §§ 7A-245 and 143-215.6C, and for such
other relief as the Court shall deem proper.
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6. Wake County is a proper venue for this action because Defendant's principal
place of business is located in Wake County.
GENERAL ALLEGATIONS
Applicable Laws and Rerulations
7. Pursuant to N.C. Gen. Stat. § 143-215.3(a)(1), the Environmental Management
Commission ("EMC" or the "Commission") has the power "[t]o make rules implementing
Articles 21, 21A, 21B or 38 of... Chapter" 143 of the North Carolina General Statutes. These
statutes, and the rules adopted under them, are designed to further the public policy of the State,
as declared in N.C. Gen. Stat. § 143-211, "to provide for the conservation of its water and air
resources ... [and], within the context of this Article [21] and Articles 21A and 21B of this
Chapter [143], to achieve and to maintain for the citizens of the State a total environment of
superior quality."
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 f6r 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 which
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,
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and particularly discharge permits, to the Director of the Division of Water Resources
("Director"). See Title 15A of the North Carolina Administrative Code ("NCAC"), rule
2H.01122. A copy of this rule is attached hereto as Plaintiff's 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).
12. The Commission's rules in 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 Plaintiffs
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
2 15A NCAC 2H.0112. This Rule actually delegates the authority to issue discharge
permits to the Director of the former DWQ. However, this authority has now been delegated to
the Director of the DWR.
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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 parry."
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).
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
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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 15A NCAC 2L.0202(g) and (h). If a substance is not specifically listed and if it is
naturally occurring, the standard is the naturally occurring concentration as determined by the
Director. 15A NCAC 2L.0202(c). If a substance is listed, if it is naturally occurring and the
substance exceeds 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.
21. The DWQ Director established the 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 Plaintiff's Exhibit Nos. 3 and 4, respectively, and both exhibits are
incorporated herein by reference. The interim maximum allowable concentration for Thallium is
0.2 micrograms per liter (" 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). Seethe last page of Plaintiffs Exhibit No. 2.
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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), "[f]or 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."
15A NCAC 2L.0102(5). A site assessment pursuant to a corrective action plan 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.0106 (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 ofthis Part [Part 1, Article 21, of the General Statutes], any of the terms of any permit
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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. The statute 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 Legal AllePations
All 6 Facilities
31. With the exception of the Sutton Electric Plant, which began groundwater
monitoring in 1984, and added new monitoring wells between 1990 and 2011, Defendant
implemented a voluntary groundwater monitoring program at most of the 6 Facilities in 2006.
32. In 2009, the DWQ required Defendant to place monitoring wells at the
compliance boundaries of all of the Coal Ash Ponds at all 6 Facilities.
33. The DWQ approved Defendant's proposed locations of compliance boundary
wells and monitoring wells at each of the 6 Facilities on the following dates:
(1) Mayo Steam Electric Plant— November 12, 2010;
(2) Roxboro Steam Electric Plant — November 12, 2010;

(3) Cape Fear Steam Electric Plant — January 4, 2011;
(4) Lee Steam Electric Plant — January 4, 2011;
(5) Weatherspoon Steam Electric Plant— November 1, 2010; and
(6) Sutton Electric Plant — March 17, 2011 and October 24, 2011.
34. Defendant constructed compliance monitoring wells at the compliance boundaries
of the Coal Ash Ponds at each of the 6 Facilities on the following dates:
(1) Mayo Steam Electric Plant - November 2010;
(2) Roxboro Steam Electric Plant — October and November 2010;
(3) Cape Fear Steam Electric Plant — September 2010;
(4) Lee Steam Electric Plant — July 2010 and September 2012;
(5), Weatherspoon Steam Electric Plant — August 2010; and
(6) Sutton Electric Plant —1990 to 2012.
35. Each of the 6 Facilities has a specific set of parameters being monitored:
(1) Mayo Steam Electric Plant — Aluminum, Antimony, Arsenic,
Barium, Boron, Cadmium, Chromium, Chloride, Copper, Iron,
Lead, Manganese, Mercury, Nickel, Nitrate, pH, Selenium,
Sulfate, Thallium, Total Dissolved Solids, Water Level, and Zinc;
(2) Roxboro Steam Electric Plant — Aluminum, Antimony, Arsenic,
Barium, Boron, Cadmium, Chromium, Chloride, Copper, Iron,
Lead, Manganese, Mercury, Nickel, Nitrate, pH, Selenium,
Sulfate, Thallium, Total Dissolved Solids, Water Level, and Zinc;
(3) Cape Fear Steam Electric Plant— Aluminum, Antimony, Arsenic,
Barium, Boron, Cadmium, Chromium, Chloride, Copper, Iron,
Lead, Manganese, Mercury, Nickel, Nitrate, pH, Selenium,
Sulfate, Thallium, Total Dissolved Solids, Water Level, and Zinc;
(4) Lee Steam Electric Plant — Antimony, Arsenic, Barium, Boron,
Cadmium, Chromium, Chloride, Copper, Iron, Lead, Manganese,
Mercury, Nickel, Nitrate, pH, Selenium, Sulfate, Thallium, Total
Dissolved Solids, Water Level, and Zinc;
(5) Weatherspoon Steam Electric Plant — Antimony, Arsenic,
Barium; Boron, Cadmium, Chromium, Chloride, Copper, Iron,
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Lead, Manganese, Mercury, Nickel, Nitrate, pH, Selenium,
Sulfate, Thallium, Total Dissolved Solids, Water Level, and Zinc;
and
(6) Sutton Electric Plant — Antimony, Arsenic, Barium, Boron,
Cadmium, Chromium, Chloride, Copper, Iron, Lead, Manganese,
Mercury, Nickel, Nitrate, pH, Selenium, Sulfate, Thallium, Total
Dissolved Solids, Water Level, and Zinc.
36. In 2010 and 2011, with the exception of the Sutton Electric Plant, Defendant
began submitting groundwater monitoring data to the DWQ from 5 of the 6 Facilities. Although
actual groundwater monitoring started in 1984, the Sutton Electric Plant NPDES Permit required
groundwater monitoring to begin in the spring of 1990.
37. On June 17, 2011, the DWQ adopted a Policy for Compliance Evaluation of
Long -Term Permitted Facilities with No Prior Groundwater Monitoring Requirements
(hereinafter the "Policy for Compliance Evaluation"). A copy of the Policy for Compliance
Evaluation is attached hereto as Plaintiff's Exhibit No. 5 and is incorporated herein by reference.
38. The Policy for Compliance Evaluation establishes an approach to evaluate
groundwater compliance at long-term permitted facilities. Specifically, the Policy for
Compliance Evaluation 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.
39. All 6 Facilities are subject to the Policy for Compliance Evaluation and Plaintiff
has been working with the Defendant to move through the evaluative process as described in the
policy.
40. Plaintiff's Aquifer Protection staff compiled tables of the analytical results of
groundwater samples collected at the 6 Facilities. The 6 Facilities began submitting data in
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2010, and Plaintiff's Aquifer Protection staff prepared 6 charts of the Ash Pond Exceedances
from 2010 to July 16, 2013. The 6 charts are labeled by National Pollutant Discharge
Elimination System (NPDES) Permit number and facility name. Each chart is attached hereto
and labeled individually as Plaintiff's Exhibit: No. 6 (Mayo Steam Electric Plant Ash Pond
Exceedances Chart); No. 7 (Roxboro Steam Electric Plant Ash Pond Exceedances Chart); No. 8
(Cape Fear Stearn Electric Plant Ash Pond Exceedances Chart); No. 9 (Lee Steam Electric Plant
Ash Pond Exceedances Chart); No. 10 (Weatherspoon Steam Electric Plant Ash Pond
Exceedances Chart); and No. 11 (Sutton Electric Plant Ash Pond Exceedances Chart);
respectively, and are incorporated herein by reference.
41. Each of the 6 charts contains the following information: the well number, the
parameter sampled, the date of the sample, the 2L Groundwater Standard, the sampling result
and the unit of measurement.
Mayo Steam Electric Plant
42. On July 12, 1982, pursuant to N.C. Gen. Stat. § 143-215.1, other lawful statutes
and regulations issued by the Commission, and the Clean Water Act, the DWQ issued NPDES
Permit No. NC0038377 to Progress Energy for the Mayo Steam Electric Plant ("Mayo Steam
Electric Plant NPDES Permit"), located in Person County, North Carolina.
43. The Mayo Steam Electric Plant NPDES Permit has been renewed subsequently.
The current NPDES Permit was re -issued on October 14, 2009, with an expiration date of March
31, 2012. On September 28, 2011, Progress Energy submitted a renewal application to the
DWQ. Since the Defendant timely applied for re -issuance 180 days prior to the expiration date,
pursuant to N.C. Gen. Stat. § 150B-3, Defendant can continue to operate under the 2009 Mayo
Steam Electric Plant NPDES Permit until a new permit has been issued. A copy of the 2009
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Mayo Steam Electric Plant NPDES Permit No. NCO038377 is attached hereto as Plaintiff's
Exhibit No. 12, and is incorporated herein by reference.
44. A Special Order by Consent was approved by the EMC for the Mayo Steam
Electric Plant on June 25, 2012 and transmitted to Progress Energy on June 26, 2012. A copy of
the transmittal letter and EMC SOC WQ S 10-012 is attached hereto as Plaintiff's Exhibit No. 13
and is incorporated herein by reference. To the extent that the SOC modifies the terms of the
2009 NPDES Permit for the Mayo Steam Electric Plant, the SOC controls those terms of the
permit until a new NPDES permit is issued or a judicial order is issued.
45. The Mayo Steam Electric Plant NPDES Permit authorizes the discharge of treated
wastewater to receiving waters designated as the Mayo Reservoir in the Roanoke River Basin in
accordance with the effluent limitations, monitoring requirements and other conditions set forth
in the Mayo Steam Electric Plant NPDES Permit.
46. The Mayo Steam Electric Plant NPDES Permit authorizes a cooling tower system
less than once per year when the cooling towers and circulating water system are drained by
gravity and discharges a wastestream directly into the Mayo Reservoir through Outfall 001.
47. The Mayo Steam Electric Plant NPDES Permit authorizes a cooling tower
blowdown system that indirectly discharges to Mayo Reservoir via Internal Outfall 008 to the
Ash Pond Treatment System at Outfall 002. Cooling tower blowdown is usually mixed with ash
sluice water prior to discharge to the ash pond.
48. The Mayo Steam Electric Plant NPDES Permit authorizes an Ash Pond Treatment
System at Outfall 002 that discharges directly into the Mayo Reservoir. The Ash Pond receives
ash transport water, coal pile runoff, storm water runoff, cooling tower blowdown and various
low volume wastes such as boiler blowdown, oily waste treatment, wastes/backwash from the
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water treatment processes including Reverse -Osmosis wastewater, plant area wash down water,
equipment heat exchanger water, and treated domestic wastewater.
49. The Mayo Steam Electric Plant NPDES Permit authorizes a stormwater discharge
system to discharge stormwater to the Mayo Reservoir through Outfalls 004, 005, 006a, 006b,
006c, 006d, 006e, and 010. Drainage from the outside storage area discharges at Outfall 004.
Drainage from the industrial area and the oil/bottled gas storage area discharges at Outfall 005.
Drainage from the cooling tower(s) chemical feed building structure and the cooling tower area
discharges at Outfalls 006a, 006b, 006c, 006d and 006e. Drainage from the haul road for coal
ash, limestone, gypsum and gaseous anhydrous ammonia discharges at Outfall 010.
50. The effluent limitations and monitoring requirements in the Mayo Steam Electric
Plant NPDES Permit for the discharge from Outfall 001 (cooling tower system) require sampling
for the following parameters: Flow, Free Available Chlorine, Time of Chlorine Addition, Total
Chromium, Total Zinc, Priority Pollutants and pH. The Mayo Steam Electric Plant NPDES
Permit prohibits the discharge of polychlorinated biphenyl compounds ("PCBs") such as those
used for transformer fluid.
51. The effluent limitations and monitoring requirements in the Mayo Steam Electric
Plant NPDES Permit for the indirect discharge from Outfall 008 (cooling tower blowdown
system) to the Ash Pond Treatment System require sampling for the following parameters:
Flow, Free Available Chlorine, Time of Chlorine Addition, Total Chromium, Total Zinc, Priority
Pollutants and pH. The Mayo Steam Electric Plant NPDES Permit does not authorize a direct
discharge to the Mayo Reservoir.
52. The effluent limitations and monitoring requirements in the Mayo Steam Electric
Plant NPDES Permit for the discharge from Outfall 002 (Ash Pond Treatment System) require
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sampling for the following parameters without FGD wastewater: Flow, Oil and Grease, Total
Suspended Solids, Total Selenium, Acute Toxicity, Total Arsenic, Total Copper, Total Iron and
pH. After the FGD system is used to treat FGD wastewater, the Mayo Steam Electric Plant
NPDES Permit requires sampling for the following parameters: Flow, Oil and Grease, Total
Suspended Solids, Total Selenium, Acute Toxicity, Total Mercury, Total Arsenic, Total
Cadmium, Total Chlorides, Total Chromium, Total Copper, Total Fluoride, Total Lead, Total
Manganese, Total Nickel, Total Silver, Total Zinc, Total Barium, Total Thallium, Total
Vanadium, Total Antimony, Total Boron, Total Cobalt, Total Molybdenum, Total Iron and pH.
Among other things, the SOC authorizes Defendant to comply with all terms of its NPDES
permit except for Interim Limits for Mercury, Selenium, Boron, Manganese and Thallium during
the period of the SOC.
53. The Mayo Steam Electric Plant NPDES Permit also requires Acute Toxicity
monitoring, Fish Tissue Sampling for Arsenic only, an annual biological, physical and chemical
study of Selenium, and annual monitoring of the waters of Crutchfield Branch, 100 yards
downstream of the ash pond, for Arsenic, Copper and Selenium.
54. The effluent limitations and monitoring requirements in the Mayo Steam Electric
Plant NPDES Permit for the for the discharge from Outfall 010 (stormwater discharge system)
require sampling for the following parameters: 13 Priority Pollutant Metals (Silver, Arsenic,
Beryllium, Cadmium, Chromium, Copper, Mercury, Nickel Lead, Antimony, Selenium,
Thallium, Zinc), Aluminum, Boron, Chemical Oxygen Demand, Total Suspended Solids,
Sulfate, Oil and Grease, pH and Total Rainfall.
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Unpermitted Seeps at the Mayo Steam Electric Plant
55. As mentioned above, the Defendant's Mayo Steam Electric Plant has two permitted
outfalls and eight stormwater outlets discharging directly into the Mayo Reservoir which are
included in the Mayo Steam Electric Plant NPDES Permit.
56. Defendant's Mayo Steam Electric Plant NPDES Permit does not authorize the
Defendant to make any outlet or discharge any wastewater or stormwater other than those
included in the Mayo Steam Electric Plant NPDES Permit.
57. The Mayo Steam Electric Plant NPDES Permit expressly prohibits a discharge
from the ash pond to Crutchfield Branch. Condition A.(8) states: "There shall be no direct
discharge from the ash pond to Crutchfield Branch. There shall be no violation of water quality
standards in Crutchfield Branch due to any indirect discharge from the ash pond. The permittee
shall monitor the waters of Crutchfield Branch, 100 yards downstream of the dike, once per year
by grab sample for the following: arsenic, copper, and selenium."
58. Seeps identified at Defendant's Mayo Steam Electric Plant, include engineered
discharges from the toe -drains of its Ash Pond, which are at different locations from the outfalls
and stormwater outlets described in the Mayo Steam Electric Plant NPDES Permit. Defendant's
Ash Pond dam has 2 engineered toe -drains (running east and west) that continuously discharge to
Crutchfield Branch and Defendant does not have a permit for this direct discharge.
59. A seep or discharge from the Ash Pond of the Mayo Steam Electric Plant that is
not included in the Mayo Steam EIectric Plant NPDES Permit is an unpermitted discharge in
violation of N.C. Gen. Stat. § 143-215.1(a)(1) and (a)(6).
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Exceedances of the 2L Groundwater Standards at the Mayo Steam Electric Plant
60. The Plaintiff's Aquifer Protection staff compiled tables of the analytical results of
groundwater samples collected at the Mayo Steam Electric Plant from November 2010 through
July 16, 2013, and prepared a chart of the Ash Pond Exceedances which are listed in the Mayo
Steam Electric Plant Ash Pond Exceedances Chart. See Plaintiff's Exhibit No. 6.
61. The Mayo Stearn Electric Plant Ash Pond Exceedances Chart shows exceedances
from the 2L Groundwater Standard for Chromium (10 µg/L) in compliance wells BG -1 and BG -
2 during three sampling events from December 2010 to July 2012, with concentrations ranging
from 10.2 µg/L to 40.1 gg/L.
62. The Mayo Steam Electric Plant Ash Pond Exceedances Chart shows exceedances
from the 2L Groundwater Standard for Manganese (50 gg/L) in compliance wells BG -1, BG -2,
CW -1, CW -1D, CW -2, CW -21), CW -3, CW -5 and CW -6 during eight sampling events from
December 2010 through May 2013, with concentrations ranging from 52.6 µg/L to 1,440 gg/L.
63. The Mayo Steam Electric Plant Ash Pond Exceedances Chart shows exceedances
from the 21, Groundwater Standard for Total Dissolved Solids (500 milligrams per liter
("mg/L")) in compliance wells CW -3 and CW -6 during three sampling events from July 2012
through April 2013, with concentrations ranging from 520 mg/L to 550 mg/L.
64. The Mayo Steam Electric Plant Ash Pond Exceedances Chart shows exceedances
from the 21, Groundwater Standard for Total Iron (300 gg/L) in compliance wells BG -1, BG -2,
CW -21), CW -3, CW -4, CW -5 and CW -6 during eight sampling events from December 2010
through May 2013, with concentrations ranging from 312 µg/L to 2,660 pg/L.
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65. The DWR staff is working with the Defendant to determine if these exceedances
are naturally occurring or if corrective action will be required.
Roxboro Steam Electric Plant
66. On June 30, 1981, pursuant to N.C. Gen. Stat. § 143-215.1, other lawful statutes
and regulations issued by the Commission, and the Clean Water Act, the DWQ issued NPDES
Permit No. NC0003425 to Progress Energy for the Roxboro Steam Electric Plant ("Roxboro
Steam Electric Plant NPDES Permit'), located in Person County, North Carolina.
67. The Roxboro Steam Electric Plant NPDES Permit has been renewed
subsequently. The current NPDES Permit was re -issued on April 9, 2007, with an expiration
date of March 31, 2012. On October 10, 2011, Progress Energy submitted a renewal application
to the DWQ. Since the Defendant's predecessor timely applied for re -issuance 180 days prior to
the expiration date, pursuant to N.C. Gen. Stat. § 150B-3, Defendant can continue to operate
under the 2009 Roxboro Steam Electric Plant NPDES Permit until a new permit has been issued.
A copy of the 2007 Roxboro Steam Electric Plant NPDES Permit No. NC0003425 is attached
hereto as Plaintiff s Exhibit No. 14, and is incorporated herein by reference.
68. The Roxboro Steam Electric Plant NPDES Permit authorizes the discharge of
treated wastewater to receiving waters designated as the Hyco Lake in the Roanoke River Basin
in accordance with the effluent limitations, monitoring requirements and other conditions set
forth in the Roxboro Steam Electric Plant NPDES Permit.
69. The Roxboro Steam Electric Plant NPDES Permit authorizes a Heated Water
Discharge Canal System at Outfall 003. At the point that the discharge canal enters Hyco Lake,
it contains flows from several wastestreams including once through cooling water, stormwater
runoff and the effluent from the Ash Pond at Internal Outfall 002.
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70. The Roxboro Steam Electric Plant NPDES Permit authorizes a coal pile runoff
treatment system at Outfall 006 that handles runoff from the coal pile and other coal handling
areas, including limestone piles, gypsum piles and truck wheel washwater. The waters are
routed to a retention pond for treatment by neutralization, sedimentation and equalization prior to
being discharged directly into Hyco Lake.
71. The Roxboro Steam Electric Plant NPDES Permit authorizes an Ash Pond
Treatment System at Internal Outfall 002 that discharges to the heated water discharge canal and
ultimately into the Hyco Lake through Outfall 003. The Ash Pond treats ash transport, low
volume wastewater, runoff from the ash landfill, dry flyash handling system washwater, coal pile
runoff silo washwater, stormwater runoff, cooling tower blowdown from unit number 4 and
domestic sewage plant effluent.
72. The Roxboro Steam Electric Plant NPDES Permit authorizes a cooling tower
blowdown system from unit number 4 at Internal Outfall 005 which discharges into the Ash
Transport System, and ultimately flows into the Ash Pond at Internal Outfall 002.
73. The Roxboro Steam Electric Plant NPDES Permit authorizes a chemical metal
cleaning treatment system at Internal Outfall 009 that occasionally discharges a wastestream to
the Ash Pond Treatment System. It contains chemical metal cleaning wastes.
74. The Roxboro Steam Electric Plant NPDES Permit authorizes a domestic
wastewater treatment system at Internal Outfall 008 that flows into the Ash Pond Treatment
System.
75. The Roxboro Steam Electric Plant NPDES Permit authorizes discharges from an
FGD treatment system at Internal Outfall 010. This wastestream is generated from blowdown
18

from the FGD treatment unit. After treatment in the bioreactors, this effluent is discharged into
the heated water discharge canal.
76. The effluent limitations and monitoring requirements in the Roxboro Steam
Electric Plant NPDES Permit for the discharge from Outfall 003 (heated water discharge canal
system to the Hyco Reservoir) require sampling for the following parameters: Flow, Total
Residual Chlorine, Total Phosphorus, Total Nitrogen, Temperature, Total Arsenic, pH and Acute
Toxicity. The Roxboro Steam Electric Plant NPDES Permit prohibits the discharge of floating
solids or visible foam in other than trace amounts.
77. The effluent limitations and monitoring requirements in the Roxboro Steam
Electric Plant NPDES Permit for the discharge from Outfall 006 (coal pile runoff treatment
system to the Hyco Reservoir) require sampling for the following parameters: Flow, Total
Suspended Solids, Acute Toxicity and pH.
78. The effluent limitations and monitoring requirements in the Roxboro Steam
Electric Plant NPDES Permit for the discharge from Internal Outfall 002 (Ash Pond Treatment
System) require sampling for the following parameters: Flow, Total Selenium, Oil and Grease
and Total Suspended Solids.
79. The effluent limitations and monitoring requirements in the Roxboro Steam
Electric Plant NPDES Permit for the discharge from Internal Outfall 005 (cooling tower
blowdown system) require sampling for the following parameters: Flow, Free Available
Chlorine, Total Residual Chlorine, Total Chromium, Total Zinc and 126 Priority Pollutants.
80. The effluent limitations and monitoring requirements in the Roxboro Steam
Electric Plant NPDES Permit for the discharge from Internal Outfall 008 (domestic wastewater
19

treatment system) to the Ash Pond require sampling for the following parameters: Flow,
Biochemical Oxygen Demand, Total Suspended Solids, Total Ammonia and pH.
81. The effluent limitations and monitoring requirements in the Roxboro Steam
Electric Plant NPDES Permit for the discharge from Internal Outfall 009 (heated water discharge
canal system) require sampling for the following parameters: Flow, Total Suspended Solids, Oil
and Grease, Total Copper and Total Iron.
82. The effluent limitations and monitoring requirements in the Roxboro Steam
Electric Plant NPDES Permit for the discharge from Internal Outfall 010 (FGD treatment
system), require sampling for the following parameters: Flow, Total Beryllium, Total Mercury,
Total Antimony, Total Selenium, Total Silver and Total Vanadium.
83. Stormwater runoff to the heated water discharge canal is included in the Roxboro
Steam Electric Plant NPDES Permit.
Unpermitted Seeps at the Roxboro Steam Electric Plant
84. As mentioned above, the Defendant's Roxboro Steam Electric Plant has seven
permitted outfalls, with two outfalls (Outfalls 003 and 006) discharging directly into Hyco Lake
which are included in the Roxboro Steam Electric Plant NPDES Permit.
85. Defendant's Roxboro Steam Electric Plant NPDES Permit does not authorize the
Defendant to make any outlet or discharge any wastewater or stormwater other than those
included in the Roxboro Steam Electric Plant NPDES Permit.
86. Seeps identified at Defendant's Roxboro Steam Electric Plant, include 7
engineered discharges to the heated water discharge canal, which are at different locations from
the outfalls and stormwater outlets described in the Roxboro Steam Electric Plant NPDES
Permit.
20

87. Seeps identified at Defendant's Roxboro Steam Electric Plant, include 2
stormwater discharges directly to Hyco Lake, which are at different locations from the outfalls
and stormwater outlets described in the Roxboro Steam Electric Plant NPDES Permit.
88. A seep or discharge from the Ash Pond or any other part of the Roxboro Steam
Electric Plant that is not included in the Roxboro Steam Electric Plant NPDES Permit is an
unpermitted discharge in violation of N.C. Gen. Stat. § 143-215.1(a)(1) and (a)(6).
Exceedances in Violation of 2L Groundwater Standards at the Roxboro Steam Electric Plant
89. The Plaintiffs Aquifer Protection staff compiled a table of the analytical results
of groundwater samples collected at the Roxboro Steam Electric Plant from November 2010
through July 16, 2013, and prepared a chart of the Ash Pond Exceedances which are listed in in
the Roxboro Steam Electric Plant Ash Pond Exceedances Chart. See Plaintiff s Exhibit No. 7.
90. The Roxboro Steam Electric Plant Ash Pond Exceedances Chart shows
exceedances from the 2L Groundwater Standard for Sulfate (250 mg/L) in monitoring well CW -
5 during seven sampling events from November 2010 to April 2013, with concentrations ranging
from 296 mg/L to 873 mg/L. Although Sulfate is a naturally occurring compound, its presence
in groundwater and specific occurrence at this site indicates impacts to groundwater resulting
from the wastewater treatment and disposal associated with coal burning activities. Monitoring
well CW -5 is located at the compliance boundary of the Ash Pond Treatment System at the
Roxboro Steam Electric Plant.
91. Defendant's exceedances of the 2L Groundwater Standards for Sulfate at or
beyond the compliance boundary of the Roxboro Steam Electric Plant Ash Pond are violations of
the groundwater standards as prohibited by 15A NCAC 2L.0103(d).
21

Other Exceedances of 2L Groundwater Standards
at the Roxboro Steam Electric Plant
92. The Roxboro Steam Electric Plant Ash Pond Exceedances Chart shows
exceedances from the 2L Groundwater Standard for Total Chromium (10 µg/L) in compliance
well BG -1 during five sampling events from November 2010 to November 2012, with
concentrations ranging from 11.1 µg/L to 42.7 µg/L. The last sample from this well remained an
exceedance of the 21, Groundwater Standard. The Roxboro Steam Electric Plant Ash Pond
Exceedances Chart shows additional exceedances from the 2L Groundwater Standard for Total
Chromium in wells CW -1, CW -21), and CW -4 during three sampling events from November
2010 through July 2011, with concentrations ranging from 16.9 pg/L to 29.6 µg/L.
93. The Roxboro Steam Electric Plant Ash Pond Exceedances Chart shows
exceedances from the 2L Groundwater Standard for Manganese (50 4g/L) in compliance well
CW -31) during eight sampling events from November 2010 through April 2013, with
concentrations ranging from 84.8 µg/L to 416 µg/L. The Roxboro Steam Electric Plant Ash
Pond Exceedances Chart shows exceedances from the 2L Groundwater Standard for Manganese
in compliance wells CW -1 and CW -2 during one sampling event in November 2010, with
concentrations of 180 µg/L and 52.9 4g/L, respectively.
94. The Roxboro Steam Electric Plant Ash Pond Exceedances Chart shows
exceedances from the 2L Groundwater Standard for Total Dissolved Solids (500 mg/L) in CW -3,
CW -4 and CW -5 during seven sampling events from November 2010 through April 2013, with
concentrations ranging from 570 mg/L to 652 mg/L in CW -3; with a value of 612 mg/L in CW -
4 in November 2011; and with concentrations ranging from 616 mg/L to 1,510 mg/L in CW -5.
22

95. The Roxboro Stearn Electric Plant Ash Pond Exceedances Chart shows
exceedances from the 2L Groundwater Standard for Total Iron (300 µ/L) in compliance well
BG -1 during six sampling events, from November 2010 to November 2012 with concentrations
ranging from 307 µg/L to 881 µg/L. The Roxboro Steam Electric Plant Ash Pond Exceedances
Chart shows exceedances from the 2L Groundwater Standard for Total Iron in compliance wells
CW -1, CW -2, CW -21), CW -3, CW -313 and CW -4 during eight sampling events from November
2010 through April 2013, with concentrations ranging from 321 µg/L to 2,290 µg/L.
96. The DWR staff is working with the Defendant to determine if these exceedances
are naturally occurring or if corrective action will be required.
Cage Fear Steam Electric Plant
97. On August 30, 1976, pursuant to N.C. Gen. Stat. § 143-215.1, other lawful
statutes and regulations issued by the Commission, and the Clean Water Act, the DWQ issued
NPDES Permit No. NC0003433 to Progress Energy for the Cape Fear Steam Electric Plant
("Cape Fear Steam Electric Plant NPDES Permit"), located in Chatham County, North Carolina.
98. The Cape Fear Steam Electric Plant NPDES Permit has been renewed
subsequently. The current Cape Fear Steam Electric Plant NPDES Permit was re -issued on July
22, 2011, with an effective date of September 1, 2011, and with an expiration date of July 31,
2016. A copy of the current Cape Fear Steam Electric Plant NPDES Permit No. NC0003433 is
attached hereto as Plaintiff's Exhibit No. 15, and is incorporated herein by reference.
99. The Cape Fear Steam Electric Plant NPDES Permit authorizes the discharge of
treated wastewater to receiving waters designated as an unnamed tributary to the Cape Fear
River in the Cape Fear River Basin in accordance with the effluent limitations, monitoring
requirements and other conditions set forth in the NPDES permit.
23

100. The Cape Fear Steam Electric Plant NPDES Permit authorizes the West Ash Pond
Treatment System (Internal Outfall 001) to discharge through Outfall 007 into an unnamed
tributary of the Cape Fear River. The West Ash Pond receives treated wastewater including ash
sluice waters (bottom and fly), coal pile runoff, No. 2 fuel oil tank runoff, settling basin drains,
sand bed filter backwash, parking lot drains, equipment cooling tower blowdown and drain,
boiler blowdown, metal cleaning waste, oil unloading area drains, softener regenerate,
demineralizer regenerate, acid/caustic sump wastewater, yard and floor drains, and ash trench
drain wastewater.
101. The Cape Fear Steam Electric Plant NPDES Permit authorizes a Once -Through
Cooling Water and Stormwater System (Internal Outfall 003) that discharges a wastestream
through Outfall 007 into an unnamed tributary of the Cape Fear River.
102. The Cape Fear Steam Electric Plant NPDES Permit authorizes the East Ash Pond
Treatment System (Internal Outfall 005) to discharge through Outfall 007 into an unnamed
tributary of the Cape Fear River. The East Ash Pond receives treated wastewater including ash
sluice waters (bottom and fly), runoff from yard drains, air preheater washes, electrostatic
precipitator washes, metal cleaning wastes, spent sandblast material, and treated sanitary
wastewater.
103. The Cape Fear Steam Electric Plant NPDES Permit authorizes the discharge of
the Combined Wastewater to the Cape Fear River at Outfall 007, which is a combination of all
the internal outfalls.
104. The effluent limitations and monitoring requirements in the Cape Fear Steam
Electric Plant NPDES Permit for the discharge from Internal Outfall 001 (West Ash Pond
Treatment System) require sampling for the following parameters: Flow, Oil and Grease, Total
24

Suspended Solids, Total Arsenic, Total Selenium, Ammonia -Nitrogen, Total Iron and Total
Copper.
105. The effluent limitations and monitoring requirements in the Cape Fear Steam
Electric Plant NPDES Permit for the discharge from Internal Outfall 003 (Once -Through
Cooling Water and Stormwater System) require sampling for Flow.
106. The effluent limitations and monitoring requirements in the Cape Fear Steam
Electric Plant NPDES Permit for the discharge from Internal Outfall 005 (East Ash Pond
Treatment System) require sampling for the following parameters: Flow, Oil and Grease, Total
Suspended Solids, Total Arsenic, Total Selenium, Fecal Coliform, Ammonia -Nitrogen, Total
Iron and Total Copper.
107. The effluent limitations and monitoring requirements in the Cape Fear Steam
Electric Plant NPDES Permit for the discharge from Outfall 007 (Combined wastewater and
stormwater discharge) require sampling for the following parameters: Flow, Total Chromium,
Total Arsenic, Total Selenium, Total Mercury, Total Nickel, Total Copper, Total Nitrogen, Total
Phosphorus, Fecal Coliform, Temperature, pH and Chronic Toxicity. The permit also prohibits
the discharge of floating solids or visible foam in other than trace amounts.
Unpermitted Seeps at the Cape Fear Steam Electric Plant
108. As mentioned above, the Defendant's Cape Fear Steam Electric Plant has four
permitted outfalls, with one (Outfall 007) discharging directly into the Cape Fear River or into an
unnamed tributary to the Cape Fear River, which are included in the Cape Fear Steam Electric
Plant NPDES Permit.
25
It

109. Defendant's Cape Fear Steam Electric Plant NPDES Permit does not authorize
the Defendant to make any outlet or discharge any wastewater or stormwater other than those
included in the Cape Fear Steam Electric Plant NPDES Permit.
110. Seeps identified at Defendant's Cape Fear Steam Electric Plant, include potential
discharges from its 1985 Ash Pond, which are at different locations from the outfalls and
stormwater outlets described in the Cape Fear Steam Electric Plant NPDES Permit.
111. During an NPDES inspection on September 23, 2009, documented sample results
from swamp/drainage area near permitted Internal Outfall 005 indicated the possibility of
seepage from the 1985 Ash pond. A grab sample was taken during the inspection by Progress
Energy and processed at Tritest Lab in Raleigh. Another grab sample was taken by DWQ and
processed at the DWQ Lab. The lab results showed the following: for Aluminum (the Tritest
Lab reported 216 gg/L; the DWQ Lab reported 1,400 gg/L); for Arsenic (the Tritest Lab
reported <3 gg/L; the DWQ Lab reported 140 gg/L); for Molybdenum (the Tritest Lab reported
<5 gg/L; the DWQ Lab reported 550 gg/L); for Selenium (the Tritest Lab reported <2 gg/L; the
DWQ Lab reported 240 gg/L); and for Vanadium (the Tritest Lab reported 13.3 gg/L; the DWQ
Lab reported 250 gg/L). Based on its review of the above results, the Plaintiff's Raleigh
Regional Office Surface Water Protection Staff concludes there may be seepage from
Defendant's 1985 Ash Pond.
112. A seep or discharge from the Ash Ponds or any other part of the Cape Fear Steam
Electric Plant that is not included in the Cape Fear Steam Electric Plant NPDES Permit is an
unpermitted discharge in violation of N.C. Gen. Stat. § 143-215.1(a)(1) and (a)(6).
..61

Exceedances in Violation of 2L Groundwater Standards
at the Cape Fear Steam Electric Plant
113. Plaintiff's Aquifer Protection staff compiled a table of the analytical results of
groundwater samples collected at the Cape Fear Steam Electric Plant from December 2010
through July 16, 2013, and prepared a chart of the Ash Pond Exceedances which are listed in the
Cape Fear Steam Electric Plant Ash Pond Exceedances Chart. See Plaintiff's Exhibit No. 8.
114. The Cape Fear Steam Electric Plant Ash Pond Exceedances Chart shows
exceedances from the 2L Groundwater Standard for Boron (700 gg/L) in monitoring well CMW-
1 during eight sampling events from December 2010 to March 2013, with concentrations ranging
from 1,790 gg/L to 2,950 gg/L; in monitoring well CMW-6 during six sampling events from
December 2010 to March 2013, with concentrations ranging from 704 gg/L to 1,010 gg/L; and
in monitoring well CMW-8 during eight sampling events from December 2010 to March
2013,with concentrations ranging from 1,070 gg/L to 1,340 gg/L. Although Boron is a naturally
occurring element, its presence in groundwater and specific occurrence at this site indicates
impacts to groundwater resulting from the waste water treatment and disposal associated with
coal burning activities.
115. Monitoring well CMW-1 is located at the southwest corner of the compliance
boundary of the West Ash Pond Treatment System at the Cape Fear Steam Electric Plant. Well
CMW-1 is located immediately adjacent to the compliance boundary and the Cape Fear River.
Monitoring well CMW-6 is located at the southeast corner of the compliance boundary of the
East Ash Pond Treatment System at the Cape Fear Steam Electric Plant. The monitoring well is
located approximately 300 feet southeast of the East Ash Pond. Monitoring well CMW-8 is
located on the western side of the compliance boundary of the West Ash Pond Treatment System
27

at the Cape Fear Steam Electric Plant. CMW-8 is located immediately between the compliance
boundary and the Cape Fear River.
116. The Cape Fear Steam Electric Plant Ash Pond Exceedances Chart also shows
exceedances from the 2L Groundwater Standard for Selenium (20 µg/L) in monitoring well
CMW-3 during eight sampling events from December 2010 to March 2013, with concentrations
ranging from 20.6 pg/L to 41.2 µg/L. Although Selenium is a naturally occurring element, its
presence in groundwater and specific occurrence at this site indicates impacts to groundwater
resulting from the wastewater treatment and disposal associated with coal burning activities.
117. The Cape Fear Steam Electric Plant Ash Pond Exceedances Chart also shows
exceedances from the 2L Groundwater Standard for Sulfate (250 mg/L) in monitoring well
CMW-2 during seven sampling events from November 2010 to March 2013, with concentrations
ranging from 260 mg/L to 630 mg/L. Although Sulfate is a naturally occurring compound, its
presence in groundwater and specific occurrence at this site indicates impacts to groundwater
resulting from the waste water treatment and disposal associated with coal burning activities.
118. Monitoring well CMW-2 is located adjacent to the 1956 Semi -Active Ash Pond
located in the northwest corner of the site. CMW-2 is also located on the west-northwest
compliance boundary, immediate adjacent to the Cape Fear River
119. Defendant's exceedances of the 2L Groundwater Standards for Boron, Selenium
and Sulfate at or beyond the compliance boundary of the Cape Fear Steam Electric Plant Ash
Ponds are violations of the groundwater standards as prohibited by 15A NCAC 2L.0103(d).
Other Exceedances of 2L Groundwater Standards
at the Cape Fear Steam Electric Plant
120. The Cape Fear Steam Electric Plant Ash Pond Exceedances Chart shows
exceedances from the 2L Groundwater Standard for Arsenic (10 µg/L) in compliance well
28

CTMW-8 during one sampling event in June 2012, with a concentration of 10.5 µg/L. However,
Arsenic is naturally occurring and no other exceedances of arsenic have been identified in this
well or in other compliance monitoring wells.
121. The Cape Fear Steam Electric Plant Ash Pond Exceedances Chart consistently
shows exceedances from the 2L Groundwater Standard for Iron (300 µg/L) in CMW-1 during
eight sampling events from December 2010 to March 2013, with a maximum observed
concentration of 54,600 4g/L; in compliance wells CMW-7, CMW-8, CTMW-1 and CTMW-8
during eight sampling events from December 2010 to March 2013, with concentrations ranging
from 416 µg/L to 52,700 µg/L; in compliance wells BGMW-4, BGTMW-4, CMW-2, CMW-3,
CMW-5, CMW-6, CTMW-2 and CTMW-7 during eight sampling events from December 2010
to March 2013, with concentrations ranging from 303 µg/L to 5,950 µg/L.
122. The Cape Fear Steam Electric Plant Ash Pond Exceedances Chart consistently
shows exceedances from the 21, Groundwater Standard for Manganese (50 µg/L) in compliance
monitoring wells BGMW-4, CMW-1, CMW-2, CMW-3, CMW-5, CMW-6, CMW-7, CMW-8,
CTMW-1, CTMW-2, CTMW-7 and CTMW-8, during eight sampling events from December
2010 to March 2013, with concentrations ranging from 51.9 µg/L to 18,000 µg/L.
123. The Cape Fear Steam Electric Plant Ash Pond Exceedances Chart shows
exceedances from the 21, Groundwater Standard for Boron in monitoring well CMW-3 during
seven sampling events from December 2010 through March 2013, with concentrations ranging
from 714 µg/L to 1,260 µg/L. The Cape Fear Steam Electric Plant Ash Pond Exceedances Chart
also shows an exceedance from the 21, Groundwater Standard for Sulfate in CMW-3 during one
sampling event with a concentration of 388 mg/L. Monitoring well CMW-3 is located at the
29

northwest corner of the compliance boundary of the West Ash Pond Treatment System at the
Cape Fear Steam Electric Plant, adjacent to the 1956 Semi -Active Ash Pond.
124. The Cape Fear Steam Electric Plant Ash Pond Exceedances Chart consistently
shows exceedances from the 2L Groundwater Standard for Total Dissolved Solids (500 mg/L) in
compliance wells CMW-2, CMW-3, CMW-6, and CTMW-8, during eight sampling events from
December 2010 to March 2013, with concentrations ranging from 502 mg/L to 1,100 mg/L.
125. The Cape Fear Steam Electric Plant Ash Pond Exceedances Chart consistently
shows exceedances from the 2L Groundwater Standard for pH levels in monitoring well
BGTMW-4 during three sampling events from December 2010 to March 2013, with
concentrations- of 10.3, 9.4 and 9.1, respectively. However, recent sampling events did not
identify pH outside the acceptable 2L Groundwater Standard range of 6.5 to 8.5.
126. The DWR staff is working with the Defendant to determine if these exceedances
are naturally occurring or if corrective action will be required.
Lee Steam Electric Plant
127. On June 30, 1977, pursuant to N.C. Gen. Stat. § 143-215.1, other lawful statutes
and regulations issued by the Commission, and the Clean Water Act, the DWQ issued NPDES
Permit No. NC0003417 to the Progress Energy for the H.F. Lee Steam Electric Plant ("Lee
Steam Electric Plant NPDES Permit"), located in Wayne County, North Carolina.
128. The Lee Steam Electric Plant NPDES Permit has been renewed subsequently
The current Lee Steam Electric Plant NPDES Permit was re -issued on October 14, 2009, with an
effective date of November 1, 2009, and with an expiration date of May 31, 2013. A copy of the
current Lee Steam Electric Plant NPDES Permit No. NC0003417 is attached hereto as Plaintiff's
Exhibit No. 16, and is incorporated herein by reference.
30

129. The Lee Steam Electric Plant NPDES Permit was also modified on November 1,
2009, to reflect a name change.
130. On November 20, 2012, Defendant submitted a renewal application to the DWQ.
While the renewal application is being processed, Defendant continues to operate the Lee Steam
Electric Plant under the 2009 Lee Steam Electric Plant NPDES Permit.
131. The Lee Steam Electric Plant NPDES Permit authorizes the discharge of treated
wastewater to receiving waters designated as the Neuse River in the Neuse River Basin in
accordance with the effluent limitations, monitoring requirements and other conditions set forth
in the Lee Steam Electric Plant NPDES Permit.
132. The Lee Steam Electric Plant NPDES Permit authorizes an Ash Pond Treatment
System at Outfall 001 that discharges directly into the Neuse River. The Ash Pond receives ash
transport water, including effluent from a Rotamix System, storm water runoff, various low
volume wastes (such as filter plant blowdown and wash water, combustion turbine wash water),
and precipitator and air pre -heater wash water.
133. The Lee Steam Electric Plant NPDES Permit authorizes the discharge of re-
circulated condenser cooling water, non -contact cooling water, coal pile runoff, low volume
waste, sanitary wastes, stormwater runoff and evaporative cooler wastewater and contaminant
stormwater from the combustion turbine site directly into the Neuse River through Outfall 002.
134. The Lee Steam Electric Plant NPDES Permit authorizes the discharge of filter
plant wastewater, equipment and contaminant drains, reverse osmosis reject and filter backwash,
and quenched -heat recovery steam generator blowdown via Outfall'003 directly into the Neuse
River. Generally, chemical metal cleaning wastes are treated by evaporation in boilers.
31

Unpermitted Seeps at the Lee Steam Electric Plant
135. As mentioned above, the Defendant's Lee Steam Electric Plant has three permitted
outfalls discharging directly into the Neuse River which are included in the Lee Steam Electric
Plant NPDES Permit.
136. Defendant's Lee Steam Electric Plant NPDES Permit does not authorize the
Defendant to make any outlet or discharge any wastewater or stormwater other than those
included in the Lee Steam Electric Plant NPDES Permit.
137. Upon information and belief, Plaintiff believes there are non -engineered seeps at
Defendant's Lee Steam Electric Plant, which are at different locations from the outfalls described
in the Lee Steam Electric Plant NPDES Permit.
138. A seep or discharge from the Ash Pond or any other part of the Lee Steam
Electric Plant that is not included in the Lee Steam Electric Plant NPDES Permit is an
unpermitted discharge in violation of N.C. Gen. Stat. § 143-215.1(a)(1) and (a)(6).
Exceedances In Violation of the 2L Groundwater Standards
at the Lee Steam Electric Plant
139. Plaintiffs Aquifer Protection staff compiled tables of the analytical results of
groundwater samples collected at the Lee Steam Electric Plant from December 2010 through
July 16, 2013, and prepared a chart of the Ash Pond Exceedances which are listed in in the Lee
Steam Electric Plant Ash Pond Exceedances Chart. See Plaintiffs Exhibit No. 9.
140. The Lee Steam Electric Plant Ash Pond Exceedances Chart shows exceedances
from the 2L Groundwater Standard for Arsenic (10 µg/L) in compliance well CMW-6 during six
sampling events from December 2010 through June 2012, with a maximum concentration of 665
pg/L; in replacement well CMW-6R during two sampling events from October 2012 and March
2013, with concentrations of 30.2 gg/L and 10.2 gg/L, respectively; and in CMW-10,during one
32

sampling event in December 2010, with a concentration of 12 µg/L. Although Arsenic is a
naturally occurring element, its presence in groundwater and specific occurrence at this site
indicates impacts to groundwater resulting from the wastewater treatment and disposal
associated with coal burning activities.
141. The Lee Steam Electric Plant Ash Pond Exceedances Chart shows exceedances
from the 2L Groundwater Standard for Boron (700 pg/L) in CMW-5 and CMW-6 (with the last
two samples taken in CMW-6's replacement well CMW-6R) during eight sampling events from
December 2010 through March 2013, with maximum concentrations of 3,940 µg/L and 4,940
µg/L, respectively; in CMW-8 during two sampling events in April 2012 and in March 2013,
with concentrations of 754 µg/L and, 1,170 µg/L, respectively; and in CW -3 during three
sampling events from October 2011 through March 2012, with a maximum concentration of 947
µg L. Although Boron is a naturally occurring element, its presence in groundwater and
specific occurrence at this site indicates impacts to groundwater resulting from the waste water
treatment and disposal associated with coal burning activities.
142. The Lee Steam Electric Plant Ash Pond Exceedances Chart shows exceedances
from the 2L Groundwater Standard for Chromium (10 µg/L) in CMW-10 during two sampling
events in December 2010 and March 2012, with concentrations of 50.3 µg/L and 20.2 pg/L,
respectively. Although Chromium is a naturally occurring element, its presence in groundwater
and specific occurrence at this site indicates impacts to groundwater resulting from the
wastewater treatment and disposal associated with coal burning activities.
143. Defendant's exceedances of the 2L Groundwater Standards for Arsenic, Boron,
and Chromium at or beyond the compliance boundary of the Lee Steam Electric Plant are
violations of the groundwater standards as prohibited by 15A NCAC 2L .0103(d).
33

Other Exceedances of 2L Groundwater Standards at the Lee Steam Electric Plant
144. The Lee Steam Electric Plant Ash Pond Exceedances Chart shows consistent
exceedances from the 2L Groundwater Standard for Iron (300 gg/L) in compliance well BGMW-
9 during eight sampling events from December 2010 through March 2013, with a maximum
concentration of 2,960 gg/L; in compliance wells CMW-10, CMW-6/CMW-6R, and CMW-7
during eight sampling events from December 2010 through March 2013, with maximum
concentrations of 33,600 gg/L, 11,200 gg/L and 12,400 gg/L, respectively; in compliance well
BW -1 during five sampling events from October 2011 through March 2013, with a maximum
concentration of 26,700 gg/L; in compliance well CMW-5 during six sampling events from
December 2010 through March 2013, with a maximum concentration of 1,140 gg/L; in
compliance well CW -2 during five sampling events from October 2011 through March 2013,
with a maximum concentration of 17,500 gg/L; in compliance well CW -4 during five sampling
events from October 2011 through March 2013; with a maximum concentration of 13,200 gg/L;
in compliance well CTMW-1 during seven sampling events from December 2010 through March
2013, with a maximum concentration of 3,690 gg/L; in compliance wells CW -1 and CW -3
during four sampling events from October 2011 through March 2013, with maximum
concentrations of 8,540 gg/L and 28,600 gg/L, respectively; and in compliance wells BGMW-10
and CMW-8 during one sampling event in March 2013 with maximum concentrations of 6,050
4g/L and 898 gg/L, respectively.
145. The Lee Steam Electric Plant Ash Pond Exceedances Chart consistently shows
exceedances from the 2L Groundwater Standard for Manganese (50 gg/L) in compliance wells
CMW-6/6R and CMW-7 during eight sampling events from December 2010 through March
2013, with maximum concentrations of 936 gg/L and 616 gg/L, respectively; in compliance
wells CMW-10 and CTMW-1 during seven sampling events from December 2010 through
34

March 2013, with maximum concentrations of 732 pg/L and 102 µg/L, respectively; in
compliance well BGMW-9 during six sampling events from December 2010 through October
2012, with a maximum concentration 322 µg/L; in compliance well CMW-5 during five
sampling events from December 2010 through March 2012, with a maximum concentration of
163 µg/L; in compliance wells CW -1, CW -2, CW -3, CW -4, and BW -1 during eight sampling
events from October 2011 through March 2013, with maximum concentrations of 494 µg/L, 205
µg/L, 3,080 µg/L, 1,260 µg/L and 1,130 gg/L, respectively; in compliance well CMW-8 during
two sampling events in March 2012 and March 2013, with concentrations of 51.1 µg/L and
2,340 gg/L, respectively; and in compliance well BGMW-10 during one sampling event in
March 2013, with a concentration of 83 gg/L.
146. The Lee Steam Electric Plant Ash Pond Exceedances Chart shows an exceedance
from the 2L Groundwater Standard for Total Dissolved Solids (500 mg/L) in CW -1 during one
sampling event in March 2012, with a concentration of 1,900 mg/L.
147. The DWR staff is working with the Defendant to determine if these exceedances .
are naturally occurring or if corrective action will be required.
Weatherspoon Steam Electric Plant
148. On March 20, 1980, pursuant to N.C. Gen. Stat. § 143-215.1, other lawful statutes
and regulations issued by the Commission, and the Clean Water Act, the DWQ issued NPDES
Permit No. NC0005363 to Progress Energy for the Weatherspoon Steam Electric Plant
("Weatherspoon Steam Electric Plant NPDES Permit"), located in Robeson County, North
Carolina.
149. The Weatherspoon Steam Electric Plant NPDES Permit has been renewed
subsequently. The current Weatherspoon Steam Electric Plant NPDES Permit was re -issued on
35

November 20, 2009, with an effective date of January 1, 2010, and with an expiration date of
July 31, 2014. A copy of the current Weatherspoon Steam Electric Plant NPDES Permit No.
NC0005363 is attached hereto as Plaintiff's Exhibit No. 17, and is incorporated herein by
reference.
150. The Weatherspoon Steam Electric Plant NPDES Permit authorizes the continued
discharge from a 225 -acre cooling pond ("Ash Pond") under extremely severe weather
conditions, where unavoidable to prevent loss of life, severe property damage, or damage to the
cooling pond structure, or during pond maintenance. The Ash Pond receives recirculated cooling
water, coal pile runoff, storm water runoff, ash sluice water, domestic wastewater, various low
volume wastes including reject water from operation of a reserve osmosis water treatment unit,
and chemical metal cleaning wastewater, discharged from Outfall 001 (potentially).
151. The Weatherspoon Steam Electric Plant NPDES Permit authorizes the continuous
discharge of Non -Contact Cooling Water from heat exchanger units through Outfall 002.
152. The Weatherspoon Steam Electric Plant NPDES Permit authorizes a Stormwater
Discharge System to discharge stormwater from outfalls SW -1, SW -2, and SW -3 into the
Lumber River.
153. The effluent limitations and monitoring requirements in the Weatherspoon Steam
Electric Plant NPDES Permit for the discharge from Outfall 001 (Ash Pond) require sampling for
the following parameters: Flow, Oil and Grease, Total Suspended Solids, Total Copper, Total
Iron, Total Arsenic, Total Selenium pH, Temperature and Acute Toxicity.
154. The effluent limitations and monitoring requirements in the Weatherspoon Steam
Electric Plant NPDES Permit for the discharge from Outfall 002 (Non -Contact Cooling Water
Irr

system) require sampling for the following parameters: Flow, Temperature, Total Residual
Chlorine, Time of Chlorine Addition and pH.
155. The effluent limitations and monitoring requirements in the Weatherspoon Steam
Electric Plant NPDES Permit for the Stormwater Discharge System require sampling for the
following parameters: 40 CFR Part 43 Appendix A 13 Priority Pollutant Metals, Aluminum,
Boron, Chemical Oxygen Demand, Total Suspended Solids, Sulfate, Oil and Grease, pH and
Total Rainfall. Stormwater from the Weatherspoon Plant must also be assessed for qualitative
monitoring requirements, including: • Color, Odor, Clarity, Floating Solids, Suspended Solids,
Foam, Oil Sheen, Erosion or deposition at the outfall and other obvious indicators of stormwater
pollution.
Exceedances in Violation of 2L Groundwater Standards
at the Weatherspoon Steam Electric Plant
A 156. The Aquifer Protection staff of Plaintiff's predecessor division compiled a table
of the analytical results of groundwater samples collected at the Weatherspoon Steam Electric
Plant from November 2010 through July 16, 2013, and prepared a chart of the Ash Pond
Exceedances which are listed in in the Weatherspoon Steam Electric Plant Ash Pond
Exceedances Chart. See Plaintiff s Exhibit No. 10.
157. The Weatherspoon Steam Electric Plant Ash Pond Exceedances Chart shows
exceedances from the alternate 2L Groundwater Standard for Iron (above the naturally occurring
background concentration of 2,040 Rg/L) in compliance wells CW -1 and CW -3 during eight
sampling events from November 2010 through March 2013, with concentrations ranging from
2,060 Rg/L to 4,140 Rg/L; and in monitoring well CW -3 during two sampling events in June
2011 and June 2012, with concentrations of 3,740 Rg/L and 2,120 Rg/L, respectively. Although
Iron is a naturally occurring element, its presence in groundwater and specific occurrence at this
37

site indicates impacts to groundwater resulting from the waste water treatment and disposal
associated with coal burning activities.
158. Defendant's exceedances of the 21, Groundwater Standards for Iron at or beyond
the compliance boundary of the Weatherspoon Steam Electric Plant Ash Pond are violations of
the groundwater standards as prohibited by 15A NCAC 2L.0103(d).
Other Exceedances of 2L Groundwater Standards
at the Weatherspoon Steam Electric Plant
159. The Weatherspoon Steam Electric Plant Ash Pond Exceedances Chart shows an
exceedance from the 2L Groundwater Standard for Thallium (0.2 µg/L) in background
monitoring well BW -1 during one sampling event in June 2012, with a concentration of 0.66
µg/L. Background monitoring well BW -1 is located at the compliance boundary of the Ash Pond
Treatment System at the Weatherspoon Plant. Well BW -1 is located about 600 feet northwest of
the active ash pond. Whether one exceedance of the Thallium standard is sufficient to constitute
a violation is unclear.
160. The Weatherspoon Steam Electric Plant Ash Pond Exceedances Chart shows
exceedances from the 2L Groundwater Standard for Manganese (50 µg/L) in monitoring well
CW -1 during two sampling events in November 2010 and June 2011, with concentrations of 53.4
µg/L and 53.5 gg/L respectively; and in monitoring well CW -3 during one sampling event in
March 2013, with a concentration of 55 µg/L.
161. The DWR staff is working with the Defendant to determine if these exceedances
are naturally occurring or if corrective action will be required.
38

Sutton Electric Plant
162 On June 30, 1977, pursuant to N.C. Gen. Stat. § 143-215.1, other lawful statutes
and regulations issued by the Commission, and the Clean Water Act, the DWQ issued NPDES
Permit No NC0001422 to the Progress Energy for the L. V. Sutton Electric Plant ("Sutton
Electric Plant NPDES Permit"), located in New Hanover County, North Carolina.
163. The Sutton Electric Plant NPDES Permit has been renewed subsequently. The
current Sutton Steam Electric Plant NPDES Permit was re -issued on December 2, 2011, with an
effective date of January 1, 2012, and with an expiration date of December 31, 2016. A copy of
the current Sutton Electric Plant NPDES Permit No. NC0001422 is attached hereto as Plaintiff's
Exhibit No. 18, and is incorporated herein by reference.
164. The Sutton Electric Plant NPDES Permit authorizes the discharge of wastewater
to receiving waters designated as the Cape Fear River in the Cape Fear River Basin in
accordance with the effluent limitations, monitoring requirements and other conditions set forth
in the Sutton Electric Plant NPDES Permit.
165. The Sutton Electric Plant NPDES Permit authorizes the discharge of cooling pond
blowdown, recirculation cooling water, non -contact cooling water and treated wastewater from
Internal Outfalls 002, Internal Outfall 003, and Internal Outfall 004 via Outfall 001, which
discharges directly into the Cape Fear River, Class C -Swamp waters in the Cape Fear River
Basin.
166. The Sutton Electric Plant NPDES Permit authorizes the discharge of coal pile
runoff, low volume wastes, ash sluice water (including wastewater generated from the Rotomix
system), and stormwater through Internal Outfall 002.
MI

167 The Sutton Electric Plant NPDES Permit authorizes the discharge of chemical
metal cleaning waste through Internal Outfall 003. Generally, chemical metal cleaning wastes
are treated by evaporation in boilers.
168 The Sutton Electric Plant NPDES Permit authorizes the discharge of coal pile
runoff, low volume wastes, and stormwater runoff from Internal Outfall 004.
169. The Sutton Electric Plant NPDES Permit authorizes the discharge of ultrafilter
water treatment system filter backwash, closed cooling water cooler blowdown, reverse
osmosis/electrodeionization system reject wastewater and other low volume wastewater to the
Cooling Pond, from new Internal Outfall 005 after beginning operation of a natural gas fired
combined cycle generation facility.
170. The Sutton Electric Plant NPDES Permit authorizes the discharge of low volume
wastewater including the heat recovery steam generator blowdown and auxiliary boiler
blowdown into the cooling pond from the new Internal Outfall 006 after beginning operation of a
natural gas fired combined cycle generation facility.
171. The effluent limitations and monitoring requirements in the Sutton Electric Plant
NPDES Permit for discharges from Outfall 001 require sampling for the following parameters:
Flow, Temperature, Total Residual Chlorine, Time of Chlorine Addition, Total Copper, Total
Nitrogen, Total Phosphorus, Dissolved Oxygen, Acute Toxicity, Total Mercury, pH, Total
Suspended Solids, Total Selenium, and Total Arsenic.
172. The effluent limitations and monitoring requirements in the Sutton Electric Plant
NPDES Permit for discharges from Internal Outfall 002 require sampling for the following
parameters: Flow, Oil and Grease, Total Suspended Solids, Total Arsenic, Total Selenium, and
Amonia-Nitrogen.
40

173. The effluent limitations and monitoring requirements in the Sutton Electric Plant
NPDES Permit for discharges from Internal Outfall 003 require sampling for the following
parameters: Flow, Total Copper and Total Iron.
174. The effluent limitations and monitoring requirements in the Sutton Electric Plant
NPDES Permit for discharges from Outfall 004 require sampling for the following parameters:
Flow, Oil and Grease, Total Suspended Solids, Total Selenium, Total Arsenic and Ammonia -
Nitrogen.
175. The effluent limitations and monitoring requirements in the Sutton Electric Plant
NPDES Permit for Internal Outfall 005 require sampling for the following parameters: Flow, Oil
and Grease, Total Suspended Solids, and pH.
176 The effluent limitations and monitoring requirements in the Sutton Electric Plant
NPDES Permit for Internal Outfall 006 require sampling for the following parameters: Flow, Oil
and Grease, Total Suspended Solids, and pH.
Exceedances in Holation of 2L Groundwater Standards at the Sutton Electric Plant
177. The groundwater monitoring requirements in the Sutton Electric Plant NPDES
Permit require sampling the following compliance wells MW -4B (background), MW -5C
(background), MW -7C, MW -11, MW -12, MW -19, MW -21C, MW -22B, MW -22C, MW -2313,
MW -23C, MW -24B, MW -24C, MW -27B, MW -28B, MW -28C and MW -31C. All current wells
being sampled are located at or beyond the Compliance Boundary. Prior to October 24, 2012,
the groundwater monitoring requirements in the Sutton Electric Plant NPDES Permit required
sampling the following wells MW -2C, MW -413 (background), MW -5C (background), MW -6C,
MW -7C, MW -8, MW -9, MW -10, MW -11, MW -12, MW -17, MW -18, and MW -19. Some wells
sampled prior to October 24, 2012, were located inside the Compliance Boundary.
41

178. Plaintiffs Aquifer Protection staff compiled a table of the analytical results of
groundwater samples collected at the Sutton Electric Plant from March 2010 through July 16,
2013, and prepared a chart of the Ash Pond Exceedances which are listed in in the Sutton
Electric Plant Ash Pond Exceedances Chart. See Plaintiff s Exhibit No. 11.
179. The Sutton Electric Plant Ash Pond Exceedances Chart shows exceedances from
the 2L Groundwater Standard for Thallium (0.2 4g/L) in compliance wells MW -19 during four
sampling events from October 2011 through March 2013, with a maximum concentration of 0.62
µg/L; and in compliance wells MW -22C and MW -24B during two sampling events in October
2012 and March 2013, with maximum concentrations of 0.35 µg/L and 0.586 gg/L, respectively.
Although Thallium is a naturally occurring element, its presence in groundwater and specific
occurrence at this site indicates impacts to groundwater resulting from the wastewater treatment
and disposal associated with coal burning activities.
180. The Sutton Electric Plant Ash Pond Exceedances Chart shows exceedances from
the 2L Groundwater Standard for Antimony (1 µg/L) in compliance well MW -24B during two
sampling events in October 2012 and March 2013 with a maximum concentration of 1.1 gg/L.
Although Antimony is a naturally occurring element, its presence in groundwater and specific
occurrence at this site indicates impacts to groundwater resulting from the wastewater treatment
and disposal associated with coal burning activities.
181. The Sutton Electric Plant Ash Pond Exceedances Chart shows exceedances from
the 2L Groundwater Standard for Boron (700 µg/L) in compliance well MW -7C during two
sampling events in March 2012 and June 2012, with a maximum concentration of 767 µg/L; in
compliance well MW -12 during four sampling events from March 2012 through March 2013,
with a maximum concentration of 1,510 gg/L; in MW -19 during five sampling events from
42

October 2011 through March 2013, with a maximum concentration of 1,940 pg/L; in compliance
well MW -21 C during two sampling events in October 2012 and March 2013, with a maximum
concentration of 1,720 µg/L; in compliance well MW -22C during two sampling events in
October 2012 and March 2013, with a maximum concentration of 2,100 µg/L; in compliance
well MW -23B during two sampling events in October 2012 and March 2013 with a maximum
concentration of 1,330 µg/L; in compliance well MW -23C during two sampling events in
October 2012 and March 2013, with a maximum concentration of 2,580 µg/L; in compliance
well MW -24B during two sampling events from in October 2012 and March 2013, with a
maximum concentration of 1,420 gg/L; in compliance well MW -24C during two sampling
events in October 2012 and March 2013, with a maximum concentration of 1,160 µg/L; in
compliance well MW -28C during one sampling event in March 2013, with a concentration of
1,030 gg/L; and in compliance well MW -31C during sampling events in October 2012 and
March ,2013, with a maximum concentration of 1,120 gg/L. Although Boron is a naturally
occurring element, its presence in groundwater and specific occurrence at this site indicates
impacts to groundwater resulting from the wastewater treatment and disposal associated with
coal burning activities.
182. The Sutton Electric Plant Ash Pond Exceedances Chart shows exceedances from
the 2L Groundwater Standard for Selenium (20 pg/L) in compliance well MW -27B during two
sampling events in October 2012 and March 2013, with a maximum concentration of 37.1
pg/L. Although Selenium is a naturally occurring element, its presence in groundwater and
specific occurrence at this site indicates impacts to groundwater resulting from the wastewater
treatment and disposal associated with coal burning activities.
43

183. The Sutton Electric Plant Ash Pond Exceedances Chart shows exceedances from
the 2L Groundwater Standard for Total Dissolved Solids (500 mg/L) at compliance well MW -
24C during two sampling events from October 2012 to March 2013, with a maximum
concentration of 579 mg/L. The presence of Total Dissolved Solids in groundwater and the
specific occurrence at this site indicates impacts to groundwater resulting from the wastewater
treatment and disposal associated with coal burning activities.
184. The Sutton Electric Plant Ash Pond Exceedances Chart shows exceedances from
the 2L Groundwater Standard for Sulfate (250 mg/L) in compliance well MW -21C during one
sampling event in October 2012, with a concentration of 814 mg/L. Although Sulfate is a
naturally occurring compound, its presence in groundwater and specific occurrence at this site
indicates impacts to groundwater resulting from the waste water treatment and disposal
associated with coal burning activities.
185. The Sutton Electric Plant Ash Pond Exceedances Chart consistently shows
exceedances from the 2L GW standard for Manganese (50 µg/L) in compliance well MW -7C
during four sampling events from March 2012 through March 2013, with a maximum
concentration of 458 gg/L); in compliance well MW -12 during four sampling events from March
2012 through March 2013, with a maximum concentration of 281 gg/L; in compliance well
MW -19 during three sampling events from October 2011 through March 2013, with a maximum
concentration of 508 µg/L; in compliance well MW -21C during two sampling events in October
2012 and March 2013, with a maximum concentration of 1,460 µg/L; in compliance well MW -
22B during one sampling event in October 2012, with a concentration of 116 gg/L; and in
compliance wells MW -22C, MW -23B, MW -23C, MW 24B, MW -24C, MW -28C, and MW -31C
during two sampling events in October 2012 and March 2013, with maximum concentrations of
44

798 µg/L, 348 µg/L, 1,150 pg/L, 805 gg/L, 2,360 µg/L, 367 gg/L and 1,800 µg/L, respectively.
Although Manganese is a naturally occurring element, its presence in groundwater and specific
occurrence at this site indicates impacts to groundwater resulting from the wastewater treatment
and disposal associated with coal burning activities.
186. The Sutton Electric Plant Ash Pond Exceedances Chart consistently shows
exceedances from the 2L Groundwater Standard for Iron (3 00 gg/L) in compliance well MW -11
during one sampling event in March 2011 with a concentration of 420 gg/L; in compliance well
MW -21C during two sampling events in October 2012 and March 2013, with a maximum
concentration of 7,680 µg/L; in compliance well MW -24C during one sampling event in October
2012, with a concentration of 2,860 pg/L; and in compliance well MW -31 C during two sampling
events in October 2012 and March 2013, with a maximum concentration of 2,820 µg/L.
Although Iron is a naturally occurring element, its presence in groundwater and specific
occurrence at this site indicates impacts to groundwater resulting from the waste water treatment
and disposal associated with coal burning activities.
187. The Sutton Electric Plant Ash Pond Exceedances Chart shows an exceedance
from the 2L Groundwater Standard for Lead (15 gg/L) in compliance well MW -12 during one
sampling event in March 2012, with a concentration of 17.3 µg/L. Although Lead is a naturally
occurring element, its presence in groundwater and specific occurrence at this site indicates
impacts to groundwater resulting from the wastewater treatment and disposal associated with
coal burning activities.
188. The Sutton Electric Plant Ash Pond Exceedances Chart shows an exceedance
from the 2L Groundwater Standard for Arsenic (10 gg/L) in compliance well MW -21C during
one sampling event in March 2013, with a concentration of 15 pg/L. Although Arsenic is a
45

naturally occurring element, its presence in groundwater and specific occurrence at this site
indicates impacts to groundwater resulting from the waste water treatment and disposal
associated with coal burning activities.
189. Defendant's exceedances of the 2L Groundwater Standards for Thallium,
Antimony, Boron, Selenium, Total Dissolved Solids, Sulfate, Manganese, Iron, Lead and
Arsenic at or beyond the compliance boundary of the Sutton Electric Plant Ash Ponds are
violations of the groundwater standards as prohibited by 15A NCAC 2L.0103(d).
Risk Factors Due to Exceedances of the 2L Groundwater Standards
at the Sutton Electric Plant
190. Violations above 2L Groundwater Standards have been measured in compliance
wells MW -7C, MW -19, MW -21C, MW -22B, MW -22C, MW -23B, MW -23C, and MW -28C
which are located upgradient of two water supply wells (PW#3 and PW#4) serving the New
Hanover Water System identified as CFPUA/NHC-42 i (No. NC0465191). Water supply wells
PW#3 and PW#4 are located approximately 2,200 feet from the compliance boundary or
approximately 2,700 feet from the edge of the ash ponds.
191. Compliance well MW -7C has shown violations of the 2L Groundwater Standards
for Boron, Iron, and Manganese. Compliance well MW -19 has shown pH, Boron, iron,
Manganese, and Thallium violations. Compliance well MW -21 C has shown violations Sulfate,
Arsenic, Boron, Iron, and Manganese. Compliance well MW -22B has shown pH and
Manganese violations. Compliance well MW -22C has shown pH, Boron, Iron, Manganese, and
Thallium violations. Compliance well MW -23B has shown pH, Boron, and Manganese
violations. Compliance well MW -28C has shown pH, Boron, and Manganese.
46

Other Exceedances of the 2L Groundwater Standards at the Sutton Electric Plant
192. The Sutton Electric Plant Ash Pond Exceedances Chart shows exceedances from
the 2L Groundwater Standard for Manganese (50 µg/L) in compliance well MW -10 during four
sampling events from October 2011 to June 2012, with a maximum concentration of 96.7 µg/L;
in compliance well MW -11 during four sampling events from March 2012 through March 2013,
with a maximum concentration of 99.6 gg/L; in compliance well MW -27B during two sampling
events in October 2012 and March 2013, with a maximum concentration of 229 pg/L; in
background well MW -4B during one sampling event in June 2012, with a concentration of 265
µg/L; and in background well MW -5C during four sampling events from March 2012 to March
2013, with a maximum concentration of 447 µg/L.
193. The Sutton Electric Plant Ash Pond Exceedances Chart shows exceedances from
the 21, Groundwater Standard for Iron (300 µg/L) in compliance well MW -7C during two
sampling events in March 2012 and June 2012, with a maximum concentration of 707 µg/L; in
compliance well MW -12 during four sampling events from March 2011 to October 2012, with a
maximum concentration of 1,490 gg/L; in compliance well MW -19 during one sampling event
in March 2010, with a concentration of 322 µg/L; in compliance well MW22-C during one
sampling event in March 2013, with a concentration of 431 µg/L; in background well MW -4B
during eight sampling events from March 2010 through March 2013, with a maximum
concentration of 1,650 µg/L.
194. The Sutton Electric Plant Ash Pond Exceedances Chart consistently shows
exceedances from the 2L Groundwater Standard for pH (6.5-8.5) in compliance wells MW -5C,
MW -7C, MW -10, MW -11, MW -12, MW -19, MW -22B, MW -22C, MW -23B, MW -23C, MW -
47

24B, MW -24C, MW -27B, MW -28C, and MW -31C during eight sampling events from March
2010 through March 2013 with levels ranging from 4.5 to 6.47.
195. The DWR staff is working with the Defendant to determine if these exceedances
are naturally occurring or if corrective action will be required.
CLAIMS FOR RELIEF
196. The allegations contained in paragraphs 1 through 195 are incorporated into these
claims for relief as if fully set forth herein.
197. With the exception of the Weatherspoon Steam Electric Plant and the Sutton
Electric Plant, which have no unpermitted seeps, Defendant's unpermitted seeps from the 4 of
the 6 Facilities (Mayo, Roxboro, Cape Fear and Lee) are violations of N.C. Gen. Stat. §§ 143-
215.1(a)(1) and (a)(6).
198. Defendant's exceedances of the groundwater standards for Sulfate at or beyond
the compliance boundary of the Roxboro Steam Electric Plant Ash Pond are violations of the 2L
Groundwater Standards as prohibited by 15A NCAC 2L.0103(d).
199. Defendant's exceedances of the groundwater standards for Boron, Selenium and
Sulfate at or beyond the compliance boundary of the Cape Fear Steam Electric Plant Ash Ponds
are violations of the 2L Groundwater Standards as prohibited by 15A NCAC 2L.0103(d).
200. Defendant's exceedances of the groundwater standards for Arsenic, Boron, and
Chromium at or beyond the compliance boundary of the Lee Steam Electric Plant Ash Ponds
Treatment System are violations of the 2L Groundwater Standards as prohibited by 15A NCAC
2L.4103 (d).
48

201. Defendant's exceedances of the groundwater standards for Iron at or beyond the
compliance boundary of the Weatherspoon Steam Electric Plant Ash Pond are violations of the
2L Groundwater Standards as prohibited by 15A NCAC 2L.0103(d).
202. Defendant's exceedances of the groundwater standards for Thallium, Antimony,
Boron, Selenium, Total Dissolved Solids, Sulfate, Manganese, Iron, Lead and Arsenic at or
beyond the compliance boundary of the Sutton Electric Plant Ash Ponds are violations of the 2L
Groundwater Standards as prohibited by 15A NCAC 2L.0103(d).
203. 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.
204. Defendant's violations of N.C. Gen. Stat. §§ 143-215.1(a)(1) and (a)(6) for the
unpermitted seeps and Defendant's violations and potential violations of the 2L 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 6 Facilities;
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
49

Assessment Needs", which is attached hereto as Plaintiffs Exhibit No. 19, 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.
Respectfully submitted, this the � d�f August, 2013.
ROY COOPER
By
Yatlh!�*nes Co per
Special puty At orneyLeral
NC State B . 12176
per .
By
onald W. Caton
Assistant Attorney General
5tate
B o. 3
d '
By
Anita LeVea
Assistant Attorney General
NC State Bar No. 13667
[e-mail]
By Jk4-.,,�
eJ e L. Oliver
ssistant Attorney General
NC State Bar No. 16771
[e-mail]
N.C. Department of Justice
Environmental Division
Post Office Box 629
Raleigh, NC 27602-0629
[phone] phone
[phone] facsimile
Attorneys for the Plaintiff
State of North Carolina ex rel.
North Carolina Department of
Environment and Natural Resources
50

EXHIBIT 2
Sutton NPDES Permit NC0001422
December 7, 2015

Permit NC0001422 If
STATE OF NORTH CAROLINA
DEPARTMENT OF ENVIRONMENT AND NATURAL RESOURCES
DIVISION OF WATER RESOURCES
PERMIT
TO DISCHARGE WASTEWATER UNDER THE
NATIONAL POLLUTANT DISCHARGE ELIMINATION SYSTEM
In compliance with the provisions of North Carolina General Statute 143-215.1, other lawful
standards and regulations promulgated and adopted by the North Carolina Water Quality
Commission, and the Federal Water Pollution Control Act, as amended,
Duke Energy Progress, LLC
is hereby authorized to discharge wastewater from a facility located at the
L. V. Sutton Energy Complex
801 Sutton Steam Plant Road, Wilmington
New Hanover County
to receiving waters designated as the Cape Fear River and Sutton Lake in the Cape Fear
River Basin in accordance with the discharge limitations, monitoring requirements, and
other applicable conditions set forth in Parts I, II, III, and Appendix A.
This permit modification shall become effective December 7, 2015.
This permit and the authorization to discharge shall expire at midnight on December 31,
2016.
Signed this day December 3, 2015.
Original signed by S. Jay Zimmerman
S. Jay Zimmerman P.G., Director
Division of Water Resources
By the Authority of the Environmental Management Commission
Page 1 of 19

Permit NC0001422
SUPPLEMENT TO PERMIT COVER SHEET
All previous NPDES Permits issued to this facility, whether for operation or discharge are hereby
revoked As of this permit issuance, any previously issued permit bearing this number is no longer
effective. Therefore, the exclusive authority to operate and discharge from this facility arises under
the permit conditions, requirements, terms, and provisions included herein
Duke Energy Progress, LLC is hereby authorized to:
1. Continue to discharge cooling water, low volume wastes, stormwater, and
treated wastewater from internal wastewater outfalls 005, 006, 007, and 009
to the Effluent Channel, and internal stormwater outfalls SW001, SW002,
SW003, SW004, SW005, SW006, and SWO07 to the Effluent Channel (the
Effluent Channel discharges via external Outfall 008 to the Sutton Lake); ash
pond discharge, groundwater, treated wastewater, and stormwater runoff
(Outfall 001, Outfall 002 and Outfall 004); at a facility located at Sutton Steam
Electric Plant, 801 Sutton Steam Plant Road, Wilmington, New Hanover
County, and
2. Discharge wastewater (via Outfall 002, Outfall 004, and Outfall 008) from said
treatment works at the locations specified on the attached map into the Sutton
Lake which is classified C waters in the Cape Fear River Basin.
3. Discharge wastewater and groundwater (via Outfall 001) from said treatment
works at the location specified on the attached map into the Cape Fear River,
classified C -Swamp waters in the Cape Fear River Basin.
Page 2 of 19

Permit NC0001422
Part I
A. (1.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall 001 -
normal operation)? [15A NCAC 02B 0400 et seq , 02B 0500 et seq.]
During the period beginning on the effective date of the permit and lasting until expiration, the
Permittee is authorized to discharge to the Cape Fear River from Outfall 001 - removing the free
water above the settled ash layer that does not involve mechanical disturbance of the ash
(recirculation cooling water, non -contact cooling water, and treated wastewater from outfalls
002, and 004). Such discharges shall be limited and monrtored6 by the Permittee as specified
below
EFFLUENT
CHARACTERISTICS
LIMITS
MONITORING REQUIREMENTS
Monthly
Average
Daily
Maximum
Measurement Sample Sample
Frequency Type Location'
Flow, MGD
Daily
Estimate or
pump logs
Effluent
Tem erature1,2, OC
Quarterly
Grab
U, D
Temperature2, °C
Daily
Grab
Effluent
pH
6 0s
H< 9 0
Weekly
Grab
Effluent
Oil and Grease
15.0 mg/L
20 0 mg/L
Weekly
Grab
Effluent
Total Suspended Solids,
mg/L
30.0 mg/L
100 0 mg/L
Weekly
Grab
Effluent
Total Nitrogen
NO2 + NO3 + TKN , mg/L
Weekly
Grab
Effluent
Total Phosphorus, mg/L
Weekly
Grab
Effluent
Dissolved Oxygen, mg/L
Weekly
Grab
Effluent
Acute Toxicrty3
Monthly
Grab
Effluent
Total Mercury4
47 0 ng/L
47 0 ng/L
Weekly
Grab
Effluent
Total Arsenic
10 0 pg/L
50 0 pg/L
Weekly
Grab
Effluent
Total Selenium
5.0 µg/L
56 0 µg/L
Weekly
Grab
Effluent
Total Iron
1 0 mg/L
1.0 mg/L
Weekly
Grab
Effluent
Total Lead
25.0 µ L
33.8 µ L
Weekly
Grab
Effluent
Total Cadmium
2 0 µ L
15 0 µ L
Weekly
Grab
Effluent
Total Aluminum
Weekly
Grab
Effluent
Total Copper, L
Weekly
Grab
Effluent
Total Zinc, L
Weekly
Grab
Effluent
Turbidity5
Weekly
Grab
Effluent
Notes:
1 U- Upstream, 2700 feet above outfall D. Downstream, 1 25 miles below outfall.
2 The receiving water's temperature shall not be increased by more than 2.8'C above ambient
water temperature and in no case exceed 32'C, except in the mixing zone described as follows.
Extending from the eastern shore to the centerline of the river and extending not more than
1.25 miles downstream nor more than 2700 feet from the point of discharge The cross-
sectional area of the mixing zone shall not exceed 9% of the total cross sectional area of the river
at the point of discharge nor 2.5% at the mouth of Toomer's Creek
3 Acute Toxicity Limit (Fathead Minnow, 24 hour at 90%); Part I, Condition A. (10.)
4 The facility shall use EPA method 163 IE
5 The discharge from this facility shall not cause turbidity in the receiving stream to exceed 50
NTU If the instream turbidity exceeds 50 NTU due to natural background conditions, the
discharge cannot cause turbidity to increase in the receiving stream
6 No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system See Special
Condition A (23.)
7 The drawdown rate shall not exceed 1 foot/week to maintain the integrity of the dams, unless
approved by the DEQ Dam Safety Program
There shall be no discharge of floating solids or visible foam in other than trace amounts.
Page 3 of 19

Permit NC0001422
A. (2.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
001 -dewatering phase)$ [15A NCAC 02B .0400 et seq., 02B .0500 et seq.]
During the period beginning on the commencement date of the dewatering operation and lasting
until expiration, the Permittee is authorized to discharge to the Cape Fear River from Outfall 001
Dewatering -removing the interstitial water/ash pore water (recirculation cooling water, non -
contact cooling water, and treated wastewater from outfalls 002, and 004). Such discharges
shall be limited and monitored6 by the Permittee asspecified below:
EFFLUENT
CHARACTERISTICS
LIMITS
MONITORING REQUIREMENTS
Monthly
Average
Daily
Maximum
Measurement Sample Sample
Frequency Tye Location'
Flow
2 1 MGD
(applies only to ash
pond (lischarge)
Daily
Estimate
Or pump
logs
Effluent
Tem erature1,2, OC
Quarterly
Grab
U, D
Tem erature2, OC
Daily
Grab
Effluent
H
6.0s
H <_ 9.0
Daily
Daily
Effluent
Oil and Grease
15.0 m L
20 0 m L
Weekly
Grab
Effluent
Total Suspended Solids
mg L7
30.0 mg/L
100.0 mg/L
Weekly
Grab
Effluent
Total Nitrogen
NO2 + NOs + TKN , m L
Weekly
Grab
Effluent
Total Phos horus, mg/L
Weekly
Grab
Effluent
Dissolved Oxygen, mg/L
Weekly
Grab
Effluent
Acute Toxicity3
Monthly
Grab
Effluent
Total Iron
1.0 m L
1 0 m L
Weekly
Grab
Effluent
Total Cadmium
2.0 µ L
15.0 µ L
Weekly
Grab
Effluent
Total Aluminum
Weekly
Grab
Effluent
Total Lead
25.0 µg L
33.8 µg L
Weekly
Grab
Effluent
Total Arsenic
10.0 pg/L
50.0 pg/L
Weekly
Grab
Effluent
Total Selenium
5 0 µ L
56.0 µ L
Weekly
Grab
Effluent
Total Mercury4
47.0 n L
47.0 n L
Weekly
Grab
Effluent
Total Copper, µ L
Weekly
Grab
Effluent
Total Zinc,µ L
Weekly
Grab
Effluent
Turbichty5
Weekly
Grab
Effluent
Notes•.
1. U- Upstream, 2700 feet above outfall D: Downstream, 1.25 miles below outfall.
2. The receiving water's temperature shall not be increased by more than 2.8°C above ambient
water temperature and in no case exceed 32°C, except in the mixing zone described as follows
Extending from the eastern shore to the centerline of the river and extending not more than
1.25 miles downstream nor more than 2700 feet from the point of discharge. The cross-
sectional area of the mixing zone shall not exceed 9% of the total cross sectional area of the river
at the point of discharge nor 2.5% at the mouth of Toomer's Creek.
3 Acute Toxicity Limit (Fathead Minnow, 24 hour at 90%), Part I, Condition A. (10.).
4. The facility shall use EPA method 1631E.
5. The discharge from this facility shall not cause turbidity in the receiving stream to exceed 50
NTU. If the mstream turbidity exceeds 50 NTU due to natural background conditions, the
discharge cannot cause turbidity to increase in the receiving stream.
6. No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system See Special
Condition A. (23 ).
7. The facility shall continuously monitor TSS concentration and the dewatering pump shall be
shutoff automatically when the limits are exceeded.
8 The drawdown rate shall not exceed 1 foot/week to maintain the integrity of the dams, unless
approved by the DEQ Dam Safety Program.
There shall be no discharge of floating solids or visible foam in other than trace amounts.
Page 4 of 19

Permit NC0001422
A. (3.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
002 -normal operation)4, 5
[15A NCAC 02B .0400 et seq., 02B .0500 et seq.]
During the period beginning on the effective date of the permit and lasting until expiration, the
Permittee is authorized to discharge to Sutton Lake and/or to the 1971 ash pond from Outfall 002 -
removing of free water above the settled ash layer that does not involve mechanical disturbance of
the ash (Old Ash Pond - coal pile runoff, low volume wastes, ash sluice water, and stormwater
runoff). Such discharges to Sutton Lake shall be limited and monrtored3 by the Permittee as specified
below:
EFFLUENT
CHARACTERISTICS
LIMITS
MONITORING REQUIREMENTS
Monthly Daily
Average Maximum
Measurement Sample
Frequency Type
Sample Location
Flow, MGD
Weekly
Pump Logs
or similar
Effluent
Oil and Grease
15.0 mg/L
20.0 mg/L
Weekly
Grab
Effluent
Total Suspended
Solids
30.0 mg/ L
100 0 mg/ L
Weekly
Grab
Effluent
H
6.0:-<
pH s 9.0
Weekly
Grab
Effluent
Total Copper, pg/L
Weekly
Grab
Effluent
Total Zinc, pg/L
Weekly
Grab
Effluent
Total Arsenic
10.0 µg/L
50.0 µg/L
Weekly
Grab
Effluent
Total Selenium
5.0 µg/L
56 0 µg/L
Weekly
Grab
Effluent
Total Mercury
47.0 ng/L
47 0 ng/L
Weekly
Grab
Effluent
Total Iron
1.0 mg/L
1 0 mg/L
Weekly
Grab
Effluent
Total Aluminum
Weekly
Grab
Effluent
Chronic Toxicity a
Quarterly
Grab
Effluent
Notes:
1 The facility shall use EPA method 1631E.
2. Chronic Toxicity Limit (Cenodaphnia dubia at 90%); Part I, Condition A. (21.).
3. No later than 270 days from the effective date of this permit, begin submittmg discharge
monitoring reports electronically using NC DWR's eDMR application system. See Special
Condition A. (23 )
4. The facility shall submit EPA Form 2C for Outfall 002 as soon as practicable, but no later than
180 days from the effective date of this permit.
5. The drawdown rate shall not exceed 1 foot/week to maintain the integrity of the dams, unless
approved by the DEQ Dam Safety Program
There shall be no discharge of floating solids or visible foam in other than trace amounts.
Page 5 of 19

Permit NC0001422
A. (4.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
004 -normal operation)4, s
[15A NCAC 02B 0400 et seq , 02B 0500 et seq ]
During the period beginning on the effective date of the permit and lasting until expiration, the
Permittee is authorized to discharge to Sutton Lake and/or to Outfall 001 from Outfall 004 -
removing of free water above the settled ash layer that does not involve mechanical disturbance of
the ash (New Ash Pond - ash sluice water, coal pile runoff, low volume wastes, and stormwater
runoff) Such discharges to Sutton Lake shall be limited and monrtored3 by the Permittee as specified
below
EFFLUENT
CHARACTERISTICS
LIMITS
MONITORING REQUIREMENTS
Monthly Daily
Average Maximum
Measurement
Frequency
Sample
Type
Sample
Location
Flow, MGD
Weekly
Pump Logs
or similar
Effluent
Oil and Grease
15 0 mg/L 20.0 mg/L
Weekly
Grab
Effluent
Total Suspended
Solids
30 0 mg/L 100.0 mg/L
Weekly
Grab
Effluent
H
6 0:5 0< 9 0
Weekly
Grab
Effluent
Total Copper, pg/L
Weekly
Grab
Effluent
Total Zinc, pg/L
Weekly
Grab
Effluent
Total Arsenic
10.0 pg/L 50.0 pg/L
Weekly
Grab
Effluent
Total Selenium
5 0 pg/L 56 0 pg/L
Weekly
Grab
Effluent
Total Mercury'
47 0 ng/L 47 0 ng/L
Weekly
Grab
Effluent
Total Iron
1.0 m L 1 0 m L
Weekly
Grab
Effluent
Total Aluminum
Weekly
Grab
Effluent
Chronic Toxicity 2
Quarterly
I Grab
Effluent
Notes:
1. The facility shall use EPA method 1631E.
2. Chronic Toxicity Limit (Cenodaphnia dubta at 90%), Part I, Condition A (21).
3 No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system. See Special
Condition A (23 ).
4. The facility shall submit EPA Form 2C for Outfall 004 as soon as practicable, but no later than
180 days from the effective date of this permit
5 The drawdown rate shall not exceed 1 foot/week to maintain the integrity of the dams, unless
approved by the DEQ Dam Safety Program.
There shall be no discharge of floating solids or visible foam in other than trace amounts.
Page 6 of 19

Permit NC0001422
A. (5.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
005)
[15A NCAC 02B .0400 et seq , 02B .0500 et seq ]
Beginning with the commencement of this discharge and lasting until expiration, the Permittee is
authorized to discharge from Internal Outfall 005 (Combined Cycle Plant - ultrafilter water
treatment system filter backwash, closed cooling water cooler blowdown, Reverse
Osmosis/Electrodeionization system reject wastewater, and other low volume wastewater) to
the Effluent Channel. Such discharges shall be limited and monitored' by the Permittee as
specked below -
Notes:
1. No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system. See Special
Condition A (23 ).
There shall be no discharge of floating solids or visible foam in other than trace amounts.
A. (6.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
006)
[15A NCAC 02B 0400 et seq., 02B .0500 et seq.]
Beginning with the commencement of this discharge and lasting until expiration, the Permittee is
authorized to discharge from Internal Outfall 006 (Combined Cycle Plant - low volume
wastewater including the Heat Recovery Steam generator blowdown and auxiliary boiler
blowdown) to the Effluent Channel. Suca discharges shall be limited and monitored' by the
Permittee as specified below.
EFFLUENT LIMITATIONS
MONITORING REQUIREMENTS
EFFLUENT
Monthly
Daily
Monthly
Daily
Measurement
Sample
Sample
CHARACTERISTICS
Average
Maximum
Frequency
Type
Location
Flow, MGD
Daily
Pump Logs or
Daily
Pump Logs or
Influent or
Effluent
similar
Effluent
similar
15 0 mg/L
Oil and Grease
15.0 mg/L
20.0 mg/L
2/Month
Grab
Effluent
Total Suspended Solids
30 0 mg/L
100.0 mg/L
2/Month
Grab
Effluent
PH
6.0 < pH <90
2/Month
Grab
Effluent
Notes:
1. No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system. See Special
Condition A (23 ).
There shall be no discharge of floating solids or visible foam in other than trace amounts.
A. (6.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
006)
[15A NCAC 02B 0400 et seq., 02B .0500 et seq.]
Beginning with the commencement of this discharge and lasting until expiration, the Permittee is
authorized to discharge from Internal Outfall 006 (Combined Cycle Plant - low volume
wastewater including the Heat Recovery Steam generator blowdown and auxiliary boiler
blowdown) to the Effluent Channel. Suca discharges shall be limited and monitored' by the
Permittee as specified below.
Notes•.
1.No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system. See Special
Condition A (23 ).
There shall be no discharge of floating solids or visible foam in other than trace amounts.
Page 7of19
EFFLUENT LIMITATIONS
MONITORING REQUIREMENTS
EFFLUENT
Monthly
Daily
Measurement
Sample
Sample
CHARACTERISTICS
Average
Maximum
Frequency
Type
Location
Flow, MGD
Daily
Pump Logs or
Influent or
similar
Effluent
Oil and Grease
15 0 mg/L
20.0 mg/L
2/Month
Grab
Effluent
Total Suspended Solids
30 0 mg/ L
100.0 mg/ L
2/Month
Grab
Effluent
PH
6.0 < pH < 9.0
2/Month
Grab
Effluent
Notes•.
1.No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system. See Special
Condition A (23 ).
There shall be no discharge of floating solids or visible foam in other than trace amounts.
Page 7of19

Permit NC0001422
A. (7.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
007)
[15A NCAC 02B 0400 et seq., 02B.0500 et seq ]
During the period beginning on the effective date of the permit and lasting until expiration, the
Permittee is authorized to discharge from Internal Outfall 007 (stormwater flows from the closure
activities for coal-fired units, separate from stormwater outfalls SWO01 through SWO07) to the
Effluent Channel. Such discharges shall be limited and monrtored2 by the Permittee as specified
below:
EFFLUENT
LIMITS
MONITORING REQUIREMENTS
CHARACTERISTICS
Monthly
Daily
Measurement
Sample
Sample
Average
Maximum
Fre uency
Tye
Location
Flow, MGD
Weekly
Pump Logs
Effluent
or similar
Oil and Grease
15.0 mg/L
20.0 mg/L
Monthly
Grab
Effluent
Total Suspended
30.0 mg/L
100.0 mg/L
Monthly
Grab
Effluent
Solids
Total Arsenic, pg/L
6.0 < pH <90
2/Month
Quarterly
Grab
Effluent
Total Selenium, jig/L
Quarterly
Grab
Effluent
Nitrate/nitrite as N,
Quarterly
Grab
Effluent
mg/L
Total Mercury', ng/L
Quarterly
Grab
Effluent
Notes:
1. The facility shall use EPA method 1631E.
2 No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system. See Special
Condition A. (23.).
There shall be no discharge of floating solids or visible foam in other than trace amounts.
A. (8.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
009)
[15A NCAC 02B 0400 et seq., 02B .0500 et seq.]
During the period beginning on the effective date of the permit and lasting until expiration, the
Permittee is authorized to discharge from Internal Outfall 009 (low volume wastes from a new
simple cycle combustion turbine) to the Effluent Channel Such discharges shall be limited and
monitored' by the Permittee as specified below:
EFFLUENT
LIMITS
MONITORING REQUIREMENTS
CHARACTERISTICS
Monthly
Daily
Measurement
Sample
Sample
Average
Maximum
Frequency
a
Location
Flow, MGD
Weekly
Pump Logs
Effluent
or similar
Oil and Grease
15.0 m L
20.0 m L
Monthly
Grab
Effluent
Total Suspended
30.0 mg/L
100.0 mg/L
Monthly
Grab
Effluent
Solids
PH
6.0 < pH <90
2/Month
Grab
Effluent
Notes:
1.. No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system. See Special
Condition A. (23.).
There shall be no discharge of floating solids or visible foam in other than trace amounts.
Page 8 of 19

Permit NC0001422
A. (9.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
008)5,7
[15A NCAC 02B 0400 et seq , 02B .0500 et seq ]
During the period beginning on the effective date of the permit and lasting until expiration, the
Permittee is authorized to discharge to Sutton Lake from Outfall 008 (from internal wastewater
outfalls 005, 006, 007, and 009, and internal stormwater outfalls SWO01 through SWO07)
Such discharges shall be limited and momtored6 by the Permittee as specified below
EFFLUENT
CHARACTERISTICS
LIMITS
MONITORING REQUIREMENTS
Monthly
Average
Daily
Maximum
Measurement Sample Sample
Fre Type Location'
Flow, MGD
Daily
Estimate
or pump
logs
Effluent
Temperature °C
Daily
Grab
Effluent
Temperature 1,2, OC
Daily Weekly
Grab
Instream
Oil and Grease
15 0 mg/L
20 0 mg/L
Monthly
Grab
Effluent
Total Suspended Solids
30 0 m L
100.0 mg/L
Monthly
Grab
Effluent
Total Nitrogen
NO2 + NO3 + TKN , m L
Monthly
Grab
Effluent
Dissolved Oxygen, m L
Monthly
Grab
Effluent
H
6 0<_ pH <_ 9 0
Daily
Grab
Effluent
Total Phosphorus, mg/L
Monthly
Grab
Effluent
Chronic Toxicrty3
Quarterly
Grab
Effluent
Total Mercury4, ng/L
Quarterly
Grab
Effluent
Total Arsenic, pg/L
Quarterly
Grab
Effluent
Total Selenium, 4g/L
Quarterly
Grab
Effluent
Total Copper, pg/L
Quarterly
Grab
Effluent
Total Zinc, µ L
Quarterly
Grab
Effluent
Notes:
1. Instream: 1000 feet from outfall The facility is allowed 12 months from the effective date of
the permit to begin daily instream temperature monitoring The time is allowed for the
facility to budget, design, and install the automatic monitoring station. In the interim, the
instream temperature monitoring shall be conducted on a weekly basis
2 The receiving water's temperature shall not be increased by more than 2 8°C above ambient
water temperature and in no case exceed 32°C The limit is not being implemented until
further notice (Please see A (26 )).
3 Chronic Toxicity Limit (Ceriodaplima dubta at 90%); Part I, Condition A (21.)
4 The facility shall use EPA method 1631E
5 The facility shall install a screen or a barrier at the end of the Effluent Channel to minimize
fish migration .into the Channel. The design of the screen/barrier shall be submitted to the
Division for approval no later than 6 month from the effective date of the permit The
screen/barrier shall be installed no later than 6 months after Division approval
6. No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system See Special
Condition A (23.)
7. The facility shall submit EPA Form 2C for Outfall 008 as soon as practicable, but no later
than 180 days from the effective date of this permit
There shall be no discharge of floating solids or visible foam in other than trace amounts.
Page 9 of 19

Permit NC0001422
A. (10.) ACUTE TOXICITY LIMIT (QUARTERLY)- OUTFALL 001
[15A NCAC 02B 0200 et seq.]
The permittee shall conduct acute toxicity tests on a monthlU basis using protocols defined in the
North Carolina Procedure Document entitled "Pass/Fail Methodology For Determining Acute
Toxicity In A Single Effluent Concentration" (Revised -July, 1992 or subsequent versions). The
monitoring shall be performed as a Fathead Minnow (Pimephales promelas) 24 hour static test The
effluent concentration at which there may be at no time significant acute mortality is 90% (defined
as treatment two in the procedure document) Effluent samples for self-monitoring purposes must
be obtained during representative effluent discharge below all waste treatment.
All toxicity testing results required as part of this permit condition will be entered on the Effluent
Discharge Monitoring Form (MR -1) for the month in which it was performed, using the parameter
code TGE6C Additionally, DWR Form AT -2 (original) is to be sent to the following address:
Attention North Carolina Division of Water Resources
Water Sciences Section/Aquatic Toxicology Branch
1623 Mail Service Center
Raleigh, North Carolina 27699-1623
Completed Aquatic Toxicity Test Forms shall be filed with the Environmental Sciences Section no
later than 30 days after the end of the reporting period for which the report is made
Test data shall be complete and accurate and include all supporting chemical/ physical
measurements performed in association with the toxicity tests, as well as all dose/response data.
Total residual chlorine of the effluent toxicity sample must be measured and reported if chlorine is
employed for disinfection of the waste stream.
Should there be no discharge of flow from the facility during a month in which toxicity monitoring is
required, the permittee will complete the information located at the top of the aquatic toxicity (AT)
test form indicating the facility name, permit number, pipe number, county, and the month/year of
the report with the notation of "No Flow" in the comment area of the form The report shall be
submitted to the Environmental Sciences Section at the address cited above.
Should any test data from either these monitoring requirements or tests performed by the North
Carolina Division of Water Resources indicate potential impacts to the receiving stream, this permit
may be re -opened and modified to include alternate monitoring requirements or limits.
NOTE: Failure to achieve test conditions as specified in the cited document, such as mmunum
control organism survival and appropriate environmental controls, shall constitute an mvand test
and will require immediate follow-up testing to be completed no later than the last day of the month
following the month of the initial monitoring
A. (11.) GROUNDWATER MONITORING, WELL CONSTRUCTION, AND
SAMPLING
The permittee shall conduct groundwater monitoring to determine the compliance of this NPDES
permitted facility with the current groundwater Standards found under 15A NCAC 2L.0200 The
monitoring shall be conducted in accordance with the Sampling Plan approved by the Division
A. (12.) STRUCTURAL INTEGRITY INSPECTIONS OF ASH POND DAMS
The facility shall meet the dam design and dam safety requirements per 15A NCAC 2K
A. (13.) BEST MANAGEMENT PRACTICES PLAN
The Permittee shall continue to implement a Best Management Practices (BMP) Plan to control the
discharge of oils and the hazardous and toxic substances listed in 40 CFR, Part 117 and Tables II
Page 10 of 19

Permit NC0001422
and III of Appendix D to 40 CFR, Part 122, and shall maintain the Plan at the plant site and shall
be available for inspection by EPA and DWR personnel.
A. (14.) INTAKE SCREEN BACKWASH
Continued intake screen backwash discharge is permitted without limitations or monitoring
requirements.
A. (15.) NO DISCHARGE OF PCBs
As specified by 40 CFR 423 13 (a), there shall be no discharge of polychlorinated biphenyl
compounds such as those commonly used for transformer fluid
A. (16.) BIOCIDE CONDITION
The permittee shall not use any biocides except those approved in conjunction with the permit
application. The permittee shall notify the Director in writing not later than ninety (90) days prior
to instituting use of any additional biocide used in cooling systems which may be toxic to aquatic
life other than those previously reported to the Division of Water Resources Such notification shall
include completion of Biocide Worksheet Form 101 and a map locating the discharge point and
receiving stream. Completion of a Biocide Worksheet 101 is not necessary for the introduction of a
new biocide into an outfall currently being tested for toxicity
A. (17.) FISH TISSUE MONITORING NEAR ASH POND DISCHARGE — OUTFALL
001, and OUTFALLS 002/004
The facility shall conduct fish tissue monitoring at two locations (Sutton Lake and Cape Fear River)
annually and submit the results with the NPDES permit renewal application. The objective of the
monitoring is to evaluate potential uptake of pollutants by fish tissue near the Ash Pond discharge.
The parameters analyzed in fish tissue shall be arsenic, selenium, and mercury. The monitoring shall
be conducted in accordance with the Sampling Plan approved by the Division After the plan is
approved by the Division, it will become an enforceable part of the permit.
A. (18.) CLEAN WATER ACT SECTION 316(B)
The permittee shall comply with the Cooling Water Intake Structure Rule per 40 CFR 125.95. The
permittee shall submit all the materials required by the Rule with the next renewal
application.
A. (19.) ASH POND CLOSURE
The facility shall prepare an Ash Ponds Closure Plan in anticipation of the ash pond closure. This
Plan shall be submitted to the Division one month prior to the closure of the ash ponds.
A. (20.) LOWER CAPE FEAR MODELING
The permittee may elect to conduct a water quality model of the dilution factor for Outfall 001.
Contingent upon EPA approval of the Lower Cape Fear Modeling and its results, the Reasonable
Potential Analysis will be conducted again and the permit limits will be based on the new flow
numbers established by the model
A. (21.) CHRONIC TOXICITY PASS/FAIL PERMIT LIMIT (QUARTERLY) — OUTFALLS
002, 004, 008
[15A NCAC 02B 0200 et seq ]
The effluent discharge shall at no time exhibit observable inhibition of reproduction or significant
mortality to Ceriodaphnia dubia at an effluent concentration of 90 0%.
The permit holder shall perform at a minimum, quarterly monitoring using test procedures outlined
in the "North Carolina Cenodaphnia Chronic Effluent Bioassay Procedure," Revised December 2010,
or subsequent versions or "North Carolina Phase II Chronic Whole Effluent Toxicity Test Procedure"
(Revised- December 20 10) or subsequent versions. The tests will be performed during the months
Page 11 of 19

Permit NC0001422
of February, May, August, and November. These months signify the first month of each three-
month toxicity testing quarter assigned to the facility. Effluent sampling for this testing must be
obtained during representative effluent discharge and shall be performed at the NPDES permitted
final effluent discharge below all treatment processes
If the test procedure performed as the first test of any single quarter results in a failure or
ChV below the permit limit, then multiple -concentration testing shall be performed at a
minimum, in each of the two following months as described in "North Carolina Phase II
Chronic Whole Effluent Toxicity Test Procedure" (Revised -December 2010) or subsequent
versions.
All toxicity testing results required as part of this permit condition will be entered on the Effluent
Discharge Monitoring Form (MR -1) for the months in which tests were performed, using the
parameter code TGP3B for the pass/fail results and THP3B for the Chronic Value. Additionally,
DWR Form AT -3 (original) is to be sent to the following address.
Attention* North Carolina Division of Water Resources
Water Sciences Section/Aquatic Toxicology Branch
1623 Mail Service Center
Raleigh, North Carolina 27699-1623
Completed Aquatic Toxicity Test Forms shall be filed with the Water Sciences Section no later than
30 days after the end of the reporting period for which the report is made
Test data shall be complete, accurate, include all supporting chemical/ physical measurements and
all concentration/ response data, and be certified by laboratory supervisor and ORC or approved
designate signature Total residual chlorme of the effluent toxicity sample must be measured and
reported if chlorine is employed for disinfection of the waste stream.
Should there be no discharge of flow from the facility during a month in which toxicity monitoring is
required, the permittee will complete the mformation located at the top of the aquatic toxicity (AT)
test form indicating the facility name, permit number, pipe number, county, and the month/year of
the report with the notation of "No Flow" in the comment area of the form. The report shall be
submitted to the Water Sciences Section at the address cited above
Should any test data from this monitoring requirement or tests performed by the North Carolina
Division of Water Resources indicate potential impacts to the receiving stream, this permit may be
re -opened and modified to include alternate monitoring requirements or limits.
NOTE- Failure to achieve test conditions as specified in the cited document, such as minimum
control organism survival, minimum control organism reproduction, and appropriate environmental
controls, shall constitute an invalid test and will require immediate follow-up testing to be
completed no later than the last day of the month following the month of the initial monitoring
A. (22.) INSTREAM MONITORING
The facility shall conduct semiannual instream monitoring (1000 ft upstream and 1000 ft
downstream of the Outfall 001, and 1000 ft from Outfall 004) for total arsenic, total selenium, total
mercury (method 1631E), total chromium, total lead, total cadmium, total copper, and total zinc The
monitoring results shall be submitted with the NPDES permit renewal application
A. (23.) ELECTRONIC REPORTING OF DISCHARGE MONITORING REPORTS
(STATE ENFORCEABLE ONLY) [G S. 143-215.1(b)]
Proposed federal regulations require electronic submittal of all discharge monitoring reports (DMRs)
and specify that, if a state does not establish a system to receive such submittals, then permittees
Page 12 of 19

Permit NC0001422
must submit DMRs electronically to the Environmental Protection Agency (EPA) The Division
anticipates that these regulations will be adopted and is beginning implementation in late 2013
NOTE. This special condition supplements or supersedes the following sections within Part II of
this permit (Standard Conditions for NPDES Permits):
• Section B (11.) Signatory Requirements
• Section D
(2 )
• Section D
(6 )
• Section E
(5 )
Reporting
Records Retention
Monitoring Reports
1. Reporting [Supersedes Section D. (2.) and Section E. (5.) (a)1
Beginning no later than 270 days from the effective date of this permit, the permittee shall begin
reporting discharge monitoring data electronically using the NC DWR's Electronic Discharge
Monitoring Report (eDMR) internet application
Monitoring results obtained during the previous month(s) shall be summarized for each month
and submitted electronically using eDMR. The eDMR system allows permitted facilities to enter
monitoring data and submit DMRs electronically using the internet. Until such time that the
state's eDMR application is compliant with EPA's Cross -Media Electronic Reporting Regulation
(CROMERR), permittees will be required to submit all discharge monitoring data to the state
electronically using eDMR and will be required to complete the eDMR submission by printing,
signing, and submitting one signed original and a copy of the computer printed eDMR to the
following address
NC DENR / DWR / Information Processing Unit
ATTENTION: Central Files / eDMR
1617 Mail Service Center
Raleigh, North Carolina 27699-1617
If a permittee is unable to use the eDMR system due to a demonstrated hardship or due to the
facility being physically located in an area where less than 10 percent of the households have
broadband access, then a temporary waiver from the NPDES electronic reporting requirements
may be granted and discharge monitoring data may be submitted on paper DMR forms (MR 1,
1. 1, 2, 3) or alternative forms approved by the Director. Duplicate signed copies shall be
submitted to the mailing address above
Requests for temporary waivers from the NPDES electronic reporting requirements must be
submitted in writing to the Division for written approval at least sixty (60) days prior to the date
the facility would be required under this permit to begin using eDMR Temporary waivers shall
be valid for twelve (12) months and shall thereupon expire At such time, DMRs shall be
submitted electronically to the Division unless the permittee re -applies for and is granted a new
temporary waiver by the Division
Information on eDMR and application for a temporary waiver from the NPDES electronic
reporting requirements is found on the following web page:
http•//portal.ncdenr org/web/wq/admin/bog/ipu/edmr
Regardless of the submission method, the first DMR is due on the last day of the month
following the issuance of the permit or in the case of a new facility, on the last day of the month
following the commencement of discharge
Page 13 of 19

Permit NC0001422
2. Signatory Requirements [Supplements Section B. (11.) (b) and supersedes Section B. (11.1
Ldu
All eDMRs submitted to the permit issuing authority shall be signed by a person described in
Part II, Section B. (11.)(a) or by a duly authorized representative of that person as described in
Part II, Section B. (11.)(b) A person, and not a position, must be delegated signatory authority
for eDMR reporting purposes
For eDMR submissions, the person signing and submitting the DMR must obtain an eDMR user
account and login credentials to access the eDMR system. For more information on North
Carolina's eDMR system, registering for eDMR and obtaining an eDMR user account, please
visit the following web page
http://portal ncdenr org/web/wq/admin/bog/ipu/edmr
Certification. Any person submitting an electronic DMR using the state's eDMR system shall
make the following certification [40 CFR 122.22] NO OTHER STATEMENTS OF
CERTIFICATION WILL BE ACCEPTED:
"I certify, under penalty of law, that this document and all attachments were prepared under my
direction or supervision in accordance with a system designed to assure that qualified personnel
properly gather and evaluate the information submitted. Based on my inquiry of the person or
persons who manage the system, or those persons directly responsible for gathering the
information, the information submitted is, to the best of my knowledge and belief, true, accurate,
and complete. I am aware that there are significant penalties for submitting false information,
including the possibility of fines and imprisonment for knowing violations. "
3. Records Retention [Supplements Section D. (6.11
The permittee shall retain records of all Discharge Monitoring Reports, including eDMR
submissions These records or copies shall be maintained for a period of at least 3 years from
the date of the report. This period may be extended by request of the Director at any time [40
CFR 122 41].
A. (24.) APPLICABLE STATE LAW (STATE ENFORCEABLE ONLY) [G.S. 143-215.1(b)]
This facility shall meet the requirements of Senate Bill 729 (Coal Ash Management Act). This permit
may be reopened to include new requirements imposed by Senate Bill 729.
A. (25.) STORMWATER POLLUTION PREVENTION PLAN
The permittee shall develop and implement a Stormwater Pollution Prevention Plan (SPPP). The
SPPP shall be maintained on site unless exempted from this requirement by the Division The SPPP
is public information The SPPP should also specifically and separately address deconstruction,
demolition, coal, and/or coal ash hauling or disposal activities The SPPP shall include, at a
minimum, the following items*
Site Overview. The Site Overview shall provide a description of the physical facility and the
potential pollutant sources that may be expected to contribute to contamination of stormwater
discharges. The Site Overview shall contain the following -
(a) A general location map (USGS quadrangle map or appropriately drafted equivalent map),
showing the facility's location in relation to transportation routes and surface waters, the
name of the receiving waters to which the stormwater outfalls discharge, or if the discharge
is to a municipal separate storm sewer system, the name of the municipality and the
ultimate receiving waters, and accurate latitude and longitude of the points of stormwater
discharge associated with industrial activity The general location map (or alternatively the
site map) shall identify whether any receiving waters are impaired (on the state's 303(d) list
Page 14 of 19

Permit NC0001422
of impaired waters) or if the site is located in a watershed for which a TMDL has been
established, and what the parameters of concern are.
(b) A narrative description of storage practices, loading and unloading activities, outdoor
process areas, dust or particulate generating or control processes, and waste disposal
practices A narrative description of the potential pollutants that could be expected to be
present in the stormwater discharge from each outfall The narrative should also reference
deconstruction, demolition, coal, and/or coal ash hauling or disposal activities where
applicable
(c) A site map drawn at a scale sufficient to clearly depict: the site property boundary, the
stormwater discharge outfalls; all on-site and adjacent surface waters and wetlands,
industrial activity areas (including storage of materials, disposal areas, process areas,
loading and unloading areas, and haul roads), site topography and finished grade, all
drainage features and structures; drainage area boundaries and total contributing area for
each outfall; direction of flow in each drainage area, industrial activities occurring in each
drainage area; buildings; stormwater Best Management Practices (BMPs), and impervious
surfaces. The site map must indicate the percentage of each drainage area that is
impervious, and the site map must include a graphic scale indication and north arrow
(d) A list of significant spills or leaks of pollutants during the previous three (3) years and any
corrective actions taken to mitigate spill impacts.
(e) Certification that the stormwater outfalls have been evaluated for the presence of non-
stormwater discharges. The permittee shall submit the first certification no later than
90 days after the effective date of this permit to the Stormwater Permitting Program
Central Office and shall re -certify annually that the stormwater outfalls have been
evaluated for the presence of non-stormwater discharges. For any non-stormwater
discharge identified, the permittee shall indicate how that discharge is permitted or
otherwise authorized. The certification statement will be signed in accordance with the
requirements found in Part II, Standard Conditions, Section B, Paragraph 11.
2. Stormwater Management Strategy. The Stormwater Management Strategy shall contain a
narrative description of the materials management practices employed which control or
minimize the stormwater exposure of significant materials, including structural and
nonstructural measures This strategy should also address deconstruction, demolition, coal,
and/or coal ash hauling or disposal activities where applicable The Stormwater Management
Strategy, at a minimum, shall incorporate the following
(a) Feasibility Study A review of the technical and economic feasibility of changing the
methods of operations and/or storage practices to eliminate or reduce exposure of materials
and processes to rainfall and run-on flows Wherever practical, the permittee shall prevent
exposure of all storage areas, material handling operations, and manufacturing or fueling
operations. In areas where elimination of exposure is not practical, this review shall
document the feasibility of diverting the stormwater run-on away from areas of potential
contamination.
(b) Secondary Containment Requirements and Records. Secondary containment is required
for: bulk storage of liquid materials, storage in any amount of Section 313 of Title III of the
Superfund Amendments and Reauthorization Act (SARA) water priority chemicals; and
storage in anv amount of hazardous substances, in order to prevent leaks and spills from
contaminating stormwater runoff A table or summary of all such tanks and stored
materials and their associated secondary containment areas shall be maintained If the
secondary containment devices are connected to stormwater conveyance systems, the
connection shall be controlled by manually activated valves or other similar devices (which
shall be secured closed with a locking mechanism). Any stormwater that accumulates in
the containment area shall be observed for color, foam, outfall staining, visible sheens and
Page 15 of 19

Permit NC0001422
dry weather flow, prior to release of the accumulated stormwater Accumulated stormwater
shall be released if found to be uncontaminated by any material Records documenting the
individual making the observation, the description of the accumulated stormwater, and the
date and time of the release shall be kept for a period of five (5) years For facilities subject
to a federal oil Spill Prevention, Control, and Countermeasure Plan (SPCC), any portion of
the SPCC Plan fully compliant with the requirements of this permit may be used to
demonstrate compliance with this permit
In addition to secondary containment for tankage, the permittee shall provide drip pans or
other similar protection measures for truck or rail car liquid loading and unloading stations.
(c) BMP Summary A listing of site structural and non-structural Best Management Practices
(BMPs) shall be provided. The installation and implementation of BMPs shall be based on
the assessment of the potential for sources to contribute significant quantities of pollutants
to stormwater discharges and on data collected through monitoring of stormwater
discharges The BMP Summary shall include a written record of the specific rationale for
installation and implementation of the selected site BMPs The BMP Summary should also
address deconstruction, demolition, coal, and/or coal ash hauling or disposal activities
where applicable The permittee shall refer to the BMPs described in EPA's Multi -Sector
Permit (MSGP) and Industrial Stormwater Fact Sheet for Steam Electric Power Generating
Facilities (EPA -833-F-06-030) for guidance on BMPs that may be appropriate for this site
The BMP Summary shall be reviewed and updated annually.
3 Spill Prevention and Response Procedures. The Spill Prevention and Response Procedures
(SPRP) shall incorporate an assessment of potential pollutant sources based on a materials
inventory of the facility Facility personnel responsible for implementing the SPRP shall be
identified in a written list incorporated into the SPRP and signed and dated by each individual
acknowledging their responsibilities for the plan. A responsible person shall be on-site at all
times during facility operations that have increased potential to contaminate stormwater runoff
through spills or exposure of materials associated with the facility operations The SPRP must
be site stormwater specific. Therefore, an oil Spill Prevention Control and Countermeasure plan
(SPCC) may be a component of the SPRP, but may not be sufficient to completely address the
stormwater aspects of the SPRP The common elements of the SPCC with the SPRP may be
incorporated by reference into the SPRP
4. Preventative Maintenance and Good Housekeeping Program A preventative maintenance
and good housekeeping program shall be developed and implemented The program shall
address all stormwater control systems (if applicable), stormwater discharge outfalls, all on-site
and adjacent surface waters and wetlands, industrial activity areas (including material storage
areas, material handling areas, disposal areas, process areas, loading and unloading areas, and
haul roads), all drainage features and structures, and existing structural BMPs
The program shall establish schedules of inspections, maintenance, and housekeeping activities
of stormwater control systems, as well as facility equipment, facility areas, and facility systems
that present a potential for stormwater exposure or stormwater pollution where not already
addressed under another element of the SPPP Inspection of material handling areas and
regular cleaning schedules of these areas shall be incorporated into the program Compliance
with the established schedules for inspections, maintenance, and housekeeping shall be
recorded and maintained in the SPPP The program should also address deconstruction,
demolition, coal, and/or coal ash hauling or disposal activities where applicable The Good
Housekeeping Program shall also include, but not be limited to, BMPs to accomplish the
following
(a) Minimize contamination of stormwater runoff from oil-bearing equipment in
switchyard areas,
(b) Minimize contamination of stormwater runoff from delivery vehicles and rail cars
arriving and departing the plant site;
Page 16 of 19

Permit NC0001422
(c) Inspect all residue -hauling vehicles for proper covering over the load, adequate gate -
sealing, and overall integrity of the container body Repair vehicles as necessary;
and
(d) Reduce or control the tracking of ash and residue from ash loading and storage
areas,
5 Facility Inspections Inspections of the facility (including tanks, pipes, and equipment) and all
stormwater systems shall occur as part of the Preventative Maintenance and Good
Housekeeping Program at a minimum on a semi-annual schedule, once during the first half of
the year (January to June), and once during the second half (July to December), with at least 60
days separating inspection dates (unless performed more frequently than semi-annually)
6. Employee Training Training programs shall be developed and training provided at a
minimum on an annual basis for facility personnel with responsibilities for spill response and
cleanup, preventative maintenance activities, and for any of the facility's operations that have
the potential to contaminate stormwater runoff The facility personnel responsible for
implementing the training shall be identified, and their annual training shall be documented by
the signature of each employee trained
7 Responsible Party The SPPP shall identify a specific position or positions responsible for the
overall coordination, development, implementation, and revision of the SPPP Responsibilities
for all components of the SPPP shall be documented and position assignments provided
8 SPPP Amendment and Annual Update. The permittee shall amend the SPPP whenever there is
a change in design, construction, operation, site drainage, maintenance, or configuration of the
physical features which may have a significant effect on the potential for the discharge of
pollutants to surface waters All aspects of the SPPP shall be reviewed and updated on an
annual basis The annual update shall include
(a) an updated list of significant spills or leaks of pollutants for the previous three (3)
years, or the notation that no spills have occurred (element of the Site Overview),
(b) a written re -certification that the stormwater outfalls have been evaluated for the
presence of non-stormwater discharges (element of the Site Overview),
(c) a documented re-evaluation of the effectiveness of the on-site stormwater BMPs (BMP
Summary element of the Stormwater Management Strategy)
(d) a review and comparison of stormwater sample analytical data to any applicable
limits or benchmark values (if applicable) over the past year.
If the Director notifies the permittee that the SPPP does not meet one or more of the minimum
requirements of the permit, the permittee shall have 30 days to respond Within 30 days of
such notice, the permittee shall submit a time schedule to the Director for modifying the SPPP
to meet minimum requirements The permittee shall provide certification in writing to the
Director that the changes have been made
9 SPPP Implementation The permittee shall implement the Stormwater Pollution Prevention
Plan and all appropriate BMPs consistent with the provisions of this permit, in order to control
contaminants entering surface waters via stormwater Implementation of the SPPP shall
include documentation of all monitoring, measurements, inspections, maintenance activities,
and training provided to employees, including the log of the sampling data and of actions taken
to implement BMPs associated with the industrial activities, including vehicle maintenance
activities. Such documentation shall be kept on-site for a period of five (5) years and made
available to the Director or the Director's authorized representative immediately upon request
A. (26.) TEMPERATURE LIMIT COMPLIANCE SCHEDULE- OUTFALL 008
The facility shall develop the plan for compliance with the State temperature standard and submit
the plan to the Division within 1 year from the effective date of the permit. The plan shall contain
Page 17 of 19

Permit NC0001422
milestones and the specific action items After the plan is approved by the Division, it will become an
enforceable part of the permit
A. (27.) ADDITIONAL CONDITIONS AND DEFINITIONS
1 EPA methods 200 7 or 200 8 (or the most current versions) shall be used for analyses of all
metals except for total mercury.
2. All effluent samples for all external outfalls shall be taken at the most accessible location
after the final treatment but prior to discharge to waters of the U S (40 CFR 122.410).
3 The term low volume waste sources means wastewater from all sources except thouse for
which specific limitations are otherwise established in this part (40 CFR 423 11 (b))
4 The term chemical metal cleaning waste means any wastewater resulting from cleaning any
metal process equipment with chemical compounds, including, but not limited to, boiler
tube cleaning (40 CFR 423 11 (c)).
5. The term metal cleaning waste means any wastewater resulting from cleaning [with or
without chemical cleaning compounds] any metal process equipment including, but not
limited to, boiler tube cleaning, boiler fireside cleaning, and air preheater cleaning (40 CFR
423 11 (d))
6. For all outfalls where the flow measurement is to be "estimated" the estimate can be done by
using calibrated V -notch weir, stop -watch and graduated cylinder, or other method
approved by the Division
7. During normal operations removing of the free water above the settled wet ash layer shall
not .involve mechanical disturbance of the ash.
Page 18 of 19

Permit NC0001422
Appendix A
Plan for Identification of New Discharges (attached).
Page 19 of 19

I
EXHIBIT 3
Riverbend Final NPDES Permit NC0004961
February 12, 2016

Water Resources
ENVIRONMENTAL. QUALITY
February 12, 2016
IVIi. Hammy Sideris, Senior Vice President
Environmental, Health and Safety
Duke Energy Carolinas, LLC
Mail Code EC13K
P.O. Box 1006
Charlotte, North Carolina 28201-1006
PAT MCCRORY
Govemoi
DONALD R. VAN DER VAART
secsetaly
S. JAY ZIMMERMAN
Subject: NPDES Permit Issuance
Pet it No. NC0004961
Riveibend Steam Station
Gaston County
Dear Mr. Sideris:
Dnectoi
The Division of Water Resources is forwarding herewith the Final NPDES permit for Riverbend
Steam Station. This permit renewal is issued pursuant to the requirements of North Carolina
General Statute 143-215.1 and the Me notandum of Agreement between North Carolina and the
U.S. Environmental Protection Agency dated Octobei 15, 2007 (ot as subsequently amended).
A public hearing was held on April. 8, 2015 in Lincolnton seeking comments on the Draft
permit. This Final permit incorporates tecommendations of the DWR Heating Officer, EPA, as
well as other changes. Listed below ate all changes from the Draft permit:
• The Outfall 010 was eliminated and the Special Condition A. (16) was updated to meet
the requirements of The Water Quality Standard Regulatory Revisions Final Rule that has
become effective on Octobet 20, 2015.
• Fish tissue monitoring was increased to annually from once every five years to address the
EPA comment. Please see Special Condition A. (12).
• The Additional Conditions and Definitions Special Condition was added to the petinit to
address the EPA comment. Please see Special Condition A. (20.).
• Measurement frequency was changed from "Episodic" to "Per discharge event" (Outfall
002A) to address the EPA comment.
• The Flow limit was added for Outfall 002 (dewatering phase) to address the EPA
comment.
• The automatic pump shutoff tegLitements for TSS limit exceedance was added £ot Outfall
002 to address the EPA comment.
• The variance from MonthlyAverage TSS limit (Outfall 002 and Outfall 011) was eliminated
to address the EPA comment.
State of North Carolina I Environmental Quality I Water Resources
1617 Mail service Center I Raleigh, North Carolina 27699-1611
919 707 9000

• Monitoring frequency for all patameteis was increased to Weekly for Outfall 002 to address
the EPA comment.
• The specific date of December 31, 2019 replaced 4.5 years for Outfall 002. This change
was made to addiess EPA comment. Please see Special Condition A. (2.).
• Clarifying language was added to define the discharge from the ash pond under normal
operating conditions to address the Hearing O£ficet tecommendation and the comment
from the permittee: Please see Special Condition A. (2).
• The definition of dewatering was added to Special Condition A. (3.). The definition was
added to address the Hearing Office recommendation and the comment from the
permittee.
• The effluent concenttation for Whole Effluent Toxicity was changed to correct a typo, the
correct concentiationis 2.7%. Please see footnote to Special Conditions A. (2.) and A. (3).
: The footnote describing conditions for monitoring Total Copper and Total Iron was
removed (Outfall 011) to coriect an etror.
• Description of the wastewater sources for Outfall 001 and Outfall 002 was updated to
reflect the current status of the facility.
• Clarifying language was added to the Outfall 002 to define the conditions under which the
limits for Total Copper and Total Iron ate applicable. This change was made to address
the Hearing Officet recommendation.
• A distinct outfall was created for each seep with the effluent limits equivalent to the water
quality standards, Technology -Based limits (TSS and Oil & Grease) were also added in
accordance with the 40 CFR 423.
• The monthly seep monitoring was extended to a 12 month period, after which the
monitoring will be reduced to quarterly.
• The following requirements were added -to the Condition A. (2.). — Outfall 001: flow limit;
use of a floating pump station with free water skimmed from the basin surface using an
adjustable weir; daily monitoring of flow; continuous monitoring of TSS with auto pump
shut-off if TSS concentration (15 minute average) exceeds half the maximum daily TSS limit
(pumping will be allowed to continue if interruption might result in a dam failure or
damage); real time pH monitoring with an auto shut-off if the 15 -minute running average
pH falls below 6.1 standard units or rises above 8.9 standard units; drawdown to no less than
three feet above the ash; and monitoring for total chromium, total lead, total cadmium, and
total dissolved solids.
If any parts, measurement frequencies, or sampling requitements contained in this permit are
unacceptable to you, you have the right to an adjudicatory hearing upon written request within thirty
(30) days following receipt of this letter. This request must be in the form of a w.utten petition,
conforming to Chapter 150B of the North Caiolina General Statutes, and filed with the office of
Administrative Hearings, 6714 Mail Service Center, Raleigh, Noith Carolina 27699-6714. Unless
such a demand is made, this permit shall be final and binding.
Please take notice that this permit is not transferable except after notice to the Division of Water
Resources. The Division may require modification or revocation and reissuance of the permit. This
permit does not affect the legal requirements to obtain other permits which may be tequited by the
Division of Water Resources, the Division of Energy, Mineral, and Land Resources, the Coastal
Area Management Act, or any other fedei.al or local governmental permit.

If you have any questions on this pennit, please contact Sergei Cherni_kov at 919-807-6386.
Sincerely,
4S.Zetman, P.G.
Director, Division of Water Resources
Hardcopy: Central Files
NPDES Files
Mooresville Regional Office, SWPS
Email: US EPA, Region IV
Aquatic Toxicology Unit
David Merryman, Catawba Riverkeepet, [[e-mail]]

Pennit NC0004961
STATE OF NORTH CAROLINA
DEPARTMENT OF ENVIRONMENTAL QUALITY
DIVISION OF WATER RESOURCES
'. ► -ii1i
TO DISCHARGE WASTEWATER UNDER THE
NATIONAL POLLUTANT DISCHARGE ELIMINATION SYSTEM
In compliance with the provision of North Carolina General Statute 143-215.1, other lawful
standards and regulations promulgated and adopted by the North Carolina Environmental
Management Commission, and the Federal Water Pollution Control Act, as amended,
Duke Energy Carolinas, LLC
is hereby authorized to discharge wastewater from a facility located at the
Riverbend Steam Station
Mount Holly
Gaston County
to receiving waters designated as the Catawba River (Mountain Island Lake) in the
Catawba River Basin
in accordance with effluent limitations, monitoring requirements, and other
applicable conditions set forth in Parts I, II, III, and Appendix A.
This permit shall become effective March 1, 2016.
This permit and authorization to discharge shall expire at midnight on February 29, 2020.
Signed this day February 12, 2016. -
S.Jayt�ean P.G., Director
Divisior Resources
By Authority of the Environmental Management Commission
Page 1 of 27

Permit NC0004961
SUPPLEMENT TO PERMIT COVER SHEET
All previous NPDES Permits issued to this facility, whether for operation or discharge are hereby
revoked. As of this permit issuance, any previously issued permit bearing this number is no longer
effective. Therefore, the exclusive authority to operate and discharge from this facility arises under
the permit conditions, requirements, terms, and provisions included herein.
Duke Energy Carolinas, LLC is hereby authorized to:
1. Continue to discharge:
Water from the plant chiller system (outfall 001).
Ash basin discharge (outfall 002) consisting of consisting of stormwater
from roof drains and paving, treated groundwater, track hopper sump
(groundwater), coal pile runoff, general plant/trailer sanitary wastewater,
turbine and boiler rooms sumps, vehicle rinse water, and stormwater from
pond areas, upgradient watershed, and miscellaneous stormwater flows.
Yard sump overflow (outfall 002A) .
12 potentially contaminated groundwater seeps (outfalls 101-112).
Wastewater, stormwater and groundwater (outfall 0 11) .
From a facility located at Riverbend Steam Station, Mount Holly in Gaston
County, and
2. Discharge wastewater from said treatment works at the location specified on
the attached map into the Catawba River, which is classified WS -IV and B -CA
waters in the Catawba River Basin.
Page 2 of 27

Permit NC0004961
Part I
A. (1.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
001) [15A NCAC 02B 0400 et seq., 02B .0500 et seq.]
During the period beginning on the effective date of this permit and lasting until expiration, the
Permittee is authorized to discharge plan-- chiller system from outfall 001. Such discharges shall be
limited and monitored3 by the Permittee as specified below.
EFFLUENT
CHARACTERISTICS
LIMITS
MONITORING REQUIREMENTS
Monthly Daily
Average I Maximum
Measurement
Erequcn
Sample Type
I
Sample
I Location'
Flow, MGD
Monthly
Pump Logs
Influent or
Effluent
-Temperature (c)F)
Monthly
Grab
Effluent
Temperature (OF)2
89.6 (32-C)
Monthly
Grab
Downstream
Notes:
1. Downstream sampling point: downstream at Mountain Island Lake. If samples are collected
below the water surface, the Permittee will record the sample depth on the DMR form.
2 The ambient temperature shall not exceed 89.60F (32.00C) and is defined as the daily average
downstream water temperature When the Riverbend Station effluent temperature is recorded
below 89.60F (32.0°C), as a daily average, then monitoring and reporting of the downstream water
temperature is not required. In cases where the Permittee experiences equipment problems and
is unable to obtain daily temperatures from the existing temperature monitoring system, the
temperature monitoring must be reestablished within five working days.
3. No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system. See Special
Condition A. (18.).
Chlorination of the once through condenser cooling water, discharged through outfall 001, is
not allowed under this permit. Should Duke Energy wish to chlorinate its condenser cooling
water, a Division permission must be requested and received prior to commencing
chlorination.
There shall be no discharge of floating solids or visible foam in other than trace amounts.
Page 3 of 27

Permit NC0004961
A. (2.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
002 -normal operation) [15A NCAC 02B 0400 et seq , 02B .0500 et seq ]
During the period beginning on the effective date of this permit and lasting until expiration, the
Permittee is authorized to discharge from outfall 002 — Ash Pond Discharge (removing the free
water above the settled ash layer that does not involve mechanical movement of the ash).
Such discharges shall be limited and monitored6 by the Permittee as specified below:
EFFLUENT
CHARACTERISTICS
LIMITS
MONITORING REQUIREMENTS
Monthly Daily Measurement Sample Type Sample Location
Average Maximum Frequency
Flow
5.74 MGD
Daily
Pump logs or
estimate
Influent or Effluent
Total Suspended Solids8
23,0 mg/L
75.0 mg/L
Weekly
Grab
Effluent
Oil and Grease
110 mg/L
15 0 mg/L
Weekly
Grab
Effluent
Total Copper'
10 mg/L
1.0 mg/L
Weekly
Grab
Effluent
Total Iron'
1.0 mg/L
10 mg/L
Weekl
Grab
Effluent
Total Arsenic
52 5 g/L
72 5 Ng/L
Weekly
Grab
Effluent
Total Selenium
68 0 g/L
127 5 g/L
Weekly
Grab
Effluent
Nitrate/nitrite as N
0.65 mg/L
0 85 mg/L
Weekly
Grab
Effluent
Total Arsenic
10.5 lag/L7
14.5 lig/L7
Weekly
Grab
Effluent
Total Selenium
13 6 Ng/L7
25.5 Ng/L7
Weekly
Grab
Effluent
Total Mercury
47,0 ng/L5
47.0 ng/L5
Weekly
Grab
Effluent
Nitrate/nitrite as N
0,13 mg/L7
017 mg/L7
Weekly
Grab
Effluent
Total Phosphorus, mg/L
Weekly
Grab
Effluent
Total Nitrogen (NO2 + NO3 + TKN),
mg/L
Weekly
Grab
Effluent
pH2
Weekly
Grab
Effluent
Chronic Toxicity3
Monthly
Grab
Effluent
Turbidity4, NTU
Weekly
Grab
Effluent
Total Chromium, lag/L
Weekly
Grab
Effluent
Total Cadmium, g/L
Weekly
Grab
Effluent
Total Lead, g/L
Weekly
Grab
Effluent
TDS, mg/L
Weekly
Grab
Effluent
Notes:
1. The limits for total copper and total iron only apply when chemical metal cleaning wastewaters
are being discharged
2. The pH shall not be less than 6.0 standard units nor greater than 9.0 standard units. The facility
shall conduct a real time pH monitoring with an auto shut-off if the ,15 -minute running average
pH falls below 6.1 standard units or rises above 8 9 standard units
3 Whole Effluent Toxicity shall be monitored by chronic toxicity (Ceriodaphnia) PAF at 2 7% Tests
shall be conducted in January, April, July and October (see Part A.(6.) for details).
4. The discharge from this facility shall not cause turbidity in the receiving stream to exceed 50
NTU If the instream turbidity exceeds 50 NTU due to natural background conditions, the
discharge cannot cause turbidity to increase in the receiving stream.
NTU - Nephelometric Turbidity Unit.
5. The facility shall use EPA method 1631E.
6. No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system. See Special
Condition A. (18.).
7. The TBEL limits shall be met no later than December 31, 2019. This time period is provided
in order for the facility to budget, design, and construct the treatment system. Permit might
be re -opened to implement the final EPA Effluent Guidelines and more stringent limits
might be added.
8. The facility shall continuously monitor TSS concentration and the dewatering pump shall be
shutoff automatically when the one half of the Daily Maximum limit (15 minutes average) is
Page 4 of 27

Permit NC0004961
exceeded. Pumping will be allowed to continue if interruption might result in a dam failure or
damage.
The facility is allowed to drawdown the wastewater in the lagoon to no less than three feet
above the ash.
The facility shall use of a floating pump station with free water skimmed from the basin
surface using an adjustable weir.
The metal cleaning waste, coal pile runoff, ash transport water, domestic wastewater,
and low volume waste shall be discharged into the ash settling pond.
No chemicals, cleaners, or other additives may be present in the vehicle wash water
to be discharged from this outfall.
There shall be no discharge of floating solids or visible foam in other than trace
amounts. The level of water in the pond should not be lowered more than 1 ft/week,
unless approved by the DEQ Dam Safety Program.
Page 5 of 27

Permit NC0004961
A. (3.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
002 -dewatering phase) [15A NCAC 0213 .0400 et seq , 0213 .0500 et seq.]
During the period beginning on the commencement date of the dewatering operations and lasting
until expiration, the Permittee is authorized to discharge from outfall 002 — Ash Pond Discharge
(Dewatering -removing the interstitial water). Such discharges shall be limited and monitored7 by
the Permittee as specified below:
EFFLUENT
CHARACTERISTICS
LIMITS
MONITORING REQUIREMENTS
Monthly Daily
Average Maximum
Measurement Sample Type Sample Location
Frequency
Flow
1 45 MGD
Weekly
Pump logs or
estimate
Influent or Effluent
Total Suspended Solids'
23 0 mg/L
75.0 m /L
Weekly
Grab
Effluent
Oil and Grease
110 mg/L
15.0 mg/L
Weekly
Grab
Effluent
Total Copper2
1.0 mg/L
10 mg/L
Weekly
Grab
Effluent
Total Iron2
10 mg/L
1.0 mg/L
Weekly
Grab
Effluent
Total Arsenic
10 5 pg/L
14,5 pg/L
Weekly
Grab
Effluent
Total Selenium
13 6 pg/L
25.5 g/L
Weekly
Grab
Effluent
Total Aluminum
3,18 mg/ L
318 mg/L
Weekly
Grab
Effluent
Total Mercury
47 0 ng/L6
47.0 ng/Ls
Weekly
Grab
Effluent
Nitrate/nitrate as N
013 mg/L
017 mg/L
Weekly
Grab
Effluent
Total Phosphorus, mg/L
Weekly
Grab
Effluent
Total Nitrogen (NO2 + NOa+ TKN),
mg/L
Weekly
Grab
Effluent
H3
Weekly
Grab
Effluent
Chronic Toxnty4
Weekly
Grab
Effluent
Turbidity5, NTU
Weekly
Grab
Effluent
Notes:
1 The facility shall continuously monitor TSS concentration and the dewatering pump shall be
shutoff automatically when the limits are exceeded
2. The limits for total copper and total iron only apply when chemical metal cleaning
wastewaters are being discharged.
3 The pH shall not be less than 6.0 standard units nor greater than 9.0 standard units.
4. Whole Effluent Toxicity shall be monitored by chronic toxicity (Ceriodaphnia) P/F at 2.7%.
Tests shall be conducted in January, April, July and October (see Part A.(6.) for details).
5. The discharge from this facility shall not cause turbidity in the receiving stream to exceed 50
NTU. If the instream turbidity exceeds 50 NTU due to natural background conditions, the
discharge cannot cause turbidity to increase in the receiving stream.
NTU - Nephelometric Turbidity Unit.
6. The facility shall use EPA method 1631E.
7. No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system See
Special Condition A. (18.).
The metal cleaning waste, coal pile runoff, ash transport water, domestic wastewater,
and low volume waste shall be discharged into the ash settling pond.
No chemicals, cleaners, or other additives may be present in the vehicle wash water
to be discharged from this outfall. There shall be no discharge of floating solids or
visible foam in other than trace amounts.
The level of water in the pond should not be lowered more than 1 ft/week unless
approved by the DEQ Darn Safety Program.
Page 6 of 27

Permit NC0004961
A. (4.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
002A) [15A NCAC 02B .0400 et seq , 02B .0500 et seq.]
During the period beginning on the effective date of this permit and lasting until expiration, the
Permittee is authorized to discharge from outfall 002A — Yard Sump Overflows. Such discharges
shall be limited and monitored3 by the Permittee as specified below:
EFFLUENT
LIMITS
MONITORING REQUIREMENTS
CHARACTERISTICS
Monthly
Daily
Measurement
Sample Type
Sample Location'
Average
Maximum
Frequency
Flow, MGD
Per discharge
Estimate
Effluent
event
Total Suspended Solids
23 0 mg/L
75 0 mg/L
Per discharge
Grab
Effluent
event
Oil and Grease
11.0 mg/L
15 0 mg/L
Per discharge
Grab
Effluent
event
Fecal Coliform, CPU/100 mL
Per discharge
Grab
Effluent
event
Total Copper2
1.0 mg/L
1.0 mg/L
Per discharge
Grab
Effluent
event
Total Iron2
10 mg/L
10 mg/L
Per discharge
Grab
Effluent
event
pH4
Per discharge
Grab
Effluent
event
Notes.
1. Effluent samples shall be collected prior to the discharge to the receiving stream.
2. The limits for total copper and total iron only apply when chemical metal cleaning
wastewaters are being discharged.
3. No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system See Special
Condition A. (18.).
4. The pH shall not be less than 6 0 standard units nor greater than 9.0 standard units.
There shall be no discharge of floating solids or visible foam in other than trace
amounts.
ALL FLOWS SHALL BE REPORTED ON MONTHLY DMRS. SHOULD NO FLOW OCCUR DURING A
GIVEN MONTH, THE WORDS "NO FLOW" SHOULD BE CLEARLY WRITEN ON THE FRONT OF
THE DMR. ALL SAMPLES SHALL BE OF A REPRESENTATIVE DISCHARGE.
Page 7 of 27

Permit NC0004961
A. (5.) CHRONIC TOXICITY PASS/FAIL PERMIT LIMIT (QUARTERLY) (Outfall
002) [15A NCAC 02B.0200 et seq.]
The effluent discharge shall at no time exhibit observable inhibition of reproduction or significant
mortality to Ceriodaphnia dubia at an effluent concentration of 2.7%.
The permit holder shall perform at a minimum, quarte rlrf monitoring using test procedures outlined
in the "North Carolina Ceriodaphnia Chronic Effluent Bioassay Procedure," Revised December 2010,
or subsequent versions or "North Carolina Phase II Chronic Whole Effluent Toxicity Test Procedure"
(Revised- December 2010) or subsequent versions. Effluent sampling for this testing must be
obtained during representative effluent discharge and shall be performed at the NPDES permitted
final effluent discharge below all treatment processes.
If the test procedure performed as the first test of any single quarter results in a failure or
ChV below the permit limit, then multiple -concentration testing shall be performed at a
minimum, in each of the two following months as described in "North Carolina Phase II
Chronic Whole Effluent Toxicity Test Procedure" (Revised -December 2010) or subsequent
versions.
All toxicity testing results required as part of this permit condition will be entered on the Effluent
Discharge Monitoring Form (MR -1) for the months in which tests were performed, using the
parameter code TGP3B for the pass/fail results and THP3B for the Chronic Value. Additionally,
DWR Form AT -3 (original) is to be sent to the following address:
Attention: North Carolina Division of Water Resources
Water Sciences Section/Aquatic Toxicology Branch
1623 Mail Service Center
Raleigh, North Carolina 27699-1623
Completed Aquatic Toxicity Test Forms shall be filed with the Water Sciences Section no later than
30 days after the end of the reporting period for which the report is made.
Test data shall be complete, accurate, include all supporting chemical/ physical measurements and
all concentration/ response data, and be certified by laboratory supervisor and ORC or approved
designate signature. Total residual chlorine of the effluent toxicity sample must be measured and
reported if chlorine is employed for disinfection of the waste stream.
Should there be no discharge of flow from the facility during a month in which toxicity monitoring is
required, the permittee will complete the information located at the top -of the aquatic toxicity (AT)
test form indicating the facility name, permit number, pipe number, county, and the month/year of
the report with the notation of "No Flow" in the comment area of the form. The report shall be
submitted to the Water Sciences Section at the address cited above.
Should the permittee fail to monitor during a month in which toxicity monitoring is required,
monitoring will be required during the following month. Assessment of toxicity compliance is based
on the toxicity testing quarter, which is the three month time interval that begins on the first day of
the month in which toxicity testing is required by this permit and continues until the final day of the
third month.
Should any test data from this monitoring requirement or tests performed by the North Carolina
Division of Water Resources indicate potential impacts to the receiving stream, this permit may be
re -opened and modified to include alternate monitoring requirements or limits.
NOTE: Failure to achieve test conditions as specified in the cited document, such as minimum
control organism survival, minimum control organism reproduction, and appropriate environmental
controls, shall constitute an invalid test and will require immediate follow-up testing to be
completed no later than the last day of the month following the month of the initial monitoring.
Page 8 of 27

Permit NC0004961
A. (6.) BIOCIDE CONDITION
The permittee shall not use any biocides except those approved in conjunction with the permit
application. The permittee shall notify the Director in writing not later than ninety (90) days prior to
instituting use of any additional biocide used in cooling systems which may be toxic to aquatic life
other than those previously reported to the Division of Water Resources. Such notification shall
include completion of Biocide Worksheet Form 101 and a map locating the discharge point and
receiving stream. Completion of a Biocide Worksheet 101 is not necessary for the introduction of a
new biocide into an outfall currently being tested for toxicity.
A. (7.) SPECIAL CONDITIONS
The following special conditions are applicable to all outfalls regulated by NC0004961:
0 There shall be no discharge of polychlorinated biphenyl compounds.
Discharge of any product registered under the Federal Insecticide, Fungicide, and Rodenticide Act
to any waste stream which may ultimately be released to lakes, rivers, streams or other waters of
the United States is prohibited unless specifically authorized elsewhere in this permit. Discharge
of chlorine from the use of chlorine gas, sodium hypochlorite, or other similar chlorination
compounds for disinfection in the plant potable and service water systems and in sewage
treatment is authorized. Use of restricted use pesticides for lake management purposes by
applicators licensed by the N.C. Pesticide Board is allowed.
o The Permittee shall report all visible discharges of floating materials, such as an oil sheen, to the
Director when submitting DMRs
A. (8.) PERMIT TERMS
The following are applicable to all outfalls regulated by NC0004961:
• It has been determined from information submitted that the plans and procedures in place at
Riverbend Steam Station are equivalent to that of a BMP.
A. (9.) ASH SETTLING BASIN
Beginning on the effective date of this permit and lasting until expiration, there shall be no discharge
of plant wastewater to the ash pond unless the Permittee provides and maintains at all times a
minimum free water volume (between the top of the sediment level and the minimum discharge
elevation) equivalent to the sum of the maximum 24-hour plant discharges plus all direct rainfall and
all runoff flows to the pond resulting from a 10 -year, 24-hour rainfall event, when using a runoff
coefficient of 1.0. During the term of the permit, the Permittee shall remove settled material from the
ponds or otherwise enlarge the available storage capacities in order to maintain the required
minimum volumes at all times. The Permittee shall determine and report to the permit issuing
authority the following on an annual basis:
1) the actual free water volume of the ash pond,
2) physical measurements of the dimensions of the free water volume in sufficient detail to allow
validation of the calculated volume, and
3) a certification that the required volume is available with adequate safety factor to include all
solids expected to be deposited in the pond for the following year.
Present information indicates a needed volume of 86.2 acre-feet in addition to solids that will be
deposited to the ash pond; any change to plant operations affecting such certification shall be
reported to the Director within five days.
NOTE: In the event that adequate volume has been certified to exist for the term of the permit,
periodic certification is not needed.
Page 9 of 27

Permit NC0004961
A.(10.) GROUNDWATER MONITORING WELL CONSTRUCTION AND SAMPLING
The permittee shall conduct groundwater monitoring to determine the compliance of this NPDES
permitted facility with the current groundwater Standards found under 15A NCAC 2L .0200. The
monitoring shall be conducted in accordance with the Sampling Plan approved by the Division.
A. (11.) STRUCTURAL INTEGRITY INSPECTIONS OF ASH POND DAM
The facility shall meet the dam design and dam safety requirements per 15A NCAC 2K.
A.(12.) FISH TISSUE MONITORING NEAR ASH POND DISCHARGE
The facility shall conduct fish tissue monitoring annually and submit the results with the NPDES
permit renewal application. The objective of the monitoring is to evaluate potential uptake of pollutants
by fish tissue near the Ash Pond discharge. The parameters analyzed in fish tissue shall be arsenic,
selenium, and mercury. The monitoring shall be conducted in accordance with the Sampling Plan
approved by the Division.
A.(13.) INSTREAM MONITORING
The facility shall conduct semiannual instream monitoring (one upstream and one downstream of the
ash pond discharge) for arsenic, selenium, mercury (method 1631E), chromium, lead, cadmium,
copper, zinc, total hardness, and total dissolved solids (TDS). Instream monitoring should be
conducted at the stations that have already been established through the BIP monitoring program: B
(upstream of,the Outfall 002) and C (downstream of the Outfall 002). The monitoring results shall be
submitted with the NPDES permit renewal application.
A.(14.) ASH POND CLOSURE '
The facility shall prepare an Ash Pond Closure Plan in anticipation of the facility closure. This Plan
shall be submitted to the Division one month prior to the decommissioning of the ponds.
A.(15.) PRIORITY POLLUTANT ANALYSIS
The Permittee shall conduct a priority pollutant analysis (in accordance with 40 CFR Part 136) once
per permit cycle at outfall 002 and submit the results with the application for permit renewal.
A.(16.) SEEP POLLUTANT ANALYSIS
The facility identified 12 unpermitted seeps (all non -engineered) from the ash settling basin, of which
10 of the seeps have been classified as "jurisdictional waters" by the United States Army Corps of
Engineers.
Jurisdictional Water Seeps.
For the jurisdictional water seeps, the facility shall determine within 90 days from the effective date
of the permit if a seep meets the state water quality standards established in 15A NCAC 2B .0200
and submit the results of this determination to the Division. If the standards are not contravened,
the facility shall conduct monitoring for the parameters specified in A. (2 1.), A. (22.), A. (23.), A. (24.),
A. (25.), A. (26.), A. (27.), A. (28.), A. (29.), A. (30.), A. (31.), and A. (32.).
If any of the water quality standards are exceeded (with the exception of the Action Level standards),
the facility shall be considered in violation of the Clean Water Act until one of the options below is
fully implemented. The facility shall:
1) Submit a complete application for 404 Permit (within 30 days after determining that a water
quality standards exceeded) to pump the seep discharge to one of the existing outfalls, install
a pipe to discharge the seep to the Catawba River, or install an in-situ treatment system.
After the 404 Permit is obtained, the facility shall complete the installation of the pump, pipe,
or treatment system within 180 days from the date of the 404 permit receipt and begin
pumping/ discharging or treatment.
2) Demonstrate through modeling that the decanting and dewatering of the ash basin will result
in the elimination of the seep and submit the modeling results to the Division within 120 days
from the effective date of the permit. Within 180 days from the completion of the dewatering
Page 10 of 27

Permit NC0004961
the facility shall confirm that the seep flow ceased. If the seep flow continues, the facility
shall choose one of the other options in this Special Condition.
3) Demonstrate that the seep is discharging through the designated "Effluent Channel" and the
water quality standards in the receiving stream are not contravened. This demonstration
should be submitted to the Division no later than 180 days from the effective date of the
permit. The "Effluent Channel" designation should be established by the DEQ Regional Office
personnel prior to the issuance of the permit and appropriate 404 permit shall be obtained.
All effluent limits, including water quality -based effluent limits, remain applicable notwithstanding
any action by the Permittee to address the violation through one of the identified options, so that any
discharge in exceedance of an applicable effluent limit is a violation of the Permit as long as the seep
remains flowing.
If jurisdictional water seeps contravene Action Level Standard, the facility shall conduct a Whole
Effluent Toxicity Test (WET test). If the WET result passes, the facility shall be considered in
compliance with the state water quality standards. If the WET test fails and the Toxicity Identification
Evaluation determines that the parameter contravening the water quality standard is responsible for
the failure the facility shall be considered in violation and, shall implement one of the 3 options
identified above.
Non -Jurisdictional Water Seeps
For the non jurisdictional water seeps the facility shall demonstrate that they will not violate water
quality standards in the receiving stream or that the seep does not discharge to jurisdictional waters
or that the seep does not carry pollutants indicating ash characteristics and submit this
demonstration to the Division within 90 days from the effective date of the permit. If such
demonstration is not possible or not approved by the Division, the facility shall choose one of the 3
options identified above.
New Identified Seeps
If new seeps are identified, the facility shall follow the procedures outlined above for either
jurisdictional waters or non jurisdictional waters. The deadlines for new seeps shall be calculated
from the date of the seep discovery.
Table 1. List of Identified Seeps
The permittee has identified 12 potentially contaminated seeps in the areas adjacent to the Mountain
Island Lake. The locations of the seeps are identified on the map attached to the permit.
Seep Coordinates and Assigned Outfall Numbers
Seep ID
Latitude
Longitude
Outfall number
S-1
35.365
-80.967
101
S-2
35.365
-80.966
102
S-3
36.369
-80.965
103
S-4
35.371
-80.963
104
S-5*
35.370
-80.963
105
S-6
35.367
-80.958
106
S-7
35.367
-80.957
107
S-8*
35.365
-80.956
108
S-9
35.371
-80.963
109
S-10
35.369
-80.960
110
S-11
35.369
-80.960
111
S-12
1 35.368
1 -80.959
1 112
*Non jurisdictional seeps
Page 11 of 27

Permit NC0004961
A. (17.) ELECTRONIC REPORTING OF DISCHARGE MONITORING REPORTS
(State Enforceable Only) [G.S. 143-215.1(b)]
Proposed federal regulations require electronic submittal of all discharge monitoring reports (DMRs)
and specify that, if a state does not establish a system to receive such submittals, then permittees
must submit DMRs electronically to the Environmental Protection Agency (EPA). The Division
anticipates that these regulations will be adopted and is beginning implementation in late 2013.
NOTE: This special condition supplements or supersedes the following sections within Part II of this
permit (Standard Conditions for NPDES Permits):
• Section B. (11.) Signatory Requirements
• Section D. (2.)
• Section D. (6.)
• Section E. (5.)
Reporting
Records Retention
Monitoring Reports
1. Reporting [Supersedes Section D. (2.) and Section E. (5.) (a)]
Beginning no later than 270 days from the effective date of this permit, the permittee shall begin
reporting discharge monitoring data electronically using the NC DWR's Electronic Discharge
Monitoring Report (eDMR) internet application.
Monitoring results obtained during the previous month(s) shall be summarized for each month
and submitted electronically using eDMR. The eDMR system allows permitted facilities to enter
monitoring data and submit DMRs electronically using the internet. Until such time that the
state's eDMR application is compliant with EPA's Cross -Media Electronic Reporting Regulation
(CROMERR), permittees will be required to submit all discharge monitoring data to the state
electronically using eDMR and will be required to complete the eDMR submission by printing,
signing, and submitting one signed original and a copy of the computer printed eDMR to the
following address:
NC DENR / DWR / Information Processing Unit
ATTENTION: Central Files / eDMR
1617 Mail Service Center
Raleigh, North Carolina 27699-1617
If a permittee is unable to use the eDMR system due to a demonstrated hardship or due to the
facility being physically located in an area where less than 10 percent of the households have
broadband access, then a temporary waiver from the NPDES electronic reporting requirements
may be granted and discharge monitoring data may be submitted on paper DMR forms (MR 1,
1. 1, 2, 3) or alternative forms approved by the Director. Duplicate signed copies shall be
submitted to the mailing address above.
Requests for temporary waivers from the NPDES electronic reporting requirements must be
submitted in writing to the Division for written approval at least sixty (60) days prior to the date
the facility would be required under this permit to begin using eDMR. Temporary waivers shall
be valid for twelve (12) months and shall thereupon expire. At such time, DMRs shall be
submitted electronically to the Division unless the permittee re -applies for and is granted a new
temporary waiver by the Division.
Information on eDMR and application for a temporary waiver from the NPDES electronic
reporting requirements is found on the following web page:
http; J I-portal.ncdenr.org/web/­wq / admin/ bog/ ipu l edmr
Page 12 of 27

Permit NC0004961
Regardless of the submission method, the first DMR is due on the last day of the month following
the issuance of the permit or in the case of a new facility, on the last day of the month following
the commencement of discharge.
2. Signatory Requirements [Supplements Section B. (11.) (b) and supersedes Section B. (11.)
1AH
All eDMRs submitted to the permit issuing authority shall be signed by a person described in
Part II, Section B. (11.)(a) or by a duly authorized representative of that person as described in
Part II, Section B. (11.)(b). A person, and not a position, must be delegated signatory authority
for eDMR reporting purposes.
For eDMR submissions, the person signing and submitting the DMR must obtain an eDMR user
account and login credentials to access the eDMR system. For more information on North
Carolina's eDMR system, registering for eDMR and obtaining an eDMR user account, please visit
the following web page:
http: / /portal.ncdenr.org/­`­web/wq / admin/ bog/ipu/ edmr
Certification. Any person submitting an electronic DMR using the state's eDMR system shall
make the following certification [40 CFR 122 22]. NO OTHER STATEMENTS OF CERTIFICATION
WILL BE ACCEPTED:
"I certify, under penalty of law, that this document and all attachments were prepared under my
direction or supervision in accordance with a system designed to assure that qualified personnel
properly gather and evaluate the information submitted. Based on my inquiry of the person or
persons who manage the system, or those persons directly responsible for gathering the
information, the information submitted is, to the best of my knowledge and belief, true, accurate,
and complete. I am aware that there are significant penalties for submitting false information,
including the possibility of fines and imprisonment for knowing violations. "
3. Records Retention [Supplements Section D. (6.)1
The permittee shall retain records of all Discharge Monitoring Reports, including eDMR
submissions. These records or copies shall be maintained for a period of at least 3 years from
the date of the report. This period may be extended by request of the Director at any time [40
CFR 122.411.
A. (18.) APPLICABLE STATE LAW (State Enforceable Only)
This facility shall meet the requirements of Senate Bill 729 (Coal Ash Management Act). This permit
may be reopened to include new requirements imposed by Senate Bill 729.
Page 13 of 27

Permit NC0004961
A. (19.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
011) [15A NCAC 02B .0400 et seq., 02B .0500 et seq ]
During the period beginning on the effective date of this permit and lasting until expiration, the
Permittee is authorized to discharge from outfall 011 — Former Stormwater Outfall 1. Such
discharges shall be limited and monitored3 by the Permittee as specified below:
EFFLUENT
CHARACTERISTICS
LIMITS
MONITORING REQUIREMENTS
Monthly Daily
Average Maximum
Measurement Sample Type Sample Location
Frequency
Flow, MGD
Monthly
Pump logs or
estimate
Influent or Effluent
Total Suspended Solids
23.0 mg/L 75 0 mg/L
Monthly
Grab
Effluent
Oil and Grease
11.0 mg/L 15.0 mg/L
Annually
Grab
Effluent
Total Arsenic, g/L
Quarterly
Grab
Effluent
Total Selenium, pg/L
Quarterly
Grab
Effluent
Total Mercury4, ng/L
Quarterly
Grab
Effluent
Nitrate/nitrate as N, mg/L
Quarterly
Grab
Effluent
Total Phosphorus, mg/L
Semi-annually
Grab
Effluent
Total Nitrogen (NO2 + NO3 + TKN),
mg/L
Semi-annually
Grab
Effluent
pHl
Monthly
Grab
Effluent
Turbidity2, NTU
Monthly
Grab
Effluent
Notes.
1. The pH shall not be less than 6.0 standard units nor greater than 9.0 standard units.
2. The discharge from this facility shall not cause turbidity in the receiving stream to exceed 50
NTU. If the instream turbidity exceeds 50 NTU due to natural background conditions, the
discharge cannot cause turbidity to increase in the receiving stream.
NTU - Nephelometric Turbidity Unit
3. No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system. See
Special Condition A. (18.).
4. The facility shall use EPA method 1631E.
There shall be no discharge of floating solids or visible foam in other than trace
amounts.
A. (20.) ADDITIONAL CONDITIONS AND DEFINITIONS
1 EPA methods 200.7 or 200 8 (or the most current versions) shall be used for analyses of all
metals except for total mercury
2. All effluent samples for all external outfalls shall be taken at the most accessible location after
the final treatment but prior to discharge to waters of the U.S. (40 CFR 122.410).
3. The term low volume waste sources means wastewater from all sources except those for which
specific limitations are otherwise established in this part (40 CFR 423.11 (b)).
4. The term chemical metal cleaning waste means any wastewater resulting from cleaning any
metal process equipment with chemical compounds, including, but not limited to, boiler tube
cleaning (40 CFR 423.11 (c)).
5. The term metal cleaning waste means any wastewater resulting from cleaning [with or
without chemical cleaning compounds] any metal process equipment including, but not
limited to, boiler tube cleaning, boiler fireside cleaning, and air preheater cleaning (40 CFR
42 3. 11 (d)).
6 For all outfalls where the flow measurement is to be "estimated" the estimate can be done by
using calibrated V -notch weir, stop -watch and graduated cylinder, or other method approved
by the Division
Page 14 of 27

Permit NC0004961
A. (21.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
101) [15A NCAC 02B .0400 et seq., 02B .0500 et seq.]
During the period beginning on the effective date of this permit and lasting until expiration, the
Permittee is authorized to discharge from outfall 101 — Seep Discharge. Such discharges shall be
limited and monitored' by the Permittee as specified below:
EFFLUENT
CHARACTERISTICS
LIIVITS
Monthly Daily
Average Maximum
MONITORING REQUIREMENTS
Measurement Sample Type Sample Location
Frequencyz
Flow, MGD
Monthly/Quarterly
Estimate
Effluent
H3
Monthly/Quarterly
Grab
Effluent
Fluoride
18 mg/L
18 mg/L
Monthly/Quarterly
Grab
Effluent
Total Mercur 4, ng/L
Monthly/Quarterly
Grab
Effluent
Total Barium
1.0 mg/L
1,0 m /L
Monthly/Quarterly
Grab
Effluent
Total Iron, mg/L
Monthly/Quarterly
Grab
Effluent
Total Manganese, fag/L
Month ly/Quarterly
Grab
Effluent
Total Zinc, fag/L
Monthly/Quarterly
Grab
Effluent
Total Arsenic
10 0 pg/L
50.0 Ng/L
Monthly/Quarterly
Grab
Effluent
Total Cadmium
2.0 fag/L
15 0 pg/L
Monthly/Quarterly
Grab
Effluent
Total Chromium
50 0 g/L
1,022 0 pg/L
Month ly/Quarterly
Grab
Effluent
Total Copper, g/L
Month' /Q arterly
Grab
Effluent
Total Lead, fag/L
25.0 g/L
33 8 Ng/L
Monthly/Quarterly
Grab
Effluent
Total Nickel
25.0 lag/L
25 0 fag/L
Monthly/Quarterly
Grab
Effluent
Total Selenium
5.0 g/L
56.0 fag/L
Month ly/Quarterly
Grab
Effluent
Nitrate as N
10.0 mg/L
10.0 mg/L
Monthly/Quarterly
Grab
Effluent
Sulfates
250 0 mg/L
250.0 mg/L
Monthly/Quarterly
Grab
Effluent
Chlorides
250 0 mg/L
250.0 mg/L
Monthly/Quarterly
Grab
Effluent
TDS
500 0 mg/L
500.0 m /L
Month ly/Quarterly
Grab
Effluent
Total Hardness, mg/L
100.0 mg/L
100 0 mg/L
Monthly/Quarterly
Grab
Effluent
TSS
30.0 mg/L
100 0 mg/L
Monthly/Quarterly
Grab
Effluent
Oil and Grease
15.0 mg/L
20.0 mg/L
Monthly/Quarterly
Grab
Effluent
Temperature, OC
Monthly/Quarterly
Grab
Effluent
Specific Conductance, prnho/cm
Monthly/Quarterly
Grab
Effluent
Notes:
1. No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system. See Special
Condition A. (18.).
2. The facility shall conduct monthly sampling from the effective date of the permit. After one year
from the effective date of the permit the monitoring will be reduced to quarterly
3. The pH shall not be less than 6 0 star dard units nor greater than 9 0 standard units
4. The facility shall use EPA method 1631E
If the facility is unable to obtain a seep sample due to the dry or low now conditions
preventing the facility from obtaining a representative sample, the "no flow" should be
reported on the DMR. This requirement is established in the Section D of the Standard
Conditions and 40 CFR 122.41 a).
There shall be no discharge of floating solids or visible foam in other than trace
amounts.
Page 15 of 27

Permit NC0004961
A. (22.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
102) [15A NCAC 02B 0400 et seq , 02B .0500 et seq,]
During the period beginning on the effective date of this permit and lasting until expiration, the
Permittee is authorized to discharge from outfall 102 - Seep Discharge. Such discharges shall be
limited and monitored' by the Permittee as specified below:
EFFLUENT
CHARACTERISTICS
LIMITS
Monthly Daily
Average Maximum
MONITORING REQUIREMENTS
Measurement Sample Type Sample Location
Frequency'
Flow, MGD
Monthly/Quarterly
Estimate
Effluent
pH3
Month' /Quarterly
Grab
Effluent
Fluoride
1.8 mg/L
1,8 mg/L
Month' /Quarterly
Grab
Effluent
Total Mercur 4, ng/L
Monthly/Qu rterl
Grab
Effluent
Total Barium
10 mg/L
10 mg/L
Monthly/Quarterly
Grab
Effluent
Total Iron, mg/L
Monthly/Quarterly
Grab
Effluent
Total Manganese, Hg/L
Monthly/Quarterly
Grab
Effluent
Total Zinc, pg/L
Monthly/Quarterly
Grab
Effluent
Total Arsenic
10 0 pg/L
50 0 Ng/L
Monthly/Quarterly
Grab
Effluent
Total Cadmium
2 0 pg/L
15 0 Ng/L
Monthly/Quarter)
Grab
Effluent
Total Chromium
50 0 pg/L
1,022 0 Ng/L
Monthly/Quarterly
Grab
Effluent
Total Copper, /L
Monthly/Qu rterly
Grab
Effluent
Total Lead, pg/L
25.ONg/L
33.8 pg/L
Monthly/Quarterly
Grab
Effluent
Total Nickel
25.0 Hg/L
25.0 Hg/L
Monthly/Quarterly
Grab
Effluent
Total Selenium
5 0 Hg/L
56.0 pg/L
Monthly/Quarterly
Grab
Effluent
Nitrate as N
10.0 mg/L
10 0 mg/L
Monthly/Quarterly
Grab
Effluent
Sulfates
250.0 mg/L
250.0 mg/L
Monthly/Quarterly
Grab
Effluent
Chlorides
250.0 mg/L
250.0 mg1L
Month ly/Quarteriy
Grab
Effluent
TDS
500.0 mg/L
500.0 mg/L
Monthly/Quarterly
Grab
Effluent
Total Hardness, mg/L
100.0 mg/L
100 0 mg/L
Monthly/Quarterly
Grab
Effluent
TSS, mg/L
30 0 mg/ L
100 0 mg/L_
Monthly/Quarterly
Grab
Effluent
Oil and Grease
15 0 mg/L
20.0 mg/L
Monthly/Quarterly
Grab
Effluent
Temperature, OC
Monthly/Quarterly
Grab
Effluent
Specific Conductance, pmho/cm
Monthly/Quarterly
Grab
Effluent
Notes:
1. No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system. See Special
Condition A (18.).
2 The facility shall conduct monthly sampling from the effective date of the permit After one year
from the effective date of the permit the monitoring will be reduced to quarterly
3. The pH shall not be less than 6.0 standard units nor greater than 9.0 standard units
4. The facility shall use EPA method 1631E.
If the facility is unable to obtain a seep sample due to the dry or low now conditions
preventing the facility from obtaining a representative sample, the "no flow" should be
reported on the DMR. This requirement is established in the Section D of the Standard
Conditions and 40 CFR 122.410).
There shall be no discharge of floating solids or visible foam in other than trace
amounts.
Page 16 of 27

Permit NC0004961
A. (23.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
103) [15A NCAC 02B .0400 et seq., 02E .0500 et seq.]
During the period beginning on the effective date of this permit and lasting until expiration, the
Permittee is authorized to discharge from outfall 103 — Seep Discharge. Such discharges shall be
limited and monitored' by the Permittee as specified below:
EFFLUENT
CHARACTERISTICS
LIMITS
Monthly Daily
Average Maximum
MONITORING REQUIREMENTS
Measurement Sample Type Sample Location
Frequencyz
Flow, MGD
Monthly/Quarterly
Estimate
Effluent
pH3
Month ly/Quarterly
Grab
Effluent
Fluoride
18 mg/L
18 mg/L
Monthly/Quarterly
Grab
Effluent
Total Mercury4, ng/L
Monthly/Quarterly
Grab
Effluent
Total Barium
1,0 mg/L
1.0 mg/L
Monthly/Quarterly
Grab
Effluent
Total Iron, mg/L
Monthly/Quarterly
Grab
Effluent
Total Manganese, Ng/L
Monthly/Quarterly
Grab
Effluent
Total Zinc, Hg/L
Monthly/Quarterly
Grab
Effluent
Total Arsenic
10.0 pg/L
50 0 Hg/L
Monthly/Quarterly
Grab
Effluent
Total Cadmium
2 0 Ug/L
15 0 g/L
Month' /Quarterly
Grab
Effluent
Total Chromium
50 0 Hg/L
1,022 0 pg/L
Month' /Quarter)
Grab
Effluent
Total Copper, H /L
Monthly/Qu rterl
Grab
Effluent
Total Lead, Hg/L
25 ONg/L
33.8 Hg/L
Monthly/Quarterly
Grab
Effluent
Total Nickel
25.0 g/L
25.0 Ng/L
Monthly/Quarterly
Grab
Effluent
Total Selenium
5.0 Hg/L
56 0 Hg/L
Monthly/Quarterly
Grab
Effluent
Nitrate as N
10.0 mg/L
10.0 mg/L
Monthly/Quarterly
Grab
Effluent
Sulfates
250.0 mg/L
250 0 mg/L
Month' /Quarterly
Grab
Effluent
Chlorides
250,0 mg/L
250 0 mg/L
Monthly/Quarterly
Grab
Effluent
TDS
500.0 mg/L
500 0 mg/L
Month' /Qu arteqy
Grab
Effluent
Total Hardness, mg/L
100 0 mg/L
100 0 mg/L
Monthly/Quarterly
Grab
Effluent
TSS, mg/L
30 0 mg/L
100 0 mg/L
Monthly/Quarterly
Grab
Effluent
Oil and Grease
15 0 mg/L
20.0 mg/L
Monthly/Quarterly
Grab
Effluent
Temperature, OC
Monthly/Quarterly
Grab
Effluent
Specific Conductance, Nmho/cm
Monthly/Quarterly
Grab
Effluent
Notes:
1. No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system. See Special
Condition A. (18.).
2 The facility shall conduct monthly sampling from the effective date of the permit After one year
from the effective date of the permit the monitoring will be reduced to quarterly
3 The pH shall not be less than 6.0 standard units nor greater than 9 0 standard units.
4. The facility shall use EPA method 1631E.
If the facility is unable to obtain a seep sample due to the dry or low flow conditions
preventing the facility from obtaining a representative sample, the "no flow" should be
reported on the DMR. This requirement is established in the Section D of the Standard
Conditions and 40 CFR 122.41 (j).
There shall be no discharge of floating solids or visible foam in other than trace
amounts.
Page 17 of 27

Permit NC0004961
A. (24.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
104) [15A NCAC 02B .0400 et seq., 02B.0500 et seq.]
During the period beginning on the effective date of this permit and lasting until expiration, the
Permittee is authorized to discharge from outfall 104 — Seep Discharge. Such discharges shall be
limited and monitored' by the Permittee as specified below:
EFFLUENT
CHARACTERISTICS
LIMITS
Monthly Daily
Average Maximum
MONITORING REQUIREMENTS
Measurement Sample Type Sample Location
Frequencyz
Flow, MGD
Monthly/Quarterly
Estimate
Effluent
H3
Monthly/Quarterly
Grab
Effluent
Fluoride
18 mg/L
1.8 mg/L
Month ly/Quarterly
Grab
Effluent
Total Mercury4, ng/L
Monthly/Quarterly
Grab
Effluent
Total Barium
10 mg/L
10 mg/L
Month/ /Quarterly
Grab
Effluent
Total Iron, mg/L
Monthly/Quarterly
Grab
Effluent
Total Manganese, Hg/L
Monthly/Quarterly
Grab
Effluent
Total Zinc, Ng/L
Monthly/Qu rterly
Grab
Effluent
Total Arsenic
10.0 pg/L
50 0 Ng/L
Month/ /Quarterly
Grab
Effluent
Total Cadmium
2.0 g/L
15.0 g/L
Monthly/Quarterly
Grab
Effluent
Total Chromium
50.0 g/L
1,022 0 Ng/L
Month/ /Quarterly
Grab
Effluent
Total Copper, pg/L
Monthly/Qu rterly
Grab
Effluent
Total Lead, pg/L
25.OHg/L
33.8 Ng/L
Monthly/Quarterly
Grab
Effluent
Total Nickel
25.0 pg/L
25.0 pg/L
Month/ /Quarterly
Grab
Effluent
Total Selenium
5 0 ug/L
56.0 pg/L
Monthly/Quarterly
Grab
Effluent
Nitrate as N
10.0 mg/L
10.0 mg/L
Monthly/Quarterly
Grab
Effluent
Sulfates
250.0 mg/L
250.0 mg/L
Monthly/Quarterly
Grab
Effluent
Chlorides
250 0 m /L
250.0 mg/L
Monthly/Quarterly
Grab
Effluent
TDS
500 0 mg/L
500.0 mg/L
Month/ /Quarterl
Grab
Effluent
Total Hardness, mg/L
100.0 mg/L
100 0 mg/L
Month/ /Quarterly
Grab
Effluent
TSS, mg/L
30.0 mg/L
100 0 mg/L
Monthly/Quarterly
Grab
Effluent
Oil and Grease
15.0 mg/L
20 0 mg/L
Monthly/Quarterly
Grab
Effluent
Temperature, OC
Monthly/Quarterly
Grab
Effluent
Specific Conductance, pmho/cm
Monthly/Quarterly
Grab
Effluent
Notes:
1. No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system. See Special
Condition A. (18.).
2. The facility shall conduct monthly sampling from the effective date of the permit. After one year
from the effective date of the permit the monitoring will be reduced to quarterly
3. The pH shall not be less than 6.0 standard units nor greater than 9.0 standard units.
4. The facility shall use EPA method 1631E
If the facility is unable to obtain a seep sample due to the dry or low flow conditions
preventing the facility from obtaining a representative sample, the "no flow" should be
reported on the DMR. This requirement is established in the Section D of the Standard
Conditions and 40 CFR 122.410).
There shall be no discharge of floating solids or visible foam in other than trace
amounts.
Page 18 of 27

Permit NC0004961
A. (25.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
105) [15A NCAC 02B .0400 et seq., 02B 0500 et seq ]
During the period beginning on the effective date of this permit and lasting until expiration, the
Permittee is authorized to discharge from outfall 105 — Seep Discharge. Such discharges shall be
limited and monitored' by the Permittee as specified below:
EFFLUENT
CHARACTERISTICS
LIMITS
Monthly Daily
Average Maximum
MONITORING REQUIREMENTS
Measurement Sample Type Sample Location
Frequency2
Flow, MGD
Monthly/Quarterly
Est[mate
Effluent
H3
Month/ /Quarterly
Grab
Effluent
Fluoride
18 mg/L
18 mg/L
Month/ /Quarter)
Grab
Effluent
Total Mercu 4, ng/L
Monthly/Qu rterl
Grab
Effluent
Total Barium
10 mg/L
1.0 mg/L
Monthly/Quarterly
Grab
Effluent
Total Iron, mg/L
Monthly/Quarterly
Grab
Effluent
Total Manganese, pg/L
Monthly/Quarterly
Grab
Effluent
Total Zinc, pg/L
Monthly/Quarterly
Grab
Effluent
Total Arsenic
10.0 pg/L
50 0 pg/L
Monthly/Quarterly
Grab
Effluent
Total Cadmium
2 0 pg/L
15 0 pg/L
Month/ /Quarterly
Grab
Effluent
Total Chromium
50 0 g/L
1,022 0 g/L
Monthly/Quarterly
Grab
Effluent
Total Copper, pg/L
Month/ /Quarterly
Grab
Effluent
Total Lead, pg/L
25.Opg/L
33 8 pg/L
Month/ /Quarterly
Grab
Effluent
Total Nickel
25 0 lug/L
25 0 pg/L
Monthly/Quarterly
Grab
Effluent
Total Selenium
5.0 pg/L
56.0 pg/L
Monthly/Quarterly
Grab
Effluent
Nitrate as N
10.0 mg/L
10 0 mg/L
Monthly/Quarterly
Grab
Effluent
Sulfates
250 0 mg/L
250 0 mg/L
Monthly/Quarterly
Grab
Effluent
Chlorides
250 0 mg/L
250.0 mg/L
Month ly/Quarterly
Grab
Effluent
TDS
500 0 mg/L
500 0 mg/L
Month/ /Quarterly
Grab
Effluent
Total Hardness, mg/L
100.0 mg/L
100 0 mg/L
Month/ /Quarterly
Grab
Effluent
TSS, mg/L
30.0 mg/L
100.0 mg/L
Month/ /Quarterly
Grab
Effluent
Oil and Grease
15.0 mg/L
20.0 mg/L
Monthly/Quarterly
Grab
Effluent
Temperature, OC
Monthly/Quarterly
Grab
Effluent
Specific Conductance, Nmho/cm
Monthl /Quarterly
Grab
Effluent
Notes:
1. No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system. See Special
Condition A. (18.).
2 The facility shall conduct monthly sampling from the effective date of the permit. After one year
from the effective date of the permit the monitoring will be reduced to quarterly
3. The pH shall not be less than 6.0 standard units nor greater than 9.0 standard units.
4 The facility shall use EPA method 1631E
If the facility is unable to obtain a seep sample due to the dry or low flow conditions
preventing the facility from obtaining a representative sample, the "no flow" should be
reported on the DMR. This requirement is established in the Section D of the Standard
Conditions and 40 CFR 122.41 (j).
There shall be no discharge of floating solids or visible foam in other than trace
amounts.
Page 19 of 27

Permit NC0004961
A. (26.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
106) [15A NCAC 02B .0400 et seq , 02B .0500 et seq.]
During the period beginning on the effective date of this permit and lasting until expiration, the
Permittee is authorized to discharge from outfall 106 — Seep Discharge. Such discharges shall be
limited and monitored' by the Permittee as specified below -
EFFLUENT
CHARACTERISTICS
LIMITS
Monthly Daily
Average Maximum
MONITORING REQUIREMENTS
Measurement Sample Type Sample Location
Frequency2
Flow, MGD
Monthly/Quarterly
Estimate
Effluent
pH3
Monthly/Qu rterl
Grab
Effluent
Fluoride
18 mg/L
1,8 mg/L
Monthly/Quarter)
Grab
Effluent
Total Mercury4, ng/L
Monthly/Quarterly
Grab
Effluent
Total Barium
10 mg/L
1,0 mg/L
Monthly/Quarterly
Grab
Effluent
Total Iron, mg/L
Monthly/Quarterly
Grab
Effluent
Total Manganese, pg/L
Monthly/Quarterly
Grab
Effluent
Total Zinc, pg/L
Monthly/Quarterly
Grab
Effluent
Total Arsenic
10 0 pg/L
50,0 pg/L
Monthly/Quarterly
Grab
Effluent
Total Cadmium
2.0 pg/L
15 0 Ng/L
Month' /Quarterly
Grab
Effluent
Total Chromium
50 0 g/L
1,022 0 pg/L
Month' /Quarterly
Grab
Effluent
Total Copper, Ng/L
Monthly/Qu rterly
Grab
Effluent
Total Lead, Ng/L
25 ONg/L
33 8 pg/L
Monthly/Quarterly
Grab
Effluent
Total Nickel
25.0 pg/L
25.0 Ng/L
Monthly/Quarterly
Grab
Effluent
Total Selenium
5 0 pg/L
56 0 pg/L
Monthly/Quarterly
Grab
Effluent
Nitrate as N
10,0 mg/L
10 0 mg/L
Monthly/Quarterly
Grab
Effluent
Sulfates
250 0 mg/L
250 0 mg/L
Monthly/Quarterly
Grab
Effluent
Chlorides
250 0 mg/L
250.0 mg/L
Month ly/Quarterly
Grab
Effluent
TDS
500 0 mg/L
500.0 mg/L
Month' /Q arterly
Grab
Effluent
Total Hardness, mg/L
100.0 mg/L
100 0 mg/L
Monthly/Quarterly
Grab
Effluent
TSS, mg/L
30.0 mg/L
100 0 mg/L
Monthly/Quarterly
Grab
Effluent
Oil and Grease
15 0 mg/L
20.0 mg/L
Monthly/Quarterly
Grab
Effluent
Temperature, OC
Month' /Quarterly
Grab
Effluent
Specific Conductance, pmho/cm
Monthly/Quarterly
Grab
Effluent
Notes:
1. No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system. See Special
Condition A. (18.).
2 The facility shall conduct monthly sampling from the effective date of the permit After one year
from the effective date of the permit the monitoring will be reduced to quarterly
3. The pH shall not be less than 6.0 standard units nor greater than 9.0 standard units.
4. The facility shall use EPA method 1631E.
If the facility is unable to obtain a seep sample due to the dry or low flow conditions
preventing the facility from obtaining a representative sample, the "no flow" should be
reported on the DMR. This requirement is established in the Section D of the Standard
Conditions and 40 CFR 122.41 (j).
There shall be no discharge of floating solids or visible foam in other than trace
amounts.
Page 20 of 27

Permit NCOOO4961
A. (27.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
107) [15A NCAC 0213 .0400 et seq , 02B.0500 et seq.]
During the period beginning on the effective date of this permit and lasting until expiration, the
Permittee is authorized to discharge from outfall 107 — Seep Discharge. Such discharges shall be
limited and monitored' by the Permittee as specified below:
EFFLUENT
CHARACTERISTICS
LIMITS
Monthly Daily
Average Maximum
MONITORING REQUIREMENTS
Measurement Sample Type Sample Location
Frequencyz
Flow, MGD
Monthly/Quarterly
Estimate
Effluent
pH3
Monthly/Qu rterl
Grab
Effluent
Fluoride
18 mg/L
18 mg/L
MonthlylQuarterly
Grab
Effluent
Total Mercur 4, ng/L
Monthly/Quarterly Monthly/Quarterly
Grab
Effluent
Total Barium
10 mg/L
1.0 mg/L
Monthly/Quarterly
Grab
Effluent
Total Iron, mg/L
Month/ /Quarterly
Grab
Effluent
Total Manganese, pg/L
Monthly/Quarterly
Grab
Effluent
Total Zinc, pg/L
Monthly/Qu rterly
Grab
Effluent
Total Arsenic
10.0 pg/L
50 0 pg/L
Monthly/Quarterly
Grab
Effluent
Total Cadmium
2,0 pg/L
15 0 pg/L
Monthly/Quarterly Monthly/Quarterly
Grab
Effluent
Total Chromium
50,0 g/L
1,022 0 HgIL
rterly
Grab
Effluent
Total Copper, pg/L
Monthly/Qu rterl
Grab
Effluent
Total Lead, pg/L
25,Opg/L
33 8 pg/L
Monthly/Quarterly
Grab
Effluent
Total Nickel
25 0 pg/L
25.0 pg/L
MonthlylQuarterly
Grab
Effluent
Total Selenium
5 0 pg/L
56 0 pg/L
Monthly/Quarterly
Grab
Effluent
Nitrate as N
10.0 mg/L
10 0 mg/L
Month/ /Quarterly
Grab
Effluent
Sulfates
250.0 mg/L
250.0 mg/L
Monthly/Quarterly
Grab
Effluent
Chlorides
250.0 mg/L
250 0 mg/L
Monthly/Quarterly Monthly/Quarterly
Grab
Effluent
TDS
500,0 mg/L
500 0 mg/L
Month ly/Quarterly
Grab
Effluent
Total Hardness, mg/L
100 0 mg/L
100.0 mg/L
Monthly/Quarterly
Grab
Effluent
TSS, mg/L
30,0 mg/L
100 0 mg/L
Monthly/Quarterly
Grab
Effluent
Oil and Grease
15 0 mg/L
20,0 mg/L
Monthly/Quarterly
Grab
Effluent
Temperature, OC
Monthly/Quarterly
Grab
Effluent
Specific Conductance, pmho/cm
Monthly/Quarterly
Grab
Effluent
Notes:
1. No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system. See Special
Condition A (18.)
2 The facility shall conduct monthly sampling from the effective date of the permit. After one year
from the effective date of the permit the monitoring will be reduced to quarterly
3. The pH shall not be less than 6.0 standard units nor greater than 9.0 standard units
4. The facility shall use EPA method 1631E
If the facility is unable to obtain a seep sample due to the dry or low flow conditions
preventing the facility from obtaining a representative sample, the "no flow" should be
reported on the DMR. This requirement is established in the Section D of the Standard
Conditions and 40 CFR 122.41 (j).
There shall be no discharge of floating solids or visible foam in other than trace
amounts.
Page 21 of 27

Permit NC0004961
A. (28.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
108) [15A NCAC 02B .0400 et seq., 02B .0500 et seq.]
During the period beginning on the effective date of this permit and lasting until expiration, the
Permittee is authorized to discharge from outfall 108 — Seep Discharge. Such discharges shall be
11m1ted and monitored) by the Permittee as specified below:
EFFLUENT
CHARACTERISTICS
LIMITS
Monthly Daily
Average Maximum
MONITORING REQUIREMENTS
Measurement Sample Type Sample Location
Frequency2
Flow, MGD
Monthly/Quarterly
Estimate
Effluent
pH3
Month ly/Quarterly
Grab
Effluent
Fluoride
1.8 mg/L
1.8 mg/L
Monthly/Quarterly
Grab
Effluent
Total Mercur 4, ng/L
Monthly/Quarterly
Grab
Effluent
Total Barium
10 mg/L
1.0 mg/L
Monthly/Quarterly
Grab
Effluent
Total Iron, mg/L
Monthly/Quarterly
Grab
Effluent
Total Manganese, Ng/L
Monthly/Quarterly
Grab
Effluent
Total Zinc, gIL
Monthly/Quarterly
Grab
Effluent
Total Arsenic
10.0 fag/L
50 0 lig/L
Monthly/Quarterly
Grab
Effluent
Total Cadmium
2 0 lag/L
15.0 gIL
Month) /Quarterl
Grab
Effluent
Total Chromium
50 0 tag/L
1,022 0 lag/L
Monthl/Quarterly
Grab
Effluent
Total Copper, lag/L
Month) /Qu rterly
Grab
Effluent
Total Lead, lag/L
25.ONg/L
33 8 pg/L
Monthly/Quarterly
Grab
Effluent
Total Nickel
25.0 Ng/L
25 0 lag/L
Month ly/Quarterl
Grab
Effluent
Total Selenium
5 0 tag/L
56 0 lag/L
Monthly/Quarterly
Grab
Effluent
Nitrate as N
10 0 mg/L
10 0 mg/L
Month ly/Quarterl y
Grab
Effluent
Sulfates
250.0 mg/L
250.0 mg/L
Month ly/Quarterly
Grab
Effluent
Chlorides
250,0 mg/L
250.0 mg/L.
Monthly/Quarterly
Grab
Effluent
TDS
500.0 mg/L
500,0 mg/L
Month ly/Quarterly
Grab
Effluent
Total Hardness, mg/L
100 0 mg/L
100 0 mg/L
Monthly/Quarterly
Grab
Effluent
TSS, mg/L
30 0 mg/L
100 0 mg/L
Month) lQuarterly
Grab
Effluent
Oil and Grease
15.0 mg/L
20 0 mg/L
Monthly/Quarterly
Grab
Effluent
Temperature, OC
Monthly/Quarterly
Grab
Effluent
Specific Conductance, pmho/cm
Monthly/Quarterly
Grab
Effluent
Notes:
1 No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system. See Special
Condition A. (18.)
2. The facility shall conduct monthly sampling from the effective date of the permit After one year
from the effective date of the permit the monitoring will be reduced to quarterly
3. The pH shall not be less than 6 0 standard units nor greater than 9.0 standard units.
4. The facility shall use EPA method 1631E.
If the facility is unable to obtain a seep sample due to the dry or low flow conditions
preventing the facility from obtaining a representative sample, the "no flow" should be
reported on the DMR. This requirement is established in the Section D of the Standard
Conditions and 40 CFR 122.41 (j).
There shall be no discharge of floating solids or visible foam in other than trace
amounts.
Page 22 of 27

Permit NC0004961
A. (29.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
1.09) [15A NCAC 02B .0400 et seq , 02B.0500 et seq.]
During the period beginning on the effective date of this permit and lasting until expiration, the
Permittee is authorized to discharge from outfall 109 — Seep Discharge. Such discharges shall be
limited and monitored' by the Permittee as specified below.
EFFLUENT
CHARACTERISTICS
LIMITS
Monthly Daily
Average Maximum
MONITORING REQUIREMENTS
Measurement Sample Type Sample Location
Frequenc 2
Flow, MGD
Monthly/Quarterly
Estimate
Effluent
pH3
Month' /Quarterly
Grab
Effluent
Fluoride
1.8 mg/L
18 mg/L
Monthly/Quarterly
Grab
Effluent
Total Mercury4, ng/L
Monthly/Qu rterl
Grab
Effluent
Total Barium
10 mg/L
1.0 mg/L
Monthly/Quarterly
Grab
Effluent
Total Iron, mg/L
Monthly/Quarterly
Grab
Effluent
Total Manganese, pg/L
Monthly/Quarterly
Grab
Effluent
Total Zinc, Hg/L
Monthly/Quarterly
Grab
Effluent
Total Arsenic
10 0 Hg/L
50 0 pg/L_
Month' /Quarterly
Grab
Effluent
Total Cadmium
2 0 g/L
15 0 pg/L
Month ly/Quarterly
Grab
Effluent
Total Chromium
50 0 ug/L
1,022 0 HgIL
Monthly/Quarterly
Grab
Effluent
Total Copper, pg/L
Month' /Q arterly
Grab
Effluent
Total Lead, pg/L
25 OHg/L
33.8 g/L
Monthly/Quarterly
Grab
Effluent
Total Nickel
25.0 Ng/L
25 0 pg/L
Monthly/Quarterly
Grab
Effluent
Total Selenium
5 0 Ng/L
56,0 Hg/L
Monthly/Quarterly
Grab
Effluent
Nitrate as N
10.0 mg/L
10.0 mg/L
Month' /Quarterly
Grab
Effluent
Sulfates
250 0 mg/L
250.0 mg/L
Monthly/Quarterly
Grab
Effluent
Chlorides
250 0 m /L
250.0 mg/L
Monthly/Quarterly
Grab
Effluent
TDS
500,0 mg/L
500 0 mg/L
Monthly/Quarterly
Grab
Effluent
Total Hardness, mg/L
100 0 mg/L
100 0 mg/L
Monthly/Quarterly
Grab
Effluent
TSS, mg/L
30 0 mg/L
100.0 mg/L
Monthly/Quarterly
Grab
Effluent
Oil and Grease
15 0 mg/L
20 0 mg/L
Monthly/Quarterly
Grab
Effluent
Temperature, OC
Monthly/Qu rterly
Grab
Effluent
Specific Conductance, Hmho/cm
Monthly/Quarterly
Grab
Effluent
Notes -
1. No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system. See Special
Condition A. (18.).
2. The facility shall conduct monthly sampling from the effective date of the permit. After one year
from the effective date of the permit the monitoring will be reduced to quarterly
3 The pH shall not be less than 6.0 standard units nor greater than 9.0 standard units.
4. The facility shall use EPA method 1631E.
If the facility is unable to obtain a seep sample due to the dry or low flow conditions
preventing the facility from obtaining a representative sample, the "no flow" should be
reported on the DMR. This requirement is established in the Section D of the Standard
Conditions and 40 CFR 122.41 (j).
There shall be no discharge of floating solids or visible foam in other than trace
amounts.
Page 23 of 27

Permit NC0004961
A. (30.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
110) [15A NCAC 02B .0400 et seq., 02B .0500 et seq.]
During the period beginning on the effective date of this permit and lasting until expiration, the
Permittee is authorized to discharge from outfall 110 — Seep Discharge Such discharges shall be
limited and monitored' by the Permittee as specified below.
EFFLUENT
CHARACTERISTICS
LIMITS
Monthly Daily
Average Maximum
MONITORING REQUIREMENTS
Measurement Sample Type Sample Location
Frequency2
Flow, MGD
Monthly/Quarterly
Estimate
Effluent
H3
Monthly/Qu rterl
Grab
Effluent
Fluoride
1.8 mg/L
18 mg/L
Monthly/Quarterly
Grab
Effluent
Total Mercury4, ng/L
Month ly/Quarterly
Grab
Effluent
Total Barium
10 mg/L
1.0 mg/L
Month/ /Quarterly
Grab
Effluent
Total Iron, mg/L
Monthly/Quarterly
Grab
Effluent
Total Manganese, Ng/L
Monthly/Quarterly
Grab
Effluent
Total Zinc, Ng/L
Monthly/Quarterly
Grab
Effluent
Total Arsenic
10.0 pg/L
50 0 pg/L
Monthly/Quarterly
Grab
Effluent
Total Cadmium
2 0 g/L
15.0 pg/L
Monthly/Quarterly
Grab
Effluent
Total Chromium
50.0 /L
1,022.0 pg/L
Monthly/Quarterly
Grab
Effluent
Total Copper, g/L
Monthly/Quarterly
Grab
Effluent
Total Lead, pg/L
25.Opg/L
33 8 lug/L
Monthly/Quarterly
Grab
Effluent
Total Nickel
25.0 pg/L
25 0 lug/L
Monthly/Quarterly
Grab
Effluent
Total Selenium
5 0 pg/L
56 0 pg/L
Monthly/Quarterly
Grab
Effluent
Nitrate as N
10.0 m /L
10 0 mg/L
Monthly/Quarterly
Grab
Effluent
Sulfates
250 0 mg/L
250 0 mg/L
Monthly/Quarterly
Grab
Effluent
Chlorides
250 0 m /L
250 0 mg/L
Month/ /Quarterly
Grab
Effluent
TDS
500 0 mg/L
500 0 mg/L
Month/ /Quarterly
Grab
Effluent
Total Hardness, mg/L
100.0 mg/L
100.0 mg/L
Monthly/Quarterly
Grab
Effluent
TSS, mg/L
30.0 mg/L
100.0 mg/L
Month/ /Quarterly
Grab
Effluent
Oil and Grease
15.0 mg/L
20,0 mg/L
Monthly/Quarterly
Grab
Effluent
Temperature, OC
Monthly/Quarterly
Grab
Effluent
Specific Conductance, pmho/cm
Monthly/Qu rterly
Grab
Effluent
Notes:
1. No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system. See Special
Condition A. (18.).
2. The facility shall conduct monthly sampling from the effective date of the permit After one year
from the effective date of the permit the monitoring will be reduced to quarterly
3. The pH shall not be less than 6.0 standard units nor greater than 9.0 standard units
4. The facility shall use EPA method 1631E.
If the facility is unable to obtain a seep sample due to the dry or low flow conditions
preventing the facility from obtaining a representative sample, the "no flow" should be
reported on the DMR. This requirement is established in the Section D of the Standard
Conditions and 40 CFR 122.410).
There shall be no discharge of floating solids or visible foam in other than trace
amounts.
Page 24 of 27

Permit NC0004961
A. (31.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
111) [15A NCAC 02B .0400 et seq., 02B .0500 et seq.]
During the period beginning on the effect_ve date of this permit and lasting until expiration, the
Permittee is authorized to discharge from outfall 111 - Seep Discharge. Such discharges shall be
limited and monitored' by the Permittee as specified below:
EFFLUENT
CHARACTERISTICS
LIMITS
Monthly Daily
Average Maximum
MONITORING REQUIREMENTS
Measurement Sample Type Sample Location
Frequency2
Flow, MGD
Monthly/Quarterly
Estimate
Effluent
pH3
Month' /Quarterly
Grab
Effluent
Fluoride
18 mg/L
1,8 mg/L
Monthly/Quarteqy
Grab
Effluent
Total Mercur 4, ng/L
Monthly/Qu rterly
Grab
Effluent
Total Barium
1.0 mg/L
1.0 mg/L
Monthly/Quarterly
Grab
Effluent
Total Iron, mg/L
Month' /Quarterly
Grab
Effluent
Total Manganese, Hg/L
Monthly/Quarterly
Grab
Effluent
Total Zinc, Ng/L
Monthly/Quarterly
Grab
Effluent
Total Arsenic
10 0 Ng/L
50.0 pg/L
Monthly/Quarterly
Grab
Effluent
Total Cadmium
2 0 Hg/L
15 0 pg/L
Month ly/Quarterly
Grab
Effluent
Total Chromium
50 0 Hg/L
1,022 0 g/L
Monthly/Quarterly
Grab
Effluent
Total Copper, g/L
Monthly/Qu rterl
Grab
Effluent
Total Lead, Hg/L
25 Opg/L
33.8 g/L
Month' /Qu arterly
Grab
Effluent
Total Nickel
25 0 Hg/L
25.0 Hg/L
Monthly/Quartert
Grab
Effluent
Total Selenium
5 0 pg/L
56.0 Hg/L
Monthly/Quarterly
Grab
Effluent
Nitrate as N
10 0 mg/L
10 0 mg/L
Monthly/Quarterly
Grab
Effluent
Sulfates
250 0 mg/L
250.0 mg/L
Monthly/Quarterly
Grab
Effluent
Chlorides
250 0 mg/L
250 0 mg/L
Month' /Quarterl
Grab
Effluent
TDS
500 0 mg/L
500.0 mg/L
Monthly/Quarterly
Grab
Effluent
Total Hardness, mg/L
100 0 mg/L
100.0 mg/L
Month' /Quarterly
Grab
Effluent
TSS, mg/L
30.0 mg/L
100.0 mg/L
Monthly/Quarterly
Grab
Effluent
Oil and Grease
15,0 mg/L
20 0 mg/L
Monthly/Quarterly
Grab
Effluent
Temperature, OC
Monthly/Quarterly
Grab
Effluent
Specific Conductance, Hmho/cm
Monthly/Quarterly
Grab
Effluent
Notes:
1 No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system. See Special
Condition A. (18.) .
2. The facility shall conduct monthly sampling from the effective date of the permit. After one year
from the effective date of the permit the monitoring will be reduced to quarterly
3 The pH shall not be less than 6.0 standard units nor greater than 9.0 standard units
4. The facility shall use EPA method 1631E.
If the facility is unable to obtain a seep sample due to the dry or low now conditions
preventing the facility from obtaining a representative sample, the "no flow" should be
reported on the DMR. This requirement is established in the Section D of the Standard
Conditions and 40 CFR 122.41 (j).
There shall be no discharge of floating solids or visible foam in other than trace
amounts.
Page 25 of 27

Permit NC0004961
A. (32.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
112) [15A NCAC 02B 0400 et seq , 02B .0500 et seq.]
During the period beginning on the effective date of this permit and lasting until expiration, the
Permittee is authorized to discharge from outfall 112 — Seep Discharge. Such discharges shall be
limited and monitored' by the Permittee as specified below:
EFFLUENT
CHARACTERISTICS
LIMITS
Monthly Daily
Average Maximum
MONITORING REQUIREMENTS
Measurement Sample Type Sample Location
Frequencyz
Flow, MGD
Monthly/Quarterly
Estimate
Effluent
H3
Monthly/Qu rterl
Grab
Effluent
Fluoride
1.8 mg/L
1.8 mg/L
Monthly/Quarterly
Grab
Effluent
Total Mercur 4, ng/L
Monthly/Quarterly
Grab
Effluent
Total Barium
1.0 mg/L
1.0 mg/L
Monthly/Quarterly
Grab
Effluent
Total Iron, mg/L
Monthly/Quarterly
Grab
Effluent
Total Manganese, Ng/L
Monthly/Quarterly
Grab
Effluent
Total Zinc, Ng/L
Monthly/Quarterly
Grab
Effluent
Total Arsenic
10 0 g/L
50.0 pg/L
Monthly/Quarterly
Grab
Effluent
Total Cadmium
2 0 /L
15.0 pg/L
Month/ /Quarterly
Grab
Effluent
Total Chromium
50.0 /L
1,022 0 pg/L
Month/ /Quarterly
Grab
Effluent
Total Copper, pg/L
Monthly/Quarterly
Grab
Effluent
Total Lead, pg/L
25 Opg/L
33 8 pg/L
Monthly/Quarterly
Grab
Effluent
Total Nickel
25 0 Hg/L
25 0 Ng/L
Monthly/Quarterly
Grab
Effluent
Total Selenium
5 0 pg/L
56 0 pg/L
Monthly/Quarterly
Grab
Effluent
Nitrate as N
10 0 mg/L
10 0 mg/L
Month/ /Quarterly
Grab
Effluent
Sulfates
250 0 mg/L
250.0 mg/L
Monthly/Quarterly
Grab
Effluent
Chlorides
250 0 mg/L
250 0 mg/L
Month ly/Quarterly
Grab
Effluent
TDS
500 0 mg/L
500.0 mg/L
Monthly/Quarterly
Grab
Effluent
Total Hardness, mg/L
100.0 mg/L
100 0 mg/L
Monthly/Quarterly
Grab
Effluent
TSS, mg/L
30,0 mg/L
100 0 mg/L
Monthly/Quarterly
Grab
Effluent
Oil and Grease
15.0 mg/L
20.0 mg/L
Monthly/Quarterly
Grab
Effluent
Temperature, OC
Monthly/Quarterly
Grab
Effluent
Specific Conductance, Hmho/cm
Month/ /Quarterly
Grab
Effluent
Notes:
1. No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system. See Special
Condition A (18.).
2. The facility shall conduct monthly sampling from the effective date of the permit After one year
from the effective date of the permit the monitoring will be reduced to quarterly
3. The pH shall not be less than 6.0 standard units nor greater than 9 0 standard units.
4. The facility shall use EPA method 1631E
If the facility is unable to obtain a seep sample due to the dry or low now conditions
preventing the facility from obtaining a representative sample, the "no flow" should be
reported on the DMR. This requirement is established in the Section D of the Standard
Conditions and 40 CFR 122.410).
There shall be no discharge of floating solids or visible foam in other than trace
amounts.
Page 26 of 27

Permit NC0004961
Appendix A
Plan for Identification of New Discharges (attached)
Page 27 of 27

k ; i,

EXHIBIT 4
South Carolina Electric & Gas Company
Integrated Resource Plan (IRP)
February 28, 2014

STATE OF SOUTH CAROLINA
South Carolina Electric & Gas Company's Integrated
Resource Plan (IRP)
(Please type or print)
Submitted by: K. Chad Burgess
Address: SCANA Corp.
220 Operation Way MC C222
Cayce, SC 29033-3701
} BEFORE THE
PUBLIC SERVICE COMMISSION
OF SOUTH CAROLINA
COVERSMEET
DOCKET
NUMBER: 2014 - - E
SC Bar Number: 69456
Telephone:
Fax:
Other:
803-217-8141
803-217-7810
Entail: chad.burgess(ascana.com
NOTE: The cover sheet and information contained herein neither replaces nor supplements the filing and service of pleadings or other papers
as required by law. This form is required for use by the Public Service Commission of South Carolina for the purpose of docketing and must
be filled out completely.
DOCKETING INFORMATION (Clteck all that apply)
❑ Emergency Relief demanded in petition ❑ Request for item to be placed on Commission's Agenda expeditiously
❑ Other:
❑ Late -Filed Exhibit 7 Report
L
INDUSTRY (Check one)
NATURE OF ACTION (Check all that apply)
Z Electric
❑ Affidavit
❑ Letter
❑ Request
❑ Electric/Gas
❑ Agreement
❑ Memorandum
❑ Request for Certificatio
❑ Electric/Telecommunications
❑ Answer
❑ Motion
❑ Request for Investigatior
❑ Electric/Water
❑ Appellate Review
❑ Objection
❑ Resale Agreement
❑ Electric/Water/Telecom.
❑ Application
❑ Petition
❑ Resale Amendment
❑ Electric/Water/Sewer
❑ Brief
❑ Petition for Reconsideration
❑ Reservation Letter
❑ Gas
❑ Certificate
❑ Petition for Rulemaking
❑ Response
❑ Railroad
❑Continents - - -- -
❑ Petition for Rule -to Show Cause --
0 Response to-Discovei y
❑ Sewei
❑ Complaint
❑ Petition to Intervene
❑ Return to Petition
❑ Telecommunications
❑ Consent Order
❑ Petition to Intervene Out of Time
❑ Stipulation
❑ Transportation
❑ Discovery
❑ Prefiled Testimony
❑ Subpoena
❑ Water
❑ Exhibit
❑ Promotion
© Otliei:
❑ Water/Sewer
❑ Expedited Consideration
❑ Proposed Order Integrated Resource Plan
❑ Administrative Matter
❑ Interconnection Agreement
❑ Protest
❑ Other:
❑ Interconnection Amendment
❑ Publisher's Affidavit
❑ Late -Filed Exhibit 7 Report
L

i o
POWER FOR �IVINC3
K. Chad Burgess
Associate General Counsel
chad.burnessPscono. corn
February 28, 2014
VIA ELECTRONIC FILING
The Honorable Jocelyn G. Boyd
Chief Clerk/Administrator
Public Service Commission of South Carolina
101 Executive Center Drive
Columbia, South Carolina 29210
RE: South Carolina Electric & Gas Company's 2014 Integrated Resource
Plan
Docket No. 2014- -E
Dear Ms. Boyd:
In accordance with S.C. Code Ann. § 58-37-40 (Supp. 2013) and Order No. 98-
502 enclosed you will find the 2014 Integrated Resource Plan of South Carolina
Electric & Gas Company ("SCE&G 2014 IRP"). This filing also serves to satisfy the
annual reporting requirements of the Utility Facility Siting and Environmental
Protection Act, S.C. Code Ann § 58-33-340.
By copy of this letter, we are also serving the South Carolina Office of
Regulatory Staff and the South Carolina Energy Office with a copy of the SCE&G
2014 IRP and attach a certificate of service to that effect.
If you have any questions or concerns, please do not hesitate to contact us.
Very truly yours,
K. Chadgess
KCB/kms
cc: John W. Flitter
Jeffery M. Nelson, Esquire
Ashhe Lancaster
(all via electronic and U.S. First Class Mail)

BEFORE
THE PUBLIC SERVICE COMNUSSION OF
SOUTH CAROLINA
DOCKET NO. 2014- -E
IN RE:
South Carolina Electric & Gas Company's )
Integrated Resource Plan ) CERTIFICATE OF
SERVICE
This is the certify that I have caused to be served this day one (1) copy of the
2014 Integrated Resource Plan of South Carolina Electric & Gas Company via
electronic mail and U.S. First Class Mail to the persons named below at the address set
forth:
Jeffrey Nelson, Esquire
Ofrice of Regulatory Staff
1401 Main Street, Suite 900
Columbia, SC 29201
[e-mail]
John Flitter
Office of Regulatory Staff
1401 Main Street, Suite 900
Columbia, SC 29201
iflitter a,regstaff.sc. og_v
Ashlie Lancaster
SC Energy Office
1200 Senate Street
- - ---- --- --V- 408 Wade Hampton Building ----- - - — --~ -
Columbia, SC 29201
alancasteraenergy.sc. gov
h'i
karen M. Scruggs
Cayce, South Carolina
This 28th day of February 2014

2014
Integrated
Resource
Plan
A SCANA COMPANY

Introduction
This document presents South Carolina Electric & Gas Company's ("SCE&G" or
"Company") Integrated Resource Plan ("IRP") for meeting the energy needs of its customers
over the next fifteen years, 2014 through 2028. This document is filed with the Public Service
Commission of South Carolina ("Commission") in accordance with S.C. Code Ann. § 58-37-40
(Supp. 2013) and Order No. 98-502 and also serves to satisfy the annual reporting requirements
of the Utility Facility Siting and Environmental Protection Act, S.C. Code Ann. § 58-33-430
(Supp. 2013). The objective of the Company's IRP is to develop a resource plan that will
provide reliable and economically priced energy to its customers while complying with all
environmental laws and regulations.
I. Demand and Energy Forecast for the Fifteen -Year Period Ending 2028
Total territorial energy sales on SCE&G's system are expected to grow at an average rate
of 1.6% per year over the next 15 years, while firm territorial summer peak demand and winter
peak demand will increase at 1.6% and 1.7% per year, respectively, over this forecast horizon.
The table below contains these projected loads. By convention winter follows summer.
Summer
Peak
(MW)
Winter i Energy
Peak Sales
I (MW) (GWH)
2014
j 4,786
4,4961
22,648
20151
4,849
_
4,5571
22,732
_
2016
4,968
4,6321
22,944
2017
2018
5,073
5,166
4,713
4,814
2� 3,423
23,765
_
20191
5,245
4,894
24,279
20201
5,319
T
4,9671
24,683
2021
5,385
25,065
2022
5,458
_5,057,
5,152;
25,533
2023
2024
5,540
5,623
5,2491
26,032
_
5,3491
26,514
2025
5,705
5,4471
27,007
2026
5,789
5,5411
27,481
2027
5,867
_
5,636
27,935
2028
5,943
5,7311
28,397

The energy sales forecast for SCE&G is made for over 30 individual categories. The categories
are subgroups of our seven classes of customers. The three primary customer classes -
residential, commercial, and industrial - comprise just over 93% of our sales. The following bar
chart shows the relative contribution to territorial sales made by each class. The "other" class in
the chart below includes street lighting, other public authorities, municipalities and electric
cooperatives.
Percent Sales By Class 2014
00% 5 0% 10 0% 15 0% 20 0% 25 0% 30.0% 35 0% 40 0%
Residential11
Commercial
Industrial
Other
SCE&G's forecasting process is divided into two parts: development of the baseline
forecast, followed by adjustments for energy efficiency impacts. A detailed description of the
short-range baseline forecasting process and statistical models is contained in Appendix A of this
report. Short-range is defined as the next two years. Appendix B contains similar information
for the long-range methodology. Long range is defined as beyond two years. Sales projections
for each group are based on statistical and econometric models derived from historical
relationships.
1. System Peak Demand: Summer vs. Winter
SCE&G usually peaks in the summer as seen in the chart below. This is reasonable for
several reasons. First, the climate in SCE&G's service area is generally hotter in the summer
than colder in the winter relative to a given base temperature. Second, the penetration of air -
conditioners among SCE&G's customers approaches 100% since there are no real substitutes for
I
SCE&G's forecasting process is divided into two parts: development of the baseline
forecast, followed by adjustments for energy efficiency impacts. A detailed description of the
short-range baseline forecasting process and statistical models is contained in Appendix A of this
report. Short-range is defined as the next two years. Appendix B contains similar information
for the long-range methodology. Long range is defined as beyond two years. Sales projections
for each group are based on statistical and econometric models derived from historical
relationships.
1. System Peak Demand: Summer vs. Winter
SCE&G usually peaks in the summer as seen in the chart below. This is reasonable for
several reasons. First, the climate in SCE&G's service area is generally hotter in the summer
than colder in the winter relative to a given base temperature. Second, the penetration of air -
conditioners among SCE&G's customers approaches 100% since there are no real substitutes for

electric air -conditioners at present. Finally, a large number of residential and gas customers heat
their homes and businesses with natural gas. Results of the peak demand forecast methodology
used herein show that the general pattern of higher summer peaks relative to winter peaks will
continue.
The following charts shows SCE&G's experience with summer versus winter peaking.
By industry convention, the winter period is assumed to follow the summer period. In 19 of the
past 24 years, SCE&G peaked in the summer. One other notable feature of the peak demand
chart is the greater variability in winter peak demand.
Comparison of SCE&G Annual Summer and Winter Peak History
1990-2013
MW
5000
4500
4000
3500
3000
2500
PLOT == ' summer winter
1 1 1 1 1 1 1 1 1 1 2 2 2 2 2 2 2 2 2 2 2 2 2 2
9 9 9 9 9 9 9 9 9 9 0 0 0 0 0 0 0 0 0 0 0 0 0 0
9 9 9 9 9 9 9 9 9 9 0 0 0 0 0 0 0 0 0 0 1 1 1 1
0 1 2 3 4 5 6 7 8 9 0 1 2 3 4 5 6 7 8 9 0 1 2 3
Year
The forecast of summer peak demand is developed by combining the load profile
characteristics of each customer class collected in the Company's Load Research Program with
forecasted energy. The winter peak demand is projected through its correlation with annual
energy sales and winter degree-day departures from normal.
2. DSM Impact on Forecast
SCE&G expects its energy efficiency ("EE") programs to reduce retail sales in 2014 by
84,627 MWH or approximately 85 GYM. Retail sales after this EE impact are expected to be
22,035 GWH. Therefore, the EE programs are expected to reduce retail sales by 0.384% from
3

what they would have been. To gauge how its EE programs compared to other companies in the
Southeast, SCE&G analyzed the EE impacts filed with the U.S. Energy Information
Administration ("EIA") in 2012, the latest year available. There were 47 companies filing from
the Southeast, in particular, from the NERC regions of SERC and FRCC. Two companies were
dropped from the analysis for bad data. The chart below shows graphically the distribution of
reported results. The median EE impact was 0.19%. Thus half the companies showed results
higher and half lower than this median value. SCE&G's expectation for 2014 is twice this
median value placing it in the top half of the distribution and almost into the top quartile.
Clearly SCE&G's EE programs compare favorably with other companies in the Southeast.
EIA 861 Reported Energy Efficiency Impacts for 2012
80
70
60
50
m
a�
40
a
30
20
0
0 075 0 225 0 375 0 525
eepct
Lognormal
Lower Quartile 003
Median 019
Upper Quartile 051
0 675 0 825
As part of the forecast development, the 0.38% EE savings was divided into a residential and
commercial component. In addition, savings due to lighting efficiencies were removed from the
class numbers and combined with lighting efficiency effects due to federally mandated measures.
This was necessary to produce a consistent forecast of lighting efficiency effects. After this
adjustment, the annual EE percentages used to produce the forecast were determined to be 0.31%
and 0.13% for the residential and commercial sectors, respectively. The table below illustrates
the calculation of the EE reductions. The far right-hand column labeled "Cumulative
N

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.
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
Baseline
Residential
(GWH)
Cumulative
Reductions
(GWH)
Derivation of Annual EE Savings
Incremental Baseline Cumulative
Reductions Commercial Reductions
(GWH) Inc. % (GWH) (GWH)
Incremental
Reductions
(GWH)
Inc. %
Cumulative
Reductions
(GWH)
2014
7,883
-
-
-
7,247
-
-
-
-
2015
7,919
-
-
-
7,257
-
-
-
-
2016
8,053
-25
-25
-031
7,437
-10
-10
-0 13
-35
2017
8,192
-50
-25
-031
7,615
-20
-10
-0 13
-70
2018
8,318
-76
-26
-031
7,777
-30
-10
-0 13
-106
2019
8,511
-103
-26
-031
8,042
-40
-10
-0 13
-143
2020
8,697
-129
-27
-031
8,300
-51
-11
-0 13
-180
2021
8,877
-157
-28
-031
8,544
-62
-11
-0 13
-219
2022
9,054
-185
-28
-031
8,783
-73
-11
-0 13
-259
2023
9,242
-214
-29
-031
9,041
-85
-12
-0 13
-299
2024
9,420
-243
-29
-031
9,288
-97
-12
-0 13
-340
2025
9,602
-273
-30
-031
9,540
-110
-12
-0 13
-382
2026
9,777
-303
-30
-031
9,782
-122
-13
-0 13
-425
2027
9,947
-334
-31
-031
10,015
-135
-13
-0 13
-469
2028
10,120
-365
-31
-031
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

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
Baseline
Sales
GWIT)
Energy
SCE&G
DSM
Programs
(GWI)
Efficiency
Total
Federal EE
Mandates Impact
(GWI) (GWH)
Territorial
Sales
(GWR)
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

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
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

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

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 cominunities, 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, therinostats 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 raze. 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.
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
SCE&G Clean Energy Plan
30,000
80%
25,00070%
60%
20,0001
50%
H
15,000
900C
40%
10,000
30%
20
5,000
10%
-
0%
—
- 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

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
leading national independent certification and verification
program for renewable energy administered by the Center
for Resource Solutions, a nonprofit company based in San
Francisco, California. The nearby table shows the MWHs
of renewable energy generated by the Kapstone generator,
formerly known as the Cogen South generator:
Year
MWh
US Clean Energy Forecast
2007
371,573
1.7%
2008
EIA AE02014
1.7%
2009
5,000
1.7%
2010
360%
1.5%
2011
336,604
1.5%
2012
414,047
1.9%
2013
385,202
35.5
4,000
=
350%
3,000
34.5%
Q
34.0%
C
2,000
33.5%
=
33.0%
32.5%
1,000
32.0%
-
31.5%
-Clean Energy ...... Net Generation to the Grid ® ® ® % Clean Energy
oioeia
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
leading national independent certification and verification
program for renewable energy administered by the Center
for Resource Solutions, a nonprofit company based in San
Francisco, California. The nearby table shows the MWHs
of renewable energy generated by the Kapstone generator,
formerly known as the Cogen South generator:
Year
MWh
% of Retail Sales
2007
371,573
1.7%
2008
369,780
1.7%
2009
351,614
1.7%
2010
346,190
1.5%
2011
336,604
1.5%
2012
414,047
1.9%
2013
385,202
1.8%
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
proj ect.
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 gro-andbreaking 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
MA

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

e. 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

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
SCE&G
Electric CO2
21
19
17
'Co
0
15
13
11
9
7
Ln l0 r\ 00 O O r-1
O O O O O H r-1
O O O O O O O
N N N N N N N
N M LnW
r-1 ri r-1 c -I r-1
O O O O O
N N N N N
t\ 00 M O ri N
H ri ri N N N
O O O O O O
N N N N N N
Actual —Projected 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

L 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 rulemakmg 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 questiomlaire 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 detenmine 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 summers 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.
a]

Existing Long Term Supply Resources
The following table shows the generating capacity that is available to SCE&G in 2014.
Neal Shoals — Carlisle, SC
In -Service
Summer
Parr Shoals — Parr, SC
Date
(MW)
Coal -Fired Steam -
1914
8
McMeekin — Near Irmo, SC
1958
250
Wateree — Eastover, SC
1970
684
*Williams — Goose Creek, SC
1973
605
Cope - Cope, SC
1996
415
Kapstone — Charleston, SC
1999
85
Total Coal -Fired Steam Capacity
2,039
Gas -Fired Steam:
Urquhart — Beech Island, SC
1953
95
Nuclear:
V. C Summer - Parr, SC
1984
647
I. C. Turbines.
Hardeeville, SC
1968
9
Urquhart — Beech Island, SC
1969
39
Coit — Columbia, SC
1969
28
Parr, SC
1970
60
Williams — Goose Creek, SC
1972
40
Hagood — Charleston, SC
1991
128
Urquhart No. 4 — Beech Island, SC
1999
48
Urquhart Combined Cycle — Beech Island, SC
2002
458
Jasper Combined Cycle — Jasper, SC
2004
852
Total I. C. Turbines Capacity
1,662
Neal Shoals — Carlisle, SC
1905
3
Parr Shoals — Parr, SC
1914
7
Stevens Creek - Near Martinez, GA
1914
8
Salida - Near Irmo, SC
1930
200
Fairfield Pumped Storage - Parr, SC
1978
576
Total Hydro Capacity
794
Other: Long -Tenn Purchases
25
SEPA
20
Wi
684
610
415
M,
6611
9
48
38
73
52
145
49
4
12
10
200
25
20
Grand Total: 5.282 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 O 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
4000
tA
3500
M
3000
no
2500
2000
1 2 3 4 5 6 7 8 9 101112131415161718192021222324
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.
e. 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
W

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%.
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 AP 1000 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
Low MWs
Low %
High MWs
High %
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 AP 1000 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
Canadysl
90
1962
Canadys2
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.
z 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

L 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 $1,02; 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

14
"santee cooper
CERTIFIED MAIL
January17, 2017
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 2015 and 2016.
Year
Month
Ash tons
Soil tons
2015
Total
284,438
0
2016
January
19,825
0
2016
February
1,757
0
2016
March
36,945
0
2016
Aril
26,918
0
2016
May
28,484
0
2016
2016
2016
2016
June
July
August
September
20,236
30,104
32,982
17,578
1,379
2,973
6,131
586
2016
October
8,864
0
2016
2016
November
December
24,397
18,650
2,746
3,241
2016
2015'& 2016
Total
Total
266,741
551,179
17,056
17,056
i apse upaatea for c►ant►cation on 1/17/17
Sincerely,
r
Susan W. Jackon, P.E.
Manager
CCP and Waste Management
SWJ:ADM.pjc
cc: Frank Holleman
PO Box 2946101 1 Moncks Corner, SC 29461-6101 1 One Riverwood Dnve I Moncks Corner, SC 29461-2901 1 [phone]

3000
2500
2000
1500
1000
500
w
$/MWh vs Capacity Factor
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
v) O vl O v1 O v) O vl O vl O v) O vl O v) O vl
A -4 N N M M I:T IzT vl vl lD lD r� � 00 00 0) 0)
Solar PV _ Off -Shore Wind
Combustion Turbine . '-Combined Cycle
$/MWh vs Capacity Factor
30% ITC for Solar and Wind
3000
2500 -
2000
1500 _.
1000
500
0
0
v1 O 6 c b o 0 0 Ln O v1 O
v1 O u'1 O v) b O v1 O v1 O v1 O v1 O
ri M M 0 0 l0 (D r� r� 00 00 0) M O
c-1
—*—Solar PV—0—Off-Shore Wind
Combustion Turbine-0—Combined Cycle
36
$/MWh vs Capacity factor
500
450
400
350 Ilk -
300
250
200
150
100 _
50._
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
vl O M O vt O M O Ln O 0 O Ln O u) O v1 O M O
rl r -I N N M M d' d' vl m t0 lD r, r, oo co 0) M O
--o—Solar PV —IF--Off-Shore Wind
Combustion Turbine ­06—Combined Cycle
500
450
400
350
300
250
200
150
100
50
0
$/MWh vs Capacity Factor
30% ITC for Solar and Wind
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Ln O v) O v1 O Ln O v) O v1 O v) O v1 O v1 O Ln O
--� rr N N M M � �T v) v1 lD lD n r, Oo 00 0) M O
—Solar PV Off -Shore Wind
Combustion Turbine —�4—Combined Cycle

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
Type
Avoided CO2
Emissions
Output
MWh
Capacity
MW
CO2 Emissions
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:Hsam.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.
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
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
06%
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 cormnits 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
j
YEAR
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
Load Forecast
--'I
I Baseline Trend
50461
5113
- 5272
5407
5525
5632
5734
58301
5921
6023
6125
6227
6332
6430
6525
2I
EE Impact
-3
-4
-37
-58
-80
-103
-129
-156
-171
-187
-203
-220
-236
-253
-270
31
Gross Territorial Peak
5043
5109
5235
53491
5445
5529
5605
5674
5750
58361
5922
6007
6096
6177
6255
4
IDemand Response
-257
-260
-267
-275
-279
-283
-286
-289
-292
-296
-299
-303
-306
-313
5
Net Territorial Peak
47861
4849
4968
5074
5166
5246
5319
53851
5458
5540
5623
5704
5790
_-310
5867
5942
_
System Capacity
s
lExisting
52821
5287
5290
5293
5293
5918
6242
6288
6288
6288
6381
6474
6567
6660
6753
Additions
7
Solar Plant (20 MWs DC)
5
3
3
81
_Peaking
Intermediate
_
93
93
_ 931
93
93
93
9
Baseload
625
669
46
10
!Retirements
-345
11
I
Total System Capacity
5287
5290
5293
5293
5918
6242
6288
6288
6288
6381
6474
6567
6660
6753
6846
121
Firm Annual Purchase
300
3001
375
500
131
ITotal Production Capability
5587
5590
5668
57931
5918
62421
6288
6288
6288
63811
6474
6567
6660
6753
6846
Reserves
14
1 Margin (1-13-1-5)
801
741
700
719
752
996
9691
9031
830
841
851
863
870
886
904
15
% Reserve Margin (L14/1-5)
16.7%
15.3%
14.1%
14.2%
14.6%
19.0%1
18.2%1
16.8%
15.2%
15.2%
15.1%
15.1%
15.0%
15.1%
15.2%
16
% NERC Res.k n L141 L5 -L4
15.9%
14.5%1
13.4%
13.4%
13.8%
18.0%1
17.3%1
15.9%
14.4%1
14.4%
14.4%
14.4%
14.3%
14.3%
14.5%
Note: L17 shows the reserve margin calculated according to NERC's new definition. See the following link for details:
http //www.nerc.coin/docs/pc/ris/RIS Report on Reserve Mares 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 bits and associated facilities operating at a voltage level of 11 5k or
above
b Loss of any line operating at a voltage level of I15kV 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 750. 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,j + 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-t
Zt is the original data or a difference of the original data
f(B) is the autoregressive operator, f(B) = 1 — fl B - ... - fl Bp
u is the constant term
q(B) is the moving average operator, q (B) = 1 - ql 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
Many computer packages perform this iterative analysis. PROC ARIMA of (SAS/ETS)'
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 tion
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 AREWA 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

U xtpuaddV

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.

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 autocorreladon 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
i�

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.
i 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 through residual 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.

• 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
FM

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 mcreases 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.
M.

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 intemiptible 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

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.
I�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,
REV

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.

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EXHIBIT 5
Santee Cooper Press Release
Santee Cooper announces plans to recycle
ash for beneficial use
11/19/2013

5/5/2015 https //www santeecooper cam/about-santee-cooper/news-releases/news-Items/santee-cooper-announces-plans-to- recycle -ash -for -beneficial -use aspx
MI Business to Business 19 Education and Safety t, Contact Us ® Careers C, Storms and Outages itzlp Blog
i
santee cooper - ---------- - -- ---
Home?RoD jt Santee_Coopar _..News Releases
Leadership
_--_-__-____ --- ----------- _-- Santee Cooper announces plans to recycle ash for
Investors
- beneficial use
Communications
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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 fobs 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 fobs, Santee
Cooper powers South Carolina To learn more, visit www santeecooper com
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@ 2013 Santee Cooper All rights reserved
Legal Notices I Espanol I Sitemap
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EXHIBIT 7
W.S. Lee Steam Station (SC)
Settlement Agreement
April 23, 2015

P
5ETTL E lV1.L+ NT AGRE, V) ENT
This Settlement Agreement ('Agl=nietll") is entered this 23 rA da'Y of
2015, between Upstate forever and Save Our Saluda (collectively, the
"Conservation Groups"), an the one hand, and Duke Energy Carolinas; LLC ("Duke Cncrgy"),
on the other, on behalf of themselves and their respective successors, predecessors; assigns,
af`liliates, parent companies, subsidiaries, shareholders, officers, directors, agents, and
employees.
Whereas the parties hereto earlier entered into an agreement dated September 23, 2014
(artached hereto), under which Duke Energy agreed to remove coal ash From the inactive Ash
Basin and Ash Bill area located at the site of the coal -Bled 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 Emtrgy'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,
I, Federal Regulation` The parties ncknowledge that the Unitcd States
Environmental Protection Agcncy promulgated the Hazardous and Solid Waste 114anagenittil
system: Disposal of Coal Combustion Residuals fi•orn Electric Utilities ("CCR rule"), which was
published on , 2015, 80 Fed Reg. , and that the CCTV rule
sets minimum controlling requirements ['or management and disposal of coal combustion
residuals and the closure of ash impo_indrnents, and that the CCR rule requites Duke Encrgy to

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
E!

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 Soii 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.
ON

(a) For purposes of this Agreement, a force majeure is defined as any event
arising from causes beyond the control of the company, or any entity controlled
by the company or its contractors, which delays or prevents performance of any
obligation under this Agreement despite best efforts to fulfill the obligation and
includes but is not limited to war, civil unrest, act of God, or act of a
governmental or regulatory body delaying performance or making it impossible,
including, without limitation, any appeal or decision remanding, overturning,
modifying, or otherwise acting (or failing to act) on a permit or similar permission
or action that prevents or delays an action needed for the performance of any of
the work contemplated under this Agreement such that it prevents or substantially
interferes with its performance within the time frames specified herein.
(b) The requirement that Duke Energy exercise "best efforts to fulfill the
obligation" includes using commercially reasonable efforts to anticipate any
potential force maj eure 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 maj eure 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 =o 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

CM
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 he 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
0

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 parry 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 !> day of A„ri i '-is by;

P (
Executed this Z� CA day of by:
UPSTA , FOREVER �J--1
By:
Its: [—:'- �,' e-ucy @
12

�.a
Executed this day of or't by:
-
SAVE OUR S.ALUD
By:
13

11 1. - ., 1,
Secondary Ash Pond
X44,
Of
rimary Ash Pond
Borrow
Area
Structural Fill
%R11
Inactive Ash Basin
Ash Fill Area

EXHIBIT 8
SC DHEC & Duke Energy Consent Agreement
W.S. Lee Steam Station (SC)
September 2014

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

Agreement by the Department or in subsequent actions ielating 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•
I , 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 Umt 3 in 1959. Two (2)
combustion turbines (CTs) were added in 2007 and generate an additional approximate 84
MWs. The CTs use diesel fliel 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 Alea.
2

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 Anal. §48-1-10 et seq. (Rev.
2008 and Stipp. 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:
i , 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 tlae
Ash Removal Plan and the time schedule for implementation thereof, the Ash Removal Plan
3

and schedule shall be incorporated herein and become an enforceable part of this Consent
Agreement.
2. Submit, along with but under separate cover from the Ash Removal Plan, a Health and
Safety Plan (HASP) consistent with Occupational Safety and Health Administration
regulations. Tile 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 tile Ash Removal
Plan.
4. Upon completion of the work approved in the Ash Removal Plan, submit an Ash Removal
Report to the Department. Tile Ash Removal Report shall sununarize 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 all 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

0.
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 frill 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. lmplementability,
g. Costs.
b, 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 icsolution 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 seasonable
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.
] 1. Notwithstanding any `othet 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
0

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, of 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 Ag►eement, 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 acid any delays encountered or anticipated that may affect the
approved schedule for implementation of the terms of this Consent Agreement, and a
description of efforts made to mitigate delays or avoid anticipated delays.
14. Prepare all Plans and perform all activities under this Consent Agreement following
appropriate DHEC and EPA guidelines. All Plans and associated reports shall be prepared
7

in accordance with industry standards and endorsed by a Professional Engineer (P.E.) and/or
Professional Geologist (P.G.) duly -licensed in South Carolina. Unless otherwise requested,
one (1) paper copy and one (1) electronic copy (.pdf format) of each document prepared
under this Consent Agreement shall be submitted to the Department's Project Manager.
Unless otherwise directed in writing. all correspondence, work plans and reports should be
submitted to the Department's Project Manager at the following address:
Tim Hornosky
South Carolina Department of Health and Environmental Control
Bureau of Land and Waste Management
2600 Bull Street
Columbia, South Carolina 29201
[e-mail]
15. Reimburse the Department on a quarterly basis, for all past, present and future costs, direct
and indirect, incurred by the Department pursuant to this Consent Agreement and as
provided by law. Oversight Costs include, but ale 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 ate 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 befotc 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
LV

ft
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 incrjeure include by
example, but are not limited to, unanticipated of increased costs of performance, changed
economic circumstances, normal precipitation events, or failure by Duke Energy to exercise
due diligence in obtaining governmental permits or perforrning 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
IE

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 deerned 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 sliall 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 dul ing that thirty (30) day period.
(Signatuke Pagel Follows)
�;

FOR THE SOUTH CAROLINA DEPARTMENT
OF HEALTH AND ENVIRONMENTAL CONTROL
Elizabeth -A-1. Dieck
Director of Environmental Affairs
41d),tv, � 4
Daphne G. 344, Chief a -
Bureau of Land and Waste Management
L //- " -. ��
Van Keisler, P.G., Director
Division of Compliance and Enforcement
Reviewed By:
&AaSe22k a0_ ZeA='-
Attorney
Office of General Counsel
WE CONSENT:
DUKE ENERGY CAROLINA, LLC
Date: 9 ),29 / l q
Date: zq / l�—,
Date: ?-fR���
Date: g '/-z !`,J y
6kzz�Al-� Date: ZS /' `f
;(signature)
John Elnitsky, Senior Vice President, Ash Basin Strategy
(Please clearly print name and title)
11

EXHIBIT 9
DENR/DWR Fact Sheet for NPDES Development
Riverbend Permit Renewal NC0004961
2015

DENR/DWR
FACT SHEEN" FOR NPDES PERMIT DE'V,ECOPMENT
PERMIT RENEWAL
NPDES No NC0004961
Facility Information
Applicant/Facility Name
Duke Energy Carolinas, LLC — Riverbend Steam Station
Applicant Address
P 0 `Bor 1006, Charlotte, North Carolina 28201
Facility Address
175 Steam Plant Road, `Mount Hotly, North Carolina 28120
Permitted Flow
No limit
Type of Waste
100% industrial
Prim SiC Code 4911, — Electric Services
Facility/Permit Status
Class i/Active, `Renewal
County
I Gaston County
Miscellaneous
Receiving Stream
Catawba River
(Mt 'island `Lake)
Regional Office
Mooresville
Stream Classification
WSAV and B -CA
State Grid / USGS Quad
,F 15Sw
303(d) Listed9
No
Permit Writer
Sergei Chernikov.,
Ph D
Subbasin
03-08-33
Date
May 21, 2014
Drainage Area (mi')
1800
•
001 �� Lat, 35'21 28'-,N Long 80° 58' 12' W
002, Lal, 35' 22' 06" N bong_ 801 57' 31" W
00213 , Lat 35 21 51"N Long 801 58" 1 1" W
011 Lat 35' 21' 38" N Long 80' 58' 38" W
Summer 7Q10 (cfs)
80
Winter 7Q10 (cfs)
30Q2 (cfs)
Average Flow (cfs)
2700
IWC %for Outfall 002
( )
0 4 — discharge
g
2 7 — dewatering
BVILVAILVARVIOM
Duke Energy's Riverbend Steam Station was a coal flied steam electric plant in Gaston County,
the electricity generation was discontinued ou 04/1!2013 The facility has 5 permitted outfalls in
the current NPDES discharge perinit The Sources of wastewater for these outfalls include non -
contact cooling water, ash basin discharge, sanitary waste, stormwater from process areas, sump
overflows, and potentially confammaied groundwater seeps The facility has no FGD scrubber.
Currently, discharge of cooling water has discontinued arid discharge from the ash pond
significantly decreased
In addition to NPDES ,Pexmit NC0004961, the facility also holds 0388R20 (air permit) and
NCD024,717423 (Hazardous wastes) The facility is subject to 40 CFR 423 — Steam Electric
Power Generation
"The following descriptions of .he wastes at each outfall are offered
001 — Once through cooling water consisting 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
Since the facility was shut down, the discharge from, this outfall is not anticipated
rfl�i �31

V
002 — Ash basin discharge consisting 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 drams
rinsate wastes, general plant/trailer sanitary wastewater, turbine and boiler rooms sumps,
vehicle rinse water, and stormwater from pond areas, upgradient watershed, and
miscellaneous stormwater flows. Most of the waste streams have discontinued, but some
will remain.
002A- Yard drain sump overflow, discharge occurs rarely.
010 — Combined flow from all seeps.
011 — Former stormwater Outfall 1. Contains stormwater and groundwater flow, also
includes wastewater from 10,000 gallon oil separator tank #3. The drainage basin
includes a 2.7 acre portion of the main switchyard and 8,700 ft2 of the plant yard between
power house and combustion turbine area. The powerhouse covers about 1.5 acres of the
drainage basin. 100% of the drainage basin is paved or roofed.
This facility discharges to the Mountain Island Lake (Catawba River) in sub -basin 03-08-33.
The receiving stream is not listed as impaired.
Duke Energy Submitted Application dated May 15, 2014. The current permit expires February
28, 2015.
Duke Energy is required by the Coal Ash Management Act to remove all ash from the site by
August 1, 2019.
The discharge pipe NPDES outfall 002 from the secondary ash basin discharge tower at
Riverbend Steam Station will be slip lined to ensure integrity. While this pipe is being slip lined,
an alternative arrangement to convey wastewater to the permitted NPDES outfall 002 will be
utilized. Temporary piping will be positioned in the secondary ash basin and the treated
wastewater will be pumped to the NPDES outfall 002 discharge flow weir, located before the
concrete flume that discharges into Mountain Island Lake. Once the slip line repairs are
completed, the system will be returned to its original configuration. NPDES monitoring
requirements will continue to be collected during the slip line project at the NPDES outfall 002
discharge flow weir.
SEEPS -OUTFALL 010
The facility identified 12 unpermitted seeps from the ash settling basin. Seeps can be classified
as either engineered seeps (toe drains) from the earthen dam or non -engineered seeps that occur
as wastewater moves from the ash settling basin into groundwater and then into surface water,
either directly or after emerging on land. Engineered seeps can be captured and routed through a
permitted outfall.
The non -engineered seeps represent a treatment system that has the potential to contaminate
groundwater and surface water. The original design and location of the impoundment are such
that wastewaster is not contained and directed to only engineered outfalls as the NPDES program
generally contemplates, but wastes are also being released to groundwater and emerging in the
form of seeps at the surface at diffuse and remote locations, with wastewater then flowing into
surface waters depending on site specific factors. Potential groundwater contamination is
regulated through North Carolina's 2L program. The CWA NPDES permitting program does not
Fact Sheet
NPDES NC0004961 Renewal
N PP. 7

d
normally envision permitting of uncontrolled releases from treatment systems, such releases are
difficult to monitor and control, and it is difficult to accurately predict their impact on water
quality. Releases of this nature would typically be addressed through an enforcement action
requiring their elimination rather than permitting.
The non -engineered seeps at this facility represent a unique circumstance, where the occurrence
of the seeps is attributable to an original pond design that will require long-term action to fully
address. Recent North Carolina legislation (Coal Ash Management Act of 2014) establishes a
framework for addressing all coal ash impoundments in the state to ensure that groundwater and
surface water are adequately protected through closure or other measures. However, action to
close or otherwise address coal ash impoundments and their threats to surface waters and
groundwater will occur over a long tern of those actions. In light of the long-term nature of
action to fully address these impoundments, the Division is proposing, as an interim measure, to
ensure that all non -engineered seeps are appropriately identified, monitored, and subject to
protective effluent limits by including the seep discharges as authorized discharges in the
facility's NPDES permit. The permit includes requirements to regularly inspect for new seeps,
monitoring requirements for all identified seeps, and applicable effluent limits which ensure that
the seeps will not result in unacceptable impacts to the receiving stream.
The facility identified 12 unpermitted seeps and conducted chemical analysis of the discharges.
The total flow from the seeps was measured at 0.14 MGD. Although, all seeps don't have a
permanent discharge and discharge from all seeps does not reach the surface water, for the
purposes of the permitting it was assumed that all seeps reach the surface water. The seeps are
not located on the walls of the dike, they appear as an emerging groundwater in a swampy area
adjacent to the lake.
The maximum allowable parameter concentration for seeps was determined by multiplying the
highest concentration for a baseline seep data by 10. These values are substantially lower than
the allowable concentration determined by the Reasonable Potential Analysis for the combined
seep flow. The maximum allowable concentrations for Pb and TDS were established at the level
of the water quality standards.
ASH POND DAMS
Seepage through earthen dams is common and is an expected consequence of impounding water
with an earthen embankment. Even the tightest, best -compacted clays cannot prevent some
water from seeping through them. Seepage is not necessarily an indication that a dam has
structural problems, but should be kept in check through various engineering controls and
regularly monitored for changes in quantity or quality which, over time, may result in dam
failure.
REASONABLE POTENTIAL ANALYSIS (RPA)
The Division conducted EPA -recommended analyses to determine the reasonable potential for
toxicants to be discharged at levels exceeding water quality standards/EPA criteria by this
facility from outfall 002 (Ash Pond). Calculations included: As, Be, Cd, Total Phenolic
Compounds, Cr, Cu, CN, Pb, Hg, Mo, Ni, Se, Ag, Zn, and Fe (please see attached). The renewal
application listed 0 19 MGD as a current flow. The analysis indicates no reasonable potential to
violate the surface water quality standards or EPA criteria. However, the monitoring will
continue per recommendation of the hearing officer during the last renewal.
The Division also considered data for other parameters of concern in the EPA Form 2C that the
facility submitted for the renewal. The majority of the parameters were not detected in the
Fact Sheet
NPDES NCOOO4961 Renewal
Page 3

discharge. The Division reviewed the following parameters that were detected in the discharge
and have applicable state standards or EPA criteria for Class C WS -IV stream: fecal coliform,
nitrate, Al, Ba, B, Co, Mn, Sb, and Tl. Most of these parameters were well below the state
standards/EPA criteria. Only 1 parameter exceeded EPA criteria: Al (162 ug/L is above 87 ug/L).
Considering the in -stream waste concentration of only 0.4%, even Al is not expected to violate
applicable water quality criterion.
The RPA was also conducted for the combined flow from all the seeps. The highest
concentration for each constituent was chosen from one of the 12 seeps and used for the RPA.
The RPA was not considered for the parameters that don't have an applicable state water quality
standard. Calculations included: As, Cd, Chlorides, Cr, Cu, F, Pb, Hg, Ni, Se, Zn, Ba, Fe, and
Mn (please see attached). The analysis indicates no reasonable potential to violate the water
quality standards or EPA criteria. The combined flow volume for all the seeps was measured at
0.14 MGD. However, the flow of 0.5 MGD was used for the RPA to incorporate a safety factor,
account for potential new seeps that might emerge in the future or increase in flow volume at the
existing seeps.
The RPA was also conducted for the Outfall 011. Calculations included: As, Cd, Chlorides, Cr,
Cu, F, Pb, Hg, Ni, Se, Zn, Ba, Fe, and Mn (please see attached). The analysis indicates no
reasonable potential to violate the water quality standards or EPA criteria. The flow volume for
the Outfall 011 was measured at 0.00036 MGD. However, the flow of 0.001 MGD was used for
the RPA to incorporate a safety factor and potential increase in flow.
The RPA analysis indicates that existing discharges from the facility outfalls will not cause
contravention of the state water quality standards/ EPA criteria.
DEWATERING — OUTFALL 002
To meet the requirements of the Coal Ash Management Act of 2014, the facility needs to
dewater two ash ponds and excavate the ash to deposit it in the landfills. The facility highest
discharge rate from the dewatering process will be 1.45 MGD. The facility submitted data for the
surface water in the ash ponds, interstitial water in the ash, and interstitial ash water that was
treated by 20 µm filter and 0.45 µm filter. To evaluate the impact of the dewatering on the
receiving stream the RPA was conducted for the wastewater that will be generated by the
dewatering process. To introduce the margin of safety, the highest measured concentration for a
particular parameter was used. The RPA was conducted for As, Cd, Chlorides, Cr, Cu, F, Pb,
Mo, Hg, Ni, Se, Zn, Ba, Fe, and Mn, SO4, Al, B, Sb, and Tl (please see attached).
Based on the results of the RPA, the limit for Total Aluminum will be added to the dewatering
effluent page.
TECHNOLOGY BASED EFFLUENT LIMITS OUTFALL002 AND OUTFALL 010
The existing federal regulations require development of Technology Based Effluent Limits
(TBELs) for the parameters of concern. Since the EPA has not promulgated any new Effluent
Guidelines for Power Plants since 1982, the Division has reviewed the performance of the
existing coal-fired power plants to establish TBELs: Marshall Steam Station, Belews Steam
Station, and Allen Steam Station. Two of these facilities (Belews and Allen) were used by EPA
to establish the proposed Effluent Guidelines for Power Plants. The Division focused on the
following parameters: Total Arsenic, Total Mercury, Total Selenium, and Nitrate/nitrite as N.
These parameters are consistent with the parameters selected by EPA in the proposed Effluent
Guidelines. The Division agrees with the EPA statement from the proposed Effluent Guidelines
Fact Sheet
NPDES NC0004961 Renewal
Page 4

that justifies TBEL limitations for only four pollutants of concern: "Effluent limits and
monitoring for all pollutants of concern is not necessary to ensure that the pollutants are
adequately controlled because many of the pollutants originate from similar sources, have similar
treatabilities, and are removed by similar mechanisms Because of this, it may be sufficient to
establish effluent limits for one pollutant as a surrogate or indicator pollutant that ensures the
removal of other pollutants of concern."
Based on the review of the effluent data for the past 5 years the Division established the
following TBELs for the coal-fired power plants in North Carolina. The monthly average limits
for Total Arsenic and Total Selenium are based on 95th percentile of the effluent data, which is
consistent with the EPA methodology, and daily maximum limits for these constituents are based
on the 99.91h percentile of the effluent data. The Total Mercury limit is based on the Statewide
Mercury TMDL implementation strategy and was established by the Division previously.
Total Arsenic —10.5 µg/L (Monthly Average); 14.5 µg/L (Daily Maximum)
Total Selenium — 13.6 µg/L (Monthly Average); 25.5 µg/L (Daily Maximum)
Total Mercury — 47.0 ng/L (Monthly Average); 47.0 ng/L (Daily Maximum)
The Division does not have any long-term data for Nitrate/nitrate as N. Therefore, the limits for
this parameter are based on the proposed EPA Effluent Guidelines.
Nitrate/nitrite as N — 0.13 mg/L (Monthly Average); 0.17 mg/L (Daily Maximum)
Facility is allowed 4.5 years from the effective date of the permit to comply with the TBELs
(Outfall 002 only—Ash Pond Discharge). This time period is provided in order for the facility to
budget, design, and construct the treatment system. The compliance schedule is consistent with
the proposed EPA Effluent Guidelines that require compliance with the TBELs "as soon as
possible within the next permit cycle beginning July 1, 2012". Since the permit cycle is 5 years,
the Effluent Guidelines will allow the facility to comply with the TBELs by June 30, 2022. This
permit has a more stringent requirements, the facility shall comply with the TBELs by the end of
2019.
In the interim, the facility shall comply with the BPJ temporary limits that are derived by
multiplying the proposed TBELs by 5, please see below:
Total Arsenic — 52.5 µg/L (Monthly Average); 72.5 µg/L (Daily Maximum)
Total Selenium — 68.0 µg/L (Monthly Average); 127 5 µg/L (Daily Maximum)
Nitrate/nitrite as N — 0.65 mg/L (Monthly Average); 0.85 mg/L (Daily Maximum)
Although these interim limits higher than the proposed TBELs, they are significantly lower than
the allowable concentrations determined by the Reasonable Potential Analysis (RPA) and
should be protective of the water quality in the receiving stream. The RPA allowable
concentrations are listed below:
Total Arsenic —13,632.3 µg/L (Monthly Average); 91,690.8 µg/L (Daily Maximum)
Total Selenium —1,363.2 µg/L (Monthly Average); 12,492.0 µg/L (Daily Maximum)
TEMPERATURE VARIANCE REMOVAL -OUTFALL 001
The facility historically had a temperature variance in accordance with CWA Section 316(a). In
order to maintain the variance the facility had to conduct annual biological and chemical
monitoring of the receiving stream to demonstrate that it has a balanced and indigenous
Fact Sheet
NPDES NC0004961 Renewal
Page 5

macroinvertebrate and fish community The latest BIP (balanced and indigenous population)
report was submitted to DWQ in August of 2009. The ESS has reviewed the report and
concluded that the Mountain Island Lake near Riverbend Station has a balanced and indigenous
macroinvertebrate and fish community.
Since the facility discontinued electricity generation in 2013, it does not wish to request
continuation of the temperature variance Therefore, Effluent Sheet A. (1.) was modified to
reflect temperature requirements without a variance.
CWA SECTION 316(B)
Since the facility discontinued electricity generation in 2013 and does not use cooling water, it
will not be the subject to the Section 316(b) of Clean Water Act.
1NSTREAM MONITORING -OUTFALL 002
The facility historically had 7 monitoring station, 2 located upstream and 5 located downstream.
It is recommended that the monitoring will continue.
The permit also required semi-annual upstream and downstream monitoring of the ash pond
discharge. Upstream site (Station B) is approximately 2 miles upstream of the discharge and
downstream location (Station C) is approximately 0.5 miles downstream of the discharge. These
monitoring stations have been established through the BIP monitoring program, which was
required to maintain 316(a) temperature variance. The monitored parameters are: As, Cd, Cr, Cu,
Hg, Pb, Se, Zn, and Total Dissolved Solids (TDS). The majority of the results are below
detection level, the rest of the results are below water quality standards. These results are
consistent with the previous monitoring results.
It is required that the monitoring at the stations B and C will continue until discharges from the
station are ceased. It is also required that the facility uses low level method 1631E for all Hg
analysis.
FISH TISSUE MONITORING -OUTFALL 002
The permit required fish tissue monitoring for As, Se, and Hg near the ash pond discharge once
every 5 years. This frequency is consistent with EPA guidance. Sunfish and bass tissues were
analyzed for these trace elements. The results were below action levels for Se and Hg (10.0 µg/g
— Se, 0.40 µg/g — Hg, NC) and screening value for As (1.20 — µg/g, EPA). These results are
consistent with the previous monitoring results.
TOXICITY TESTING- Outfall 002•
Current Requirement: 24hr Chronic P/F @ 10%
Recommended Requirement: 24hr Chronic P/F @ 2.7% (flow during dewatering)
Monitoring Schedule: January, April, July, October
This facility has passed all chronic toxicity tests during the previous permit cycle, please see
attached. The change is the instream waste concentration was made based on the significant
decrease in the discharge volume.
COMPLIANCE SUMMARY
Notwithstanding the civil lawsuit filed for unauthorized discharges and groundwater
exceedances/violations, based on the monitoring required under the current version of the permit
there were no violations of effluent standards contained in the permit.
Fact Sheet
NPDES NC0004961 Renewal
Pane 6

PERMIT LIMITS DEVELOPMENT
• The pH limits (Outfalls 002, 002A, and 010) in the permit are based on the North
Carolina water quality standards (15A NCAC 2B .0200).
• The limits for Oil and Grease and Total Suspended Solids (Outfall 002 and Outfall 002A)
are based on the Best Professional Judgment and are lower than prescribed in the 40 CFR
423.
• The limits for Total Copper and Total Iron (Outfall 002 and Outfall 002A) were
established in accordance with the 40 CFR 423.
• The temperature limits (Outfall 001) are based on the North Carolina water quality
standards (15A NCAC 2B .0200).
• The turbidity limit in the permit (Outfall 002) is based on the North Carolina water
quality standards (15A NCAC 2B .0200).
• The Technology Based Effluent Limits (Outfall 002 and Outfall 010) for Total Arsenic,
Total Mercury, Total Selenium, and Nitrate/nitrate as N are based on the requirements of
40 CFR 125.3(a) , 40 CFR 122.44(a)(1); 125.3(c) and (d).
• The Interim Technology Based Effluent Limits (Outfall 002) for Total Arsenic, Total
Selenium, and Nitrate/nitrate as N are based on the requirements of 40 CFR 125.3(a) , 40
CFR 122.44(a)(1); 125.3(c) and (d).
• The Whole Effluent Toxicity limit (Outfall 002) is based on the requirements of 15A
NCAC 213.0500.
• The Total Aluminum limits (Outfall 002 dewatering) in the permit are based on the
results of the statistical analysis of the interstitial water data.
REQUESTED MODIFICATIONS
With the permit application for renewal, Duke Energy Carolinas, LLC has requested the
following modifications:
Monitoring Frequencies (Outfall 002)
Parameter
Present
Proposed
Flow
Weekly
Monthly
Total Nitrogen
2/year
1/year
Total Phosphorus
2/year
1/year
Total Copper
Quarterly
none
Total Iron
Quarterly
none
These requests could not be granted because the Division needs these data to assure compliance
with the water quality standards and criteria during the upcoming ash pond decanting/dewatering
process.
PROPOSED CHANGES:
• Monitoring requirements for Outfall 001 were adjusted due to the discontinuation of
once -through cooling water discharges.
• The Ash Pond Closure Special Condition was updated (Please see A. (15.)).
• The Seep Outfall 010 (Please see A. (5.)) and Seep Pollutant Analysis Special Condition
(Please see A. (17.)) were added to the permit.
• The Appendix A and Appendix B were added to the permit.
• A separate effluent page for the dewatering of the ash ponds (Outfall 002) was added to
the permit (Please see Special Condition A. (3)).
• The Boiler Cleaning Waste Special Condition was eliminated due to the discontinuation
of the power generation.
Fact Sheet
NPDES NC0004961 Renewal
Page 7

• The Section 316(a) of CWA Thermal Variance Special Condition was eliminated due to
the discontinuation of the power generation.
• The Section 316(b) of CWA Special Condition was eliminated due to the discontinuation
of the power generation.
• The turbidity limit was added to the permit to meet the state turbidity standard per 15A
NCAC 2B .0211(3) (k) (Outfall 002).
• The Technology Based Effluent Limits for Total Arsenic, Total Mercury, Total Selenium,
and Nitrate/nitrite as N were added to the permit and are based on the requirements of 40
CFR 125.3(a) , 40 CFR 122.44(a)(1); 40 CFR 125.3(c) and (d) (Outfall 002 and Outfall
010).
• The Interim Technology Based Effluent Limits (Outfall 002) for Total Arsenic, Total
Selenium, and Nitrate/nitrate as N were added to the permit and are based on the
requirements of 40 CFR 125.3(a) , 40 CFR 122.44(a)(1); 125.3(c) and (d).
• Proposed federal regulations require electronic submittal of all discharge monitoring
reports (DMRs) and specify that, if a state does not establish a system to receive such
submittals, then permittees must submit DMRs electronically to the Environmental
Protection Agency (EPA). The Division anticipates that these regulations will be adopted
and is beginning implementation.
The requirement to begin reporting discharge monitoring data electronically using the NC
DWR's Electronic Discharge Monitoring Report (eDMR) internet application has been
added to the permit. (Please see Special Condition A. (18.)).
The Applicable State Law Special Condition was added to the permit to meet the
requirements of Senate Bill 729 (Coal Ash Management Act, Please see Special
Condition A. (19.)).
The Outfall 011 (former Stormwater Outfall 1) was added to the permit (Please see A.
(20.)).
PROPOSED SCHEDULE:
Draft Permit to Public Notice: March 6 , 2015 (est.)
Permit Scheduled to Issue: July 27, 2015 (est.)
STATE CONTACT:
If you have any questions on any of the above information or on the attached permit, please
contact Sergei Chernikov at [phone] or [e-mail]
Fact Sheet
NPDFS NC0004961 Renewal
Page 8

EXHIBIT 10
Riverbend Draft NPDES Permit NC0004961

Permit NC0004961
STATE OF NORTH CAROLINA
DEPARTMENT OF ENVIRONMENT AND NATURAL RESOURCES
DIVISION OF WATER RESOURCES
Draft PERMIT
TO DISCHARGE WASTEWATER UNDER THE
NATIONAL POLLUTANT DISCHARGE ELIMINATION SYSTEM
In compliance with the provision of North Carolina General Statute 143-215.1, other lawful
standards and regulations promulgated and adopted by the North Carolina Environmental
Management Commission, and the Federal Water Pollution Control Act, as amended,
Duke Energy Carolinas, LLC
is hereby authorized to discharge wastewater from a facility located at the
Riverbend Steam Station
Mount Holly
Gaston County
to receiving waters designated as the Catawba River in the Catawba River Basin
in accordance with effluent limitations, monitoring requirements, and other
applicable conditions set forth in Parts I, II, III and IV hereof.
This permit shall become effective
This permit and authorization to discharge shall expire at midnight on February 28, 2020.
Signed this day
DRAFT
S. Jay Zimmerman, Director
Division of Water Resources
By Authority of the Environmental Management Commission
Page 1 of 15
I01

Permit NC0004961
SUPPLEMENT TO PERMIT COVER SHEET
All previous NPDES Permits issued to this facility, whether for operation or discharge are hereby
revoked As of this permit issuance, any previously issued permit bearing this number is no longer
effective Therefore, the exclusive authority to operate and discharge from this facility arises under
the permit conditions, requirements, terms, and provisions included herein.
Duke Energy Carolinas, LLC is hereby authorized to:
1. Continue to discharge:
• Once through cooling water (outfall 00 1) consisting 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
• Ash basin discharge (outfall 002) consisting 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,
general plant/ trailer sanitary wastewater, turbine and boiler rooms sumps,
vehicle rinse water, and stormwater from pond areas, upgradient
watershed, and miscellaneous stormwater flows.
• Yard sump overflow (outfall 002A) .
12 potentially contaminated groundwater seeps (outfall 0 10) .
• Wastewater, stormwater and groundwater (outfall 011).
From a facility located at Riverbend Steam Station, Mount Holly in Gaston
County, and
2. Discharge wastewater from said treatment works at the location specified on
the attached map into the Catawba River, which is classified WS -IV and B -CA
waters in the Catawba River Basin.
Page 2 of 15

Permit NC0004961
Part I
A. (1.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
00 1) [15A NCAC 02B .0400 et seq , 023 0500 et seq ]
During the period beginning on the effective date of this permit and lasting until expiration, the
Permittee is authorized to discharge once -through cooling water and intake screen backwash from
outfall 001. Such discharges shall be limited and monitored3 by the Permittee as specified below:
EFFLUENT
CHARACTERISTICS
LIMITS
MONITORING REQUIREMENTS
Monthly
Average
Daily
I Maximum
Measurement
Frequency
Sample Type
Sample
Location'
Flow
Monthly
Pump Logs
Influent or
Effluent
Temperature OF
Monthly
Grab
Effluent
Temperature(OF)2
89 6 (32oC)
Monthly
Grab
Downstream
Notes -
1 Downstream sampling point: downstream at Mountain Island Lake If samples are collected
below the water surface, the Permittee will record the sample depth on the DMR form.
2 The ambient temperature shall not exceed 89.60F (32 OOC) and is defined as the daily average
downstream water temperature When the Riverbend Station effluent temperature is recorded
below 89 60F (32 OOC), as a daily average, then monitoring and reporting of the downstream water
temperature is not required In cases where the Permittee experiences equipment problems and
is unable to obtain daily temperatures from the existing temperature monitoring system, the
temperature monitoring must be reestablished within five working days.
3. No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system See Special
Condition A. (18.).
Chlorination of the once through condenser cooling water, discharged through outfall 001, is
not allowed under this permit. Should Duke Energy wish to chlorinate its condenser cooling
water, a permit modification must be requested and received prior to commencing
chlorination.
There shall be no discharge of floating solids or visible foam in other than trace amounts.
Page 3 of 15

Permit NC0004961
A. (2.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
002) [15A NCAC 02B.0400 et seq , 02B 0500 et seq ]
During the period beginning on the effective date of this permit and lasting until expiratson, the
Permittee is authorized to discharge from outfall 002 — Ash Pond Discharge. Such discharges shall be
limited and monitored7 by the Permittee as specified below
EFFLUENT
CHARACTERISTICS
LIMITS
MONITORING REQUIREMENTS
Monthly Daily Measurement Sample Type Sample Location
Average Maximum Frequency
Flow
Weekly
Pump logs or
estimate
Influent or Effluent
Total Suspended Solids'
23 0 mg/L
75 0 mg/L
Monthly
Grab
Effluent
Oil and Grease
110 mg/L
15 0 mg/L
Annually
Grab
Effluent
Total Copper2
10 mg/L
10 mg/L
Quarterly
Grab
Effluent
Total Iron2
10 m /L
10 m /L
Quarterly
Grab
Effluent
Total Arsenic
52 5 Ng/L
72 5 Ng/L
Quarterly
Grab
Effluent
Total Selenium
68 0 /L
127 5 N /L
Quarterly
Grab
Effluent
Nitrate/nitrite as N
0 65 m /L
0 85 m /L
Quarterly
Grab
Effluent
Total Arsenic
10 5 p /L8
14 5 /L8
Quarterly
Grab
Effluent
Total Selenium
13 6 /L8
25 5 /L8
Quarterly
Grab
Effluent
Total Mercury
47 0 ng/L6
47 0 ng/L6
Quarterly
Grab
Effluent
Nitrate/nitrite as N
013 mg/L8
017 mg/L8
Quarterly
Grab
Effluent
Total Phosphorus
Semi-annually
Grab
Effluent
Total Nitrogen NO2 + NO3 + TKN
Semi-annually
Grab
Effluent
pH3
Monthly
Grab
Effluent
Chronic Toxiaty4
Quarterly
Grab
Effluent
Turbidity5
Monthly
Grab
Effluent
Notes
1 Monthly average of 43 mg/L is permitted provided that the Permittee can satisfactorily
demonstrate that the difference between 23 mg/L and 43 mg/L is a result of the concentration of
total suspended solids in the intake water
2. The limits for total copper and total iron only apply during a chemical metals cleaning
3. The pH shall not be less than 6 0 standard units nor greater than 9 0 standard units.
4 Whole Effluent Toxicity shall be monitored by chronic toxicity (Cenodaphnia) P/F at 10% Tests
shall be conducted in January, April, July and October (see Part A (6 ) for details)
5. The discharge from this facility shall not cause turbidity in the receiving stream to exceed 50
NTU If the instream turbidity exceeds 50 NTU due to natural background conditions, the
discharge cannot cause turbidity to increase in the receiving stream
NTU - Nephelometric Turbidity Unit
6 The facility shall use EPA method 1631E
7. No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system. See Special
Condition A (18.)
8 Facility is allowed 4 5 years from the effective date of the permit to comply with the TBELs
This time period is provided in order for the facility to budget, design, and construct the
treatment system Permit might be re -opened to implement the final EPA Effluent
Guidelines and more stringent limits might be added
The metal cleaning waste, coal pile runoff, ash transport water, domestic wastewater,
and low volume waste shall be discharged into the ash settling pond.
No chemicals, cleaners, or other additives may be present in the vehicle wash water
to be discharged from this outfall.
There shall be no discharge of floating solids or visible foam in other than trace
amounts.
Page 4 of 15

Permit NC0004961
A. (3.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
002) [15A NCAC 02B .0400 et seq., 02B .0500 et seq.]
During the period beginning on the effective date of this permit and lasting until expiration, the
Permittee is authorized to discharge from outfall 002 — Ash Pond Discharge (Dewatering). Such
discharges shall be limited and momtored7 by the Permittee as specified below:
EFFLUENT
CHARACTERISTICS
LIMITS
MONITORING REQUIREMENTS
Monthly Daily Measurement Sample Type Sample Location
Average Maximum Frequency
Flow
Weekly
Pump logs or
estimate
Influent or Effluent
Total Suspended Solids'
23 0 m /L
75 0 m /L
Monthly
Grab
Effluent
Oil and Grease
110 m /L
15 0 m /L
Annually
Grab
Effluent
Total Copper2
10 mg/L
10 mg/L
Quarterly
Grab
Effluent
Total Iron2
10 mg/L
10 mg/L
Quarterly
Grab
Effluent
Total Arsenic
10 5 Ng/L
14 5 pg/L
Quarterly
Grab
Effluent
Total Selenium
13 6 Ng/L
25 5 Ng/L
Quarterly
Grab
Effluent
Total Aluminum
318 mg/L
318 mg/L
Quarterly
Grab
Effluent
Total Mercury
47 0 n /L6
47 0 n /L6
Quarterly
Grab
Effluent
Nitrate/nitrate as N
013 m /L
017 m /L
Quarterly
Grab
Effluent
Total Phosphorus
Semi-annually
Grab
Effluent
Total Nitrogen NO2 + NO3 + TKN
Semi-annual[
Grab
Effluent
pH3
Monthly
Grab
Effluent
Chronic Toxicity4
Quarterly
Grab
Effluent
Turbidity5
Monthly
Grab
Effluent
Notes:
1 Monthly average of 43 mg/L is permitted provided that the Permittee can satisfactorily
demonstrate that the difference between 23 mg/L and 43 mg/L is a result of the
concentration of total suspended solids in the intake water
2. The limits for total copper and total iron only apply during a chemical metals cleaning.
3. The pH shall not be less than 6.0 standard units nor greater than 9.0 standard units.
4. Whole Effluent Toxicity shall be monitored by chronic toxicity (Cenodaphnia) P/F at 10%
Tests shall be conducted in January, April, July and October (see Part A (6.) for details).
5. The discharge from this facility shall not cause turbidity in the receiving stream to exceed 50
NTU. If the instream turbidity exceeds 50 NTU due to natural background conditions, the
discharge cannot cause turbidity to increase in the receiving stream.
NTU - Nephelometric Turbidity Unit.
6 The facility shall use EPA method 1631E
7 No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system See
Special Condition A (18.).
The metal cleaning waste, coal pile runoff, ash transport water, domestic wastewater,
and low volume waste shall be discharged into the ash settling pond.
No chemicals, cleaners, or other additives may be present in the vehicle wash water
to be discharged from this outfall.
There shall be no discharge of floating solids or visible foam in other than trace
amounts.
Page 5of15

Permit NC0004961
A. (4.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
002A) [ 15A NCAC 02B 0400 et seq , 02B 0500 et seq ]
During the period beginning on the effective date of this permit and lasting until expiration, the
Permittee is authorized to discharge from outfall 002A — Yard Sump Overflows Such discharges
shall be limited and monitored4 by the Permittee as specified below
EFFLUENT
CHARACTERISTICS
LIMITS
MONITORING REQUIREMENTS
Monthly Daily
Average Maximum
Measurement
Frequency
Sample Type Sample Location'
Flow
Episodic
Estimate
Effluent
Total Suspended Solids2
23 0 m /L
75 0 m /L
Eisodic
Grab
Effluent
Oil and Grease2
110 m /L
15 0 m /L
Episodic
Grab
Effluent
Fecal Coliform
Episodic
Grab
Effluent
Total Copper3
10 mg/L
10 mg/L
Episodic
Grab
Effluent
Total Iron3
10 mg/L
10 mg/L
Episodic
Grab
Effluent
pH5
Episodic
Grab
Effluent
Notes -
1 Effluent sampling shall be conducted at a point upstream of discharge to the receiving
stream.
2 The monthly average limits for total suspended solids and oil and grease are applicable only if
the overflow occurs for more than 24 hours
3 The limits for total copper and total iron only apply during a chemical metals cleaning
4 No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system See Special
Condition A (18 )
5 The pH shall not be less than 6 0 standard units nor greater than 9 0 standard units
THERE SHALL BE NO DISCHARGE OF FLOATING SOLIDS OR VISIBLE FOAM IN OTHER THAN
TRACE AMOUNTS
ALL FLOWS SHALL BE REPORTED ON MONTHLY DMRS. SHOULD NO FLOW OCCUR DURING A
GIVEN MONTH, THE WORDS "NO FLOW" SHOULD BE CLEARLY WRITEN ON THE FRONT OF
THE DMR. EPISODIC SAMPLING IS REQUIRED PER OCCURRANCE WHEN SUMP OVERFLOWS
OCCUR FOR LONGER THAN ONE HOUR. ALL SAMPLES SHALL BE OF A REPRESENTATIVE
DISCHARGE.
Page 6 of 15

Permit NC0004961
A. (5.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
010) [15A NCAC O2B 0400 et seq., 02B 0500 et seq ]
During the period beginning on the effective date of this permit and lasting until expiration, the
Permittee is authorized to discharge from Outfall 010 (combined seep outfall). Such discharges
shall be limited and monitored' by the Permittee as specified below
EFFLUENT CHARACTERISTICS
DISCHARGE LIMITATIONS
MONITORING REQUIREMENTS
Monthly
Average
Weekly
Average
Daily
Maximum
Measurement
Frequency2
Sample
Type
Sample Location
Total Suspended Solids
30 0 mg/L
100 0 mg/L
Monthly
Grab
Effluent
Total Arsenic
10 5 pg/L4
14 5 pg/L4
Monthly
Grab
Effluent
Total Mercury3
47 0 ng/L4
47 0 ng/L4
Monthly
Grab
Effluent
Total Selenium
13 6 pg/L4
25.5 pg/L4
Monthly
Grab
Effluent
Nitrate/nitrite as N
013 mg/L4
017 mg/L4
Monthly
Grab
Effluent
Flow
Monitor & Report
Monthly
Grab
Effluent
TDS
Monitor & Report
Monthly
Grab
Effluent
Chlorides
Monitor & Report
Monthly
Grab
Effluent
Fluoride
Monitor & Report
Monthly
Grab
Effluent
Total Barium
Monitor & Report
Monthly
Grab
Effluent
Total Iron
Monitor & Report
Monthly
Grab
Effluent
Total Manganese
Monitor & Report
Monthly
Grab
Effluent
Total Zinc
Monitor & Report
Monthly
Grab
Effluent
Total Cadmium
Monitor & Report
Monthly
Grab
Effluent
Total Chromium
Monitor & Report
Monthly
Grab
Effluent
Total Copper
Monitor & Report
Monthly
Grab
Effluent
Total Lead
Monitor & Report
Monthly
Grab
Effluent
Total Nickel
Monitor & Report
Monthly
Grab
Effluent
Temperature
Monitor & Report
Monthly
Grab
Effluent
Specific Conductance
Monitor & Report
Monthly
Grab
Effluent
pH
Between 6 0 and 9 0 standard units
Monthly
Grab
Effluent
NoTEs•
1. No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system See Special
Condition A. (18 )
2. After the first year, the monitoring frequency will be reduced to a semi-annual basis
3 The facility shall use EPA method 1631E
4 The limits can be met by installation of the treatment system, re-routing the discharge to the
existing treatment system, or disconLmumg the discharge.
There shall be no discharge of floating solids or visible foam in other than trace amounts.
Page 7 of 15

Permit NC0004961
A. (6.) CHRONIC TOXICITY PASS/FAIL PERMIT LIMIT (QUARTERLY) (Outfall
002) [ 15A NCAC 02B .0200 et seq.]
The effluent discharge shall at no time exhibit observable inhibition of reproduction or significant
mortality to Ceriodaphnia dubia at an effluent concentration of 2.7%.
The permit holder shall perform at a minimum,quarte rlU monitoring using test procedures outlined
in the "North Carolina Cenodaphnia Chronic Effluent Bioassay Procedure," Revised December 2010,
or subsequent versions or "North Carolina Phase II Chronic Whole Effluent Toxicity Test Procedure"
(Revised- December 20 10) or subsequent versions. The tests will be performed during the months of
January, April, July, and October. These months signify the first month of each three-month
toxicity testing quarter assigned to the facility. Effluent sampling for this testing must be obtained
during representative effluent discharge and shall be performed at the NPDES permitted final
effluent discharge below all treatment processes
If the test procedure performed as the first test of any single quarter results in a failure or
ChV below the permit limit, then multiple -concentration testing shall be performed at a
minimum, in each of the two following months as described in "North Carolina Phase II
Chronic Whole Effluent Toxicity Test Procedure" (Revised -December 2010) or subsequent
versions.
All toxicity testing results required as part of this permit condition will be entered on the Effluent
Discharge Monitoring Form (MR -1) for the months in which tests were performed, using the
parameter code TGP3B for the pass/fail results and THP3B for the Chronic Value. Additionally,
DWR Form AT -3 (original) is to be sent to the following address:
Attention: North Carolina Division of Water Resources
Water Sciences Section/Aquatic Toxicology Branch
1621 Mail Service Center
Raleigh, North Carolina 27699-1621
Completed Aquatic Toxicity Test Forms shall be filed with the Water Sciences Section no later than
30 days after the end of the reporting period for which the report is made.
Test data shall be complete, accurate, include all supporting chemical/ physical measurements and
all concentration/ response data, and be certified by laboratory supervisor and ORC or approved
designate signature. Total residual chlorine of the effluent toxicity sample must be measured and
reported if chlorine is employed for disinfection of the waste stream.
Should there be no discharge of flow from the facility during a month in which toxicity monitoring is
required, the permittee will complete the information located at the top of the aquatic toxicity (AT)
test form indicating the facility name, permit number, pipe number, county, and the month/year of
the report with the notation of "No Flow" in the comment area of the form The report shall be
submitted to the Water Sciences Section at the address cited above.
Should the permittee fail to monitor during a month in which toxicity monitoring is required,
monitoring will be required during the following month. Assessment of toxicity compliance is based
on the toxicity testing quarter, which is the three month time interval that begins on the first day of
the month in which toxicity testing is required by this permit and continues until the final day of the
third month
Should any test data from this monitoring requirement or tests performed by the North Carolina
Division of Water Resources indicate potential impacts to the receiving stream, this permit may be
re -opened and modified to include alternate monitoring requirements or limits
NOTE. Failure to achieve test conditions as specified in the cited document, such as minimum
control organism survival, minimum control organism reproduction, and appropriate environmental
Page 8 of 15

Permit NC0004961
controls, shall constitute an invalid test and will require immediate follow-up testing to be
completed no later than the last day of the month following the month of the initial monitoring
A. (7.) BIOCIDE CONDITION
The permittee shall not use any biocides except those approved in conjunction with the permit
application The permittee shall notify the Director in writing not later than nmety (90) days prior to
instituting use of any additional biocide used in cooling systems which may be toxic to aquatic life
other than those previously reported to the Division of Water Resources Such notification shall
include completion of Biocide Worksheet From 101 and a map locating the discharge point and
receiving stream. Completion of a Biocide Worksheet 101 is not necessary for the introduction of a
new biocide into an outfall currently being tested for toxicity
A. (8.) SPECIAL CONDITIONS
The following special conditions are applicable to all outfalls regulated by NC0004961:
• There shall be no discharge of polychlormated biphenyl compounds.
• The Permittee shall check the diked areas for leaks by a visual inspection and shall report any
leakage detected
• Nothing contained in this permit shall be construed as a waiver by the Permittee or any right to a
hearing it may have pursuant to State or Federal laws or regulations
• Discharge of any product registered under the Federal Insecticide, Fungicide, and Rodenticide Act
to any waste stream which may ultimately be released to lakes, rivers, streams or other waters of
the United States is prohibited unless specifically authorized elsewhere in this permit. Discharge
of chlorine from the use of chlorine gas, sodium hypochlorite, or other similar chlorination
compounds for disinfection in the plant potable and service water systems and in sewage
treatment is authorized. Use of rest-ricted use pesticides for lake management purposes by
applicators licensed by the N.C. Pestcide Board is allowed
• The Permittee shall report all visible discharges of floating materials, such as an oil sheen, to the
Director when submitting DMRs
A. (9.) PERMIT TERMS
The following are applicable to all outfal_s regulated by NC0004961
The term "low volume waste sources" means, taken collectively as if from one source, wastewater
from all sources except those for which specific limitations are otherwise established in this part.
Low volume wastewater sources include, but are not limited to: wastewater from wet scrubber
air pollution control systems, ion exchange water treatment system, water treatment evaporator
blowdown, laboratory and sampling streams, boiler blowdown, floor drains, cooling tower basin
cleaning wastes, and recirculating service water systems. Sanitary and air conditioning wastes
are not included.
The term "metal cleaning waste" means any wastewater resulting from cleaning (with or without
chemical cleaning compounds) any metal process equipment including, but not limited to, boiler
tube cleaning, boiler fireside cleaning, and air preheater cleaning. Chemical metal cleaning will
be conducted according to Duke Energy approved equivalency demonstration.
It has been determined from information submitted that the plans and procedures in place at
Riverbend Steam Station are equivalent to that of a BMP.
A. (10.) ASH SETTLING BASIN
Beginning on the effective date of this permit and lasting until expiration, there shall be no discharge
of plant wastewater to the ash pond unless the Permittee provides and maintains at all times a
minimum free water volume (between the top of the sediment level and the minimum discharge
elevation) equivalent to the sum of the maximum 24-hour plant discharges plus all direct rainfall and
all runoff flows to the pond resulting from a 10 -year, 24-hour rainfall event, when using a runoff
coefficient of 1.0. During the term of the permit, the Permittee shall remove settled material from the
ponds or otherwise enlarge the available storage capacities in order to maintain the required
Page 9 of 15

Permit NC0004961
minimum volumes at all times. The Permittee shall determine and report to the permit issuing
authority the following on an annual basis:
1) the actual free water volume of the ash pond,
2) physical measurements of the dimensions of the free water volume in sufficient detail to allow
validation of the calculated volume, and
3) a certification that the required volume is available with adequate safety factor to include all
solids expected to be deposited in the pond for the following year
Present information indicates a needed volume of 86.2 acre-feet in addition to solids that will be
deposited to the ash pond; any change to plant operations affecting such certification shall be
reported to the Director within five days
NOTE- In the event that adequate volume has been certified to exist for the term of the permit,
periodic certification is not needed.
A. (11.) GROUNDWATER MONITORING WELL CONSTRUCTION AND SAMPLING
The permittee shall conduct groundwater monitoring to determine the compliance of this NPDES
permitted facility with the current groundwater Standards found under 15A NCAC 2L .0200. The
monitoring shall be conducted in accordance with the Sampling Plan approved by the Division.
A.(12.) STRUCTURAL INTEGRITY INSPECTIONS OF ASH POND DAM
The facility shall meet the dam design and dam safety requirements per 15A NCAC 2K.
A.(13.) FISH TISSUE MONITORING NEAR ASH POND DISCHARGE
The facility shall conduct fish tissue monitoring once during the permit term and submit the results
with the NPDES permit renewal application. The objective of the monitoring is to evaluate potential
uptake of pollutants by fish tissue near the Ash Pond discharge. The parameters analyzed in fish
tissue shall be arsenic, selenium, and mercury. The monitoring shall be conducted in accordance
with the Sampling Plan approved by the Division.
A.(14.) INSTREAM MONITORING
The facility shall conduct semiannual in stream monitoring (one upstream and one downstream of
the ash pond discharge) for arsenic, selenium, mercury (method 1631E), chromium, lead, cadmium,
copper, zinc, and total dissolved solids (TDS). Instream monitoring should be conducted at the
stations that have already been established through the BIP monitoring program B (upstream of the
Outfall 002) and C (downstream of the Outfall 002). The monitoring results shall be submitted with
the NPDES permit renewal application.
A.(15.) ASH POND CLOSURE
The facility shall prepare an Ash Pond Closure Plan in anticipation of the facility closure. This Plan
shall be submitted to the Division one month prior to the decommissioning of the pond.
A.(16.) PRIORITY POLLUTANT ANALYSIS
The Permittee shall conduct a priority pollutant analysis (in accordance with 40 CFR Part 136) once
per permit cycle at outfall 002 and submit the results with the application for permit renewal.
A.(17.) SEEP POLLUTANT ANALYSIS
Seeps with locations identified in Appendix A are classified collectively as Outfall 010. The facility
shall continue to implement the Plan for Identification of New Discharges (see Appendix B) to
determine if new seeps have emerged.
Seeps are ephemeral in nature and enter the river at various changing locations. Seeps entering the
ever from the upstream edge of permittee's property to the downstream property boundary shall be
calculated as if entering at one location.
Page 10 of 15

Permit NC0004961
Permittee shall conduct seep identification survey semi-annually to determine if new seeps have
started or that previously identified seeps have significantly changed in size or flow. New seeps
identified through the seep survey or otherwise discovered or reported to the permittee shall have
their flow calculated, be sampled for parameters indicated with results and location(s) reported to
Division of Water Resources within 5 days of detection (location only, sampling results shall be
submitted within 30 days of sampling) for administrative inclusion in Appendix A.
Newly identified seeps or seeps whose flow increases will not be considered as new outfalls or
wastestream requiring modification of the permit as long as total flow of all seeps does not exceed 0.5
million gallons per day (MGD) and pollutant characterization is similar to previously identified seeps
identified in Table 1 and formation of seep(s) or increase in flow was not caused by change in
operations by permittee. If the pollutant sampling concentration of a new seep exceeds the
concentrations in Table 1 the Division will calculate reasonable potential and determine if either
administrative inclusion of the seep or formal modification of the permit is necessary Permittee will
be notified by the Division within 30 days of receiving the sampling results if permit modification is
necessary.
The maximum allowable parameter concentration in Table 1 is determined by multiplying the highest
baseline seep concentration levels by 10.
Table 1. Seep Monitoring Parameters and Screening Values
Parameter
Maximum allowable
parameter
concentration
Maximum allowable
total flow for all
existing and future
seeps
Chlorides
73 0 m /L
0 5 MGD
Fluoride
10 0 m /L
0 5 MGD
Total Mercury (Method
1631E) 1
47.0 ng/L
0 5 MGD
Total Barium
1.0 m L
0 5 MGD
Total Iron
65 1 m L
0.5 MGD
Total Manganese
12 3 m L
0.5 MGD
Total Zinc
190 0 pg/L
0 5 MGD
Arsenic'
14 5 µ L
0 5 MGD
Total Cadmium
10 0 µ L
0 5 MGD
Total Chromium
10 0 µ L
0 5 MGD
Total Copper
15 8 µ L
0 5 MGD
Total Lead
25 0 µ L
0 5 MGD
Total Nickel
87 7 µ L
0.5 MGD
Selenium'
25.5 µ L
0 5 MGD
Nitrate Nitnte as N1
0 17 m L
0.5 MGD
H
60-90
05MGD
TDS
500 0 m L
0 5 MGD
TSS
75.0 m L
0 5 MGD
Temperature
monitor
0 5 MGD
Specific Conductance
monitor
0 5 MGD
Notes:
1. Technology Based Effluent Limits The limits can be met by installation of the treatment
system, re-routing the discharge to the existing treatment system, or discontinuing the
discharge
A. (18.) ELECTRONIC REPORTING OF DISCHARGE MONITORING REPORTS
(State Enforceable Only) [G.S. 143-215.1(b)]
Proposed federal regulations require electronic submittal of all discharge monitoring reports (DMRs)
and specify that, if a state does not establish a system to receive such submittals, then permittees
must submit DMRs electronically to the Environmental Protection Agency (EPA). The Division
anticipates that these regulations will be adopted and is beginning implementation in late 2013.
Page 11 of 15

EXHIBIT I I
Notice of Inspection - Dam Safety Law
Mayo Lake Dam
June 10, 2010

AROMA
TM-
NCDENR
North Carolina Department of Environment and Natural Resources
Division of Land Resources
James D. Simons, PG, PE Land Quality Section Beverly Eaves Perdue, Governor
Director and State Geologist Dee Freeman, Secretary
June 10, 2010
NOTICE OF INSPECTION
DAM SAFETY LAW
Mr. Fred Holt
Progress Energy Carolinas, Inc.
Environmental, Health and Safety Services Section
PO Box 1551 PEB 4
Raleigh, NC 27602
RE: Mayo Lake Dam
State ID: PERSO-034
Person County
Watershed: Roanoke
Dear Mr. Holt:
Pursuant to the North Carolina Dam Safety Law of 1967, on March 1, 2010, personnel of the Land Quality Section performed a
periodic inspection of the subject high hazard potential dam, which is located on Mayo Creek in Person County. The Dam
Safety Law of 1967 provides for the certification and inspection of dams in the interest of public health, safety, and welfare.
Our goal is to reduce the risk of failure of such dams, to prevent injuries to persons, damage to property, and to ensure the
maintenance of stream flows.
According to the above mentioned visual inspection, the dam appears to be in a stable condition at this time. However, we
recommend the following items pertinent to maintenance and operation of the dam:
(1) Continue to remove all trees and thick undergrowth from the embankment. This will serve to (a) prevent the formation of a
root system which might significantly increase seepage through the dam which could ultimately result in failure of the structure,
(b) reduce the possibility of damage to the dam due to the uprooting of trees by wind or other natural causes, and (c) facilitate
inspection and increase the likelihood of early detection of more serious problems connected with the dam. This is particularly
important along the abutment contacts where seepage has been evident.
(2) Monitor and control varmint activity on the embankment by backfilling obvious penetrations with crushed stone and/or
implementation of other suitable controls.
Raleigh Regional Office
1628 Mail Service Center, Raleigh, North Carolina 27699-1628 - Phone: [phone] / FAX: [phone]
3800 Barrett Drive, Raleigh, North Carolina, 27699

Permit NC0004961
Appendix A
The permittee has identified 12 potentially contaminated seeps in the areas adjacent to the Mountain
Island Lake The locations of the seeps are identified on the map attached to the permit. Existing and
newly identified seeps shall be sampled on a monthly basis for the first 12 months. After the first
year the monitoring frequency will be reduced to a semi-annual basis
Seep Coordinates and Assigned Outfall Numbers
Seep ID
Latitude
Longitude
Outfall number
S-1
35 365
-80.967
101
S-2
35 365
-80.966
102
S-3
36.369
-80965
103
S-4
35 371
-80963
104
S-5
35 370
-80.963
105
S-6
35.367
-80.958
106
S-7
35 367
-80957
107
S-8
35 365
-80.956
108
S-9
35 371
-80.963
109
5-10
35 369
-80960
110
5-11
35.369
-80960
111
5-12
35 368
-80959
112
Plan for Identification of New Discharges
Appendix B
Page 15 of 15

Permit NC0004961
A. (20.) EFFLUENT LIMITATIONS AND MONITORING REQUIREMENTS (Outfall
011) [ 15A NCAC 02B 0400 et seq , 023 0500 et seq ]
During the period beginning on the effective date of this permit and lasting until expiration, the
Permittee is authorized to discharge from outfall 011 — Former Stormwater Outfall 1. Such
discharges shall be limited and monrtored5 by the Permittee as specified below -
EFFLUENT
CHARACTERISTICS
LIMITS
MONITORING REQUIREMENTS
Monthly Daily Measurement Sample Type Sample Location
Average Maximum Frequency
Flow
Monthly
Pump logs or
estimate
Influent or Effluent
Total Suspended Solids'
23 0 mg/L
75 0 mg/L
Monthly
Grab
Effluent
Oil and Grease
110 mg/L
15 0 mg/L
Annually
Grab
Effluent
Total Arsenic
Quarterly
Grab
Effluent
Total Selenium
Quarterly
Grab
Effluent
Total Mercury6
Quarterly
Grab
Effluent
Nitrate/nitrate as N
Quarterly
Grab
Effluent
Total Phosphorus
Semi-annually
Grab
Effluent
Total Nitrogen NO2 + NO3 + TKN)
Semi-annually
Grab
Effluent
pH3
Monthly
Grab
Effluent
Turbidity4
Monthly
Grab
Effluent
Notes:
1. Monthly average of 43 mg/L is permitted provided that the Permittee can satisfactorily
demonstrate that the difference between 23 mg/L and 43 mg/L is a result of the
concentration of total suspended solids in the intake water.
2. The limits for total copper and total iron only apply during a chemical metals cleaning
3 The pH shall not be less than 6 0 standard units nor greater than 9.0 standard units
4 The discharge from this facility shall not cause turbidity in the receiving stream to exceed 50
NTU. If the instream turbidity exceeds 50 NTU due to natural background conditions, the
discharge cannot cause turbidity to increase in the receiving stream.
NTU - Nephelometnc Turbidity Unit.
5. No later than 270 days from the effective date of this permit, begin submitting discharge
monitoring reports electronically using NC DWR's eDMR application system. See
Special Condition A. (1S.).
6 The facility shall use EPA method 1631E.
There shall be no discharge of floating solids or visible foam in other than trace
amounts.
Page 14 of 15

Permit NC0004961
2. Signatory Requirements [Supplements Section B. (11.) (b) and supersedes Section B. (11.)
tdfl
All eDMRs submitted to the permit issuing authority shall be signed by a person described in
Part II, Section B (11 )(a) or by a duly authorized representative of that person as described in
Part II, Section B (11.)(b). A person, and not a position, must be delegated signatory authority
for eDMR reporting purposes
For eDMR submissions, the person signing and submitting the DMR must obtain an eDMR user
account and login credentials to access the eDMR system For more information on North
Carolina's eDMR system, registering for eDMR and obtaining an eDMR user account, please visit
the following web page
http //portal.ncdenr org/web/wq/admin/bog/ipu/edmr
Certification. Any person submitting an electronic DMR using the state's eDMR system shall
make the following certification [40 CFR 122 22] NO OTHER STATEMENTS OF CERTIFICATION
WILL BE ACCEPTED
U certify, under penalty of law, that this document and all attachments were prepared under my
direction or supervision in accordance with a system designed to assure that qualified personnel
properly gather and evaluate the information submitted. Based on my inquiry of the person or
persons who manage the system, or those persons directly responsible for gathering the
information, the information submitted is, to the best of my knowledge and belief, true, accurate,
and complete I am aware that there are significant penalties for submitting false information,
including the possibility of fines and imprisonment for knowing violations. "
3. Records Retention [Supplements Section D. (6.)]
The permittee shall retain records of all Discharge Monitoring Reports, including eDMR
submissions These records or copies shall be maintained for a period of at least 3 years from
the date of the report. This period may be extended by request of the Director at any time [40
CFR 122.41]
A. (19.) APPLICABLE STATE LAW (State Enforceable Only)
This facility shall meet the requirements of Senate Bill 729 (Coal Ash Management Act) This permit
may be reopened to include new requirements imposed by Senate Bill 729
Page 13 of 15

Permit NC0004961
NOTE: This special condition supplements or supersedes the following sections within Part II of this
permit (Standard Conditions for NPDES Permits):
• Section B. (11 ) Signatory Requirements
• Section D. (2 )
• Section D (6.)
• Section E (5 )
Reporting
Records Retention
Monitoring Reports
1. Reporting [Supersedes Section D. (2.) and Section E. (5.) (a)1
Beginning no later than 270 days from the effective date of this permit, the permittee shall begin
reporting discharge monitoring data electronically using the NC DWR's Electronic Discharge
Monitoring Report (eDMR) internet application
Monitoring results obtained during the previous month(s) shall be summarized for each month
and submitted electronically using eDMR The eDMR system allows permitted facilities to enter
monitoring data and submit DMRs electronically using the internet Until such time that the
state's eDMR application is compliant with EPA's Cross -Media Electronic Reporting Regulation
(CROMERR), permittees will be required to submit all discharge monitoring data to the state
electronically using eDMR and will be required to complete the eDMR submission by printing,
signmg, and submitting one signed original and a copy of the computer printed eDMR to the
following address -
NC DENR / DWR / Information Processing Unit
ATTENTION• Central Files / eDMR
1617 Mail Service Center
Raleigh, North Carolina 27699-1617
If a permittee is unable to use the eDMR system due to a demonstrated hardship or due to the
facility being physically located in an area where less than 10 percent of the households have
broadband access, then a temporary waiver from the NPDES electronic reporting requirements
may be granted and discharge monitoring data may be submitted on paper DMR forms (MR 1,
1 1, 2, 3) or alternative forms approved by the Director. Duplicate signed copies shall be
submitted to the mailing address above
Requests for temporary waivers from the NPDES electronic reporting requirements must be
submitted in writing to the Division for written approval at least sixty (60) days prior to the date
the facility would be required under this permit to begin using eDMR Temporary waivers shall
be valid for twelve (12) months and shall thereupon expire. At such time, DMRs shall be
submitted electronically to the Division unless the permittee re -applies for and is granted a new
temporary waiver by the Division.
Information on eDMR and application for a temporary waiver from the NPDES electronic
reporting requirements is found on the following web page•
http• / /-Portal.ncdenr.org/web /wq / admin /bog/ 1-pu / edmr
Regardless of the submission method, the first DMR is due on the last day of the month following
the issuance of the permit or in the case of a new facility, on the last day of the month following
the commencement of discharge.
Page 12 of 15

Notice of Inspection
PERSO-034
June 10, 2010
Page 2 of 3
(3)Maintain a ground cover sufficient to restrain accelerated erosion on all earthen portions of the structure. This will enhance
the stability of the structure should these portions become exposed to overflow or other forms of concentrated flow. As
discussed with Progress Energy personnel during our visit, it is recommended that you work to achieve a predominantly turf
grass cover. Weeping lovegrass and serecia lespedeza should be taken out of the seed mixes used; appropriate clover and
Korean or Kobe lespedeza should be added if a legume is desired. The recently proposed S1opeMaster specifications for use at
the Cape Fear Plant are considered an acceptable alternative.
(4) Periodically monitor the dam and appurtenant works with respect to elements affecting their safety. This is in light of the
legal duties, obligations, and liabilities arising from the ownership and/or operation of a dam. This particularly applies to the
evidence of seepage observed at the abutment contacts and along the downstream toe of the embankment as well as the minor
erosion observed on the downstream slope of the dam. Monitor the seepage conditions for any evidence of change, and provide
suitable backfill and ground cover if erosion begins to threaten a more serious slope failure. Further, the condition of the
concrete spillway joints should continue to be monitored and addressed in a timely manner. Your current inspection program,
including periodic reviews by your independent consultant, is an appropriate way to address this recommendation.
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 the embankment stability can produce a slide failure of the downstream slope. Please monitor the dam for any
changes of this nature.
As a dam owner, you may incur liability should your dam have a problem or fail, if such an event results in loss of life,
property damage, or environmental damage downstream. It is therefore requested that you prepare an Emergency Action
Plan (EAP) for this dam. The EAP establishes procedures to be followed in events that could adversely impact the dam
such as extreme precipitation, seismic activity, excessive seepage, slides, sinkholes, and other natural hazards, and for
warning the public downstream in the event of an emergency at the dam. Guidance for preparing an EAP can be found on
the Internet at hiip://www.dir.enr.state.ne.us/paizes/damsafeiyprogram.litmi or by calling Dam Safety Program staff at (919)
733-4574. Two copies of an EAP for this dam should be submitted to the following address:
NC Division of Land Resources
Land Quality Section
Attn: Mr. Steven M. McEvoy, PE
1612 Mail Service Center
Raleigh, NC 27699-1612
Although the inspections by our staff are relatively infrequent and offer no safety guarantees, we hope that you will use the
information provided in this letter as you fulfill your obligation to safely maintain and operate your dam. In order to help us
keep our records up-to-date and therefore serve you better, please notify us concerning any changes in address or ownership.
Your cooperation in this effort is greatly appreciated.

Notice of Inspection
PERSO-034
June 10, 2010
Page 3 of 3
If there are any questions or if we can be of any assistance, please do not hesitate to contact me at [phone].
Sincerely,
JoF(n`,,. Holley, Jr., PE, I
Regiohal Engineer
Land uality Section
eigh Regional Office
cc: State Dam Safety Engineer
File

A
EXHIBIT 12
EPA Amicus Brief - Hawaii Wildlife Fund
US Court of Appeals for the Ninth Circuit
No. 15-17447, May 31, 2016

.ch m •r.. ��
No. 15-17447
IN THE UNITED STATES COURT OF APPEALS
FOR THE NINTH CIRCUIT
HAWAII WILDLIFE FUND; SIERRA CLUB -MAUI GROUP;
SURFRIDER FOUNDATION; WEST MAUI
PRESERVATION ASSOCIATION,
Plaintiffs -Appellees,
V.
COUNTY OF MAUI,
Defendant -Appellant.
On Appeal from the U.S. District Court, Dist. of Hawaii
No. 12-cv-198, Hon. Susan Oki Mollway, District Judge
BRIEF FOR THE UNITED STATES AS AMICUS CURIAE
IN SUPPORT OF PLAINTIFFS APPELLEES
OF COUNSEL:
KARYN WENDELOWSKI
U.S. Environmental
Protection Agency
Office of General Counsel
Washington, D.C.
JOHN C. CRUDEN
Assistant Attorney General
AARON P. AVILA
R. JUSTIN SMITH
FREDERICK H. TURNER
Attorneys, U.S. Dep't of Justice
Env't & Natural Resources Div.
P.O. Box 7415
Washington, DC 20044
[phone]
[e-mail]

11:j:1:1 J �� � ��< 1 "�1C1 ,i 1 1f%i :'� • �. i«ih �1) � ��'w F i� �n : f'��. G :� i ��� =' . � • � . • •
TABLE OF CONTENTS
TABLE OF AUTHORITIES.................................................................... iii
INTEREST OF THE UNITED STATES..................................................1
ISSUESPRESENTED.............................................................................. 2
STATEMENT OF THE CASE.................................................................. 3
I. STATUTORY BACKGROUND................................................................ 3
II. FACTUAL BACKGROUND................................................................... 6
III. PROCEDURAL BACKGROUND............................................................. 7
SUMMARY OF ARGUMENT.................................................................10
ARGUMENT...........................................................................................13
I. THE DISTRICT COURT'S DECISIONS ARE CONSISTENT WITH
THE LANGUAGE AND PURPOSE OF THE CWA...................................13
A. Discharges of Pollutants to Jurisdictional Surface
Waters Through Groundwater with a Direct Hydrological
Connection Properly Require CWA Permits ...........................14
B. The District Court's Decisions Give Full Effect to
Congress's Intent to Restore and Maintain the
Nation's Waters.......................................................................20
C. The District Court's Finding of Liability is Consistent
with EPA's Longstanding Position..........................................22
II. THE COUNTY IS LIABLE FOR UNPERMITTED DISCHARGES
DUE TO THE "DIRECT HYDROLOGICAL CONNECTION" BETWEEN
THE GROUNDWATER AND THE OCEAN ............................................. 26
III. THE DISTRICT COURT CORRECTLY HELD THAT THE COUNTY
HAD FAIR NOTICE FOR PURPOSES OF CIVIL PENALTIES .................. 32
CONCLUSION.......................................................................................36
i

i:i■ I 7af it�ii
CERTIFICATE OF COMPLIANCE........................................................37
CERTIFICATE OF SERVICE.................................................................38
ii

Ilaia:� J ' �� � � " 1 "UCi .i 11 'ii fo :'; • � i.i9 n) '� �'w II a. ��iD 1�". i .� � �!� =' : � - � •
TABLE OF AUTHORITIES
Cases
Bath Petrol. Storage, Inc. v. Sovas,
309 F. Supp. 2d 357 (N.D.N.Y. 2004) ............................................... 22
Chevron, U. S.A., Inc. v. NRDC, Inc.,
467 U.S. 837 (1984).................................................................... 12,24
Friends of Sakonnet v. Dutra,
738 F. Supp. 623 (D.R.I. 1990)......................................................... 15
Greater Yellowstone Coal. v. Larson,
641 F. Supp. 2d 1120 (D. Idaho 2009) ........................................ 31,32
Haw. Wildlife Fund v. Cty. of Maui,
No. 12-198, 2015 WL 328227 (D. Haw. Jan. 23, 2015) .... 6, 7, 8, 9, 28
Haw. Wildlife Fund v. Cty. of Maui,
No. 12-198, 2015 WL 3903918 (D. Haw. June 25, 2015) .........:......... 9
Hawaii Wildlife Fund v. County of Maui,
24 F. Supp. 3d 980 (D. Haw. 2014) .......................................... passim
Headwaters, Inc. v. Talent Irrigation Dist.,
243 F.3d 526 (9th Cir. 2001).............................................................. 5
Hernandez v. Esso Std. Oil Co.,
599 F. Supp. 2d 175 (D.P.R. 2009) ................................................... 19
Hudson R. Fishermen's Ass'n v. City of New York,
751 F. Supp. 1088 (S.D.N.Y. 1990) .................................................. 22
Idaho Rural Council v. Bosma,
143 F. Supp. 2d 1169 (D. Idaho 2001) ............................ 11, 18, 19, 21
Inland Steel v. EPA,
901 F.2d 1419 (7th Cir. 1990)
.......................................................... 22
iii

Oti
5• iRi1 �) �iA II r, �° f�.`: i QI • ala • •
In re EPA & Dept of Def. Final Rule,
803 F.3d 804 (6th Cir. 2015)............................................................. 24
McClellan Ecological Seepage Situation v. Cheney,
No. 86-475, 20 Envtl. L. Rep. 20,877 (E.D. Cal. Apr. 30, 1990) ....... 31
McClellan Ecological Seepage Situation v. Cheney,
763 F. Supp. 431 (E.D. Cal. 1989) .................................................... 31
McClellan Ecological Seepage Situation v. Weinberger,
707 F. Supp. 1182 (E.D. Cal. 1988) .................................................. 30
N. Cal. River Watch v. City of Healdsburg,
496 F.3d 993 (9th Cir. 2007).............................................................. 8
N. Cal. River Watch v. Mercer Fraser Co.,
No. 04-4620, 2005 WL 2122052 (N.D. Cal. Sept. 1, 2005) ... 16, 17, 19
Nw. Envtl. Def. Ctr. v. Grabhorn,
No. 08-548, 2009 WL 3672895 (D. Or. Oct. 30, 2009) ...................... 19
O'Leary v. Moyer's Landfill, Inc.,
523 F. Supp. 642 (E.D. Pa. 1981) ..................................................... 15
Rapanos v. United States,
547 U.S. 715 (2006) ...................................................... 2, 8, 10, 15, 16
Rice v. Harken Expl. Co.,
250 F.3d 264 (5th Cir. 2001) ...................................................... 19,20
S.F. Herring Ass'n v. Pac. Gas & Elec. Co.,
81 F. Supp. 3d 847 (N.D. Cal. 2015) ................................................ 18
Sierra Club v. Abston Constr. Co.,
620 F.2d 41 (5th Cir. 1980) .................................................. 10, 14, 15
Sierra Club v. El Paso Gold Mines, Inc.,
421 F.3d 1133 (10th Cir. 2005) ........................................................ 16
1V

S31d:1 J ' +� � +'� 1 'liCc� ,iii � i �� : ; • o a• , �� : r.:; r! e:. ��� m , � - � . •
Sierra Club v. Va. Elec. & Power Co.,
No. 15-112, 2015 WL 6830301 (E.D. Va. Nov. 6, 2015) ................... 18
United States v. Approximately 64,695 Pounds of Shark Fins,
520 F.3d 976 (9th Cir. 2008)............................................................ 33
United States v. Riverside Bayview Homes, Inc.,
474 U.S. 121 (1985).......................................................................... 20
United States v. Velsicol Chem. Corp.,
438 F. Supp. 945 (W.D. Tenn. 1976) ................................................ 16
Vill. of Oconomowoc Lake v. Dayton Hudson Corp.,
24 F.3d 962 (7th Cir. 1994).............................................................. 19
Wash. Wilderness Coal. v. Hecla Mining Co.,
870 F. Supp. 983 (E.D. Wash. 1994) ................................................ 21
Yadkin Riverkeeper v. Duke Energy Carolinas, LLC,
No. 14-753, 2015 WL 6157706 (M.D.N.C. Oct. 20, 2015) ................ 18
Statutes
33 U.S.C. § 1251(a).................................................................................. 3
33 U.S.C. § 1311............................................................................. 3, 4, 14
33 U.S.C. § 1318(a)(A)........................................................................... 34
33 U.S.C. § 1319....................................................................................... 4
33 U.S.C. § 1319(d)............................................................................ 5, 35
33 U.S.C. § 1341(a)............................................................ ................ 35
33 U.S.C. § 1341(a)(1)............................................................................ 31
33 U.S.C. § 1342.............................................................................. 1, 3, 4
33 U.S.C. § 1342(a)................................................................................... 4
v

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33 U.S.C. § 1342(b).................................................................................. 4
33 U.S.C. § 1342(d).................................................................................. 4
33 U.S.C. § 1344.................................................................................. 35 4
33 U.S.C. § 1362...................................................................................... 3
33 U.S.C. § 1362(6).................................................................................. 3
33 U.S.C. § 1362(7).............................................................................. 2,4
33 U.S.C. § 1362(8).................................................................................. 2
33 U.S.C. § 1362(12)(A)..................................................................... 3,14
33 U.S.C. § 1362(14)................................................................................ 4
33 U.S.C. § 1365...................................................................................... 4
Federal Register
39 Fed. Reg. 43,759 (Dec. 18, 1974) ........................................................ 4
55 Fed. Reg. 47,990 (Dec. 2, 1990) ........................................................ 23
56 Fed. Reg. 64,876 (Dec. 12, 1991) .................................................. 5,23
66 Fed. Reg. 2960 (Jan. 12, 2001) ....................................... 12, 23, 24, 26
80 Fed. Reg. 37,054 (June 29, 2015) ............................................... 17,25
vi

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The United States respectfully submits this brief as amicus curiae
pursuant to Federal Rule of Appellate Procedure 29(a).
INTEREST OF THE UNITED STATES
The United States Environmental Protection Agency (EPA)
implements the Clean Water Act (CWA), 33 U.S.C. §§ 1251-1387,
together with the states. That includes promulgating regulations
regarding the CWA's National Pollutant Discharge Elimination System
(NPDES). Id. § 1342. The United States participates as amicus curiae
because it has an interest in the proper interpretation of the NPDES-
permit provisions and the framework for analyzing whether discharges
of pollutants to jurisdictional surface waters through groundwater are
subject to those provisions.' The United States also has an interest
because it enforces the CWA and because it is a potential defendant in
actions alleging the discharge of pollutants from federal facilities
through groundwater.
The United States agrees with the result the district court reached
in this case and urges affirmance. In the United States' view, a NPDES
' We use the term "jurisdictional surface waters" throughout this brief
to mean "waters of the United States."
1

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permit is required here because the discharges from the Defendant -
Appellant County of Maui's wastewater treatment facility are from a
point source (i.e., the injection wells) to waters of the United States (i.e.,
the Pacific Ocean2). To be clear, the United States does not contend that
groundwater is a point source, nor does the United States contend that
groundwater is a water of the United States regulated by the Clean
Water Act. Moreover, the United States does not agree with the district
court's application of the "significant nexus" standard from Rapanos v.
United States, 547 U.S. 715 (2006).
ISSUES PRESENTED
This amicus brief addresses the following issues:
1. Whether a discharge of pollutants from a point source to
jurisdictional surface waters through groundwater with a direct
hydrological connection to jurisdictional surface waters is regulated
under the CWA.
2. Whether the site-specific facts here give rise to a "discharge of a
pollutant" under the CWA.
2 More specifically, into the Pacific Ocean that is part of the United
States' territorial seas under the CWA. 33 U.S.C. § 1362(7), (8).
2

Case 2,15-cv@ J A9,G44.7K03 DWQLt� IM2999-nK 0WQWfr9: 40�fffigd! 6040 R5LgeID# 9137
3. Whether the County had fair notice that it was subject to civil
penalties for its discharges to jurisdictional surface waters without a
NPDES permit.
STATEMENT OF THE CASE
I. STATUTORY BACKGROUND
Congress enacted the Clean Water Act to "restore and maintain
the chemical, physical, and biological integrity of the Nation's waters."
33 U.S.C. § 1251(a). Congress therefore prohibited any non -excepted
"discharge of any pollutant" to "navigable waters" unless it is
authorized by a permit. Id. §§ 1311, 1342, 1344, 1362. The CWA defines
"discharge of a pollutant" as "any addition of any pollutant to navigable
waters from any point source." Id. § 1362(12)(A) (emphasis added).
Pollutant means "dredged spoil, solid waste, incinerator, sewage,
garbage, sewage sludge, munitions, chemical wastes, biological
materials, radioactive materials, heat, wrecked or discarded equipment,
rock, sand, cellar dirt and industrial, municipal, and agricultural waste
discharged into water." Id. § 1362(6). The CWA defines "navigable
waters" as "the waters of the United States, including the territorial
seas"; and a point source is "any discernible, confined and discrete
3

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conveyance, including but not limited to any pipe, ditch, channel,
tunnel, conduit, well, discrete fissure, container, rolling stock,
concentrated animal feeding operation, or vessel or other floating craft,
from which pollutants are or may be discharged." Id. § 1362(7), (14).
The CWA authorizes EPA to issue NPDES permits under Section
402(a), but EPA may authorize a state to administer its own NPDES
program if EPA determines that it meets the statutory criteria. Id.
§ 1342(a), (b). When a state receives such authorization, EPA retains
oversight and enforcement authorities. Id. §§ 1319, 1342(d). Hawaii
obtained such permitting authority in 1974. See 39 Fed. Reg. 43,759
(Dec. 18, 1974).
The CWA is a strict -liability regime that prohibits non -excepted
discharges unless they are authorized by a CWA permit. Id. §§ 1311,
13425 1344. An unpermitted discharge constitutes a violation of the
CWA regardless of fault and is subject to enforcement by the state or
federal government or a private citizen. Id. §§ 1319, 1365. To establish
liability for a violation of the permit requirement, a plaintiff must show
there was (1) a discharge (2) of a pollutant (3) to navigable waters (4)
V!

Case 2:15-cvMQAt2>:9AG447K0MJtJ LUK- nM QWMIV: 4'fffi@B 6240 RBLgelD# 9139
from a point source. Headwaters, Inc. v. Talent Irrigation Dist., 243
F.3d 526, 532 (9th Cir. 2001).
The CWA includes a civil -penalty provision for those who violate
the Act. 33 U.S.C. § 1319(d). When determining a civil -penalty amount,
courts must consider "the seriousness of the violation'or violations, the
economic benefit (if any) resulting from the violation, any history of
such violations, any good -faith efforts to comply with the applicable
requirements, the economic impact of the penalty on the violator, and
such other matters as justice may require." Id.
EPA's longstanding position is that a discharge from a point
source to jurisdictional surface waters that moves through groundwater
with a direct hydrological connection comes under the purview of the
CWA's permitting requirements. E.g., Amendments to the Water
Quality Standards Regulations that Pertain to Standards on Indian
Reservations, 56 Fed. Reg. 64,876, 64,982 (Dec. 12, 1991) ("[T]he
affected ground waters are not considered `waters of the United States'
but discharges to them are regulated because such discharges are
effectively discharges to the directly connected surface waters.").
5

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II. FACTUAL BACKGROUND
The County operates the Lahaina Wastewater Reclamation
Facility. Haw. Wildlife Fund v. Cty. of Maui, 24 F. Supp. 3d 980, 983 (D.
Haw. 2014) [Hawaii I]. The facility receives approximately four million
gallons of sewage each day. Id. After treating the sewage, the facility
releases three to five million gallons of effluent into four on-site
injection wells. Id. at 983-84. The effluent travels into a shallow
groundwater aquifer and then flows into the Pacific Ocean through the
seafloor at points known as "submarine springs." Id. at 984; see also
Haw. Wildlife Fund v. Cty. of Maui, No. 12-198, 2015 WL 328227, at *1
(D. Haw. Jan. 23, 2015) [Hawaii II].
EPA, the Hawaii Department of Health (DOH), and others
conducted a tracer -dye study that confirmed this conclusion for injection
wells 3 and 4. Hawaii I, 24 F. Supp. 3d at 984. According to the study, it
took the leading edge of the dye 84 days to go from wells 3 and 4 to the
ocean and about 64% of the dye injected into these wells was discharged
from the submarine springs to the Pacific Ocean. Id. The dye's
appearance in the ocean "conclusively demonstrated that a
hydrogeologic connection exists." Id. at 985-86.
101

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contingent on a final judgment that the County violated the CWA and
that the County was "not immune from" civil penalties. Haw. Wildlife
Fund v. Cty. of Maui, No. 12-198, ECF No. 259. The court entered final
judgment in accordance with its opinions and the settlement
agreement.
The district court's first opinion held the County liable under the
CWA for unpermitted discharges from wells 3 and 4. Hawaii I, 24 F.
Supp. 3d at 1000. The court started its analysis with the language and
purpose of the CWA, and also relied on EPA's interpretation and case
law. Id. at 995-96. The court explained that Plaintiffs "must show that
pollutants can be directly traced from the injection wells to the ocean
such that the discharge at the LWRF is a de facto discharge into the
ocean." Id. at 998 (emphasis in original). The court found that Plaintiffs
had met this burden. Id. at 998-1000. The district court also found CWA
liability under the "significant nexus" standard from Justice Kennedy's
concurring opinion in Rapanos, 547 U.S. at 755-56, and the Ninth
Circuit's application of that standard in Northern California River
Watch v. City of Healdsburg; 496 F.3d 993, 999-1000 (9th Cir. 2007).
0

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The district court's second opinion held the County liable for
unpermitted discharges from wells 1 and 2. Hawaii II, 2015 WL
328227, at *6. The County "expressly conced[ed] that pollutants
introduced by the County into wells 1 and 2 were making their way to
the ocean," and the court rejected the County's argument that liability
does not arise unless a pollutant passes through "a series of sequential
point sources." Id. at *2-4.
The district court's third opinion rejected the County's argument
that it was not subject to civil penalties for its unpermitted discharges
because it lacked fair notice. Haw. Wildlife Fund v. Cty. of Maui, No.
12-198, 2015 WL 3903918, at *6 (D. Haw. June 25, 2015) [Hawaii III].
The court determined that the County had notice because the
discharges "clearly implicate[d] each statutory element." Id. at *4. The
court further held that its adjudication of the first motion for partial
summary -judgment provided notice to the County. Id. at *6.
The parties then entered into a settlement agreement, in which
the County stipulated that it would make good faith efforts to obtain
and comply with a NPDES permit and that it would pay $100,000 in
civil penalties and $2.5 million for a supplemental environmental
9

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project, all contingent on a final judgment and ruling that the County
violated the CWA and that the County was "not immune from" civil
penalties. Haw. Wildlife Fund v. Cty. of Maui, No. 12-198, ECF No. 259.
The district court then entered a final judgment.
SUMMARY OF ARGUMENT
The judgment should be affirmed because it is consistent with the
language and purpose of the Clean Water Act and EPA's longstanding
interpretation and practice of issuing NPDES permits for discharges of
pollutants similar to the ones here. As Justice Scalia said in Rapanos,
the statute's language prohibiting "any addition of any pollutant to
navigable waters from any point source" does not limit liability only to
discharges of pollutants directly to navigable waters. See Rapanos, 547
U.S. at 743 (plurality op.) (emphasis in original). Courts have
interpreted the CWA as covering not only discharges of pollutants
directly to navigable waters, but also discharges of pollutants that
travel from a point source to navigable waters over the surface of the
ground or through underground means. E.g., Sierra Club v. Abston
Constr. Co., 620 F.2d 41, 44-45 (5th Cir. 1980). The discharges in this
case fall squarely within the statutory language.
10

■ n ■ w .• 11 • V pr ■ n a 71 • �
In the United States' view, a NPDES permit is required here
because the discharges at issue are from a point source (i.e., the
injection wells) to waters of the United States (i.e., the Pacific Ocean's
coastal waters). To be clear, the United States views groundwater as
neither a point source nor a water of the United States regulated by the
CWA. The United States therefore agrees with the district court's
conclusion that a NPDES permit was required here, but only to the
extent that the court's analysis is consistent with the above -stated
principles regarding groundwater.
The district court's conclusions accord with the CWA's purpose.
Congress enacted the CWA "to restore and maintain ... the country's
waters"; and to achieve this goal, Congress created a strict -liability
regime prohibiting discharges unless they are authorized under the
CWA. Recognizing Congress's goals in the CWA, courts have concluded
that in certain circumstances discharges of pollutants that reach
navigable waters through groundwater fall squarely within the
statute's terms. E.g., Idaho Rural Council v. Bosma, 143 F. Supp. 2d
11692 1179-80 (D. Idaho 2001).
11

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Even if Congress's intent on this issue had been ambiguous, EPA
has clearly stated for decades that pollutants that move through
groundwater can constitute discharges subject to the CWA, and that
interpretation is entitled to Chevron deference. Chevron, U. S.A., Inc. v.
Nat. Res. Def. Council, Inc., 467 U.S. 837, 842-43 (1984). It has been
EPA's longstanding position that discharges moving through
groundwater to a jurisdictional surface water are subject to CWA
permitting requirements if there is a "direct hydrological connection"
between the groundwater and the surface water. See NPDES Permit
Regulation and Effluent Limitations Guidelines and Standards for
Concentrated Animal Feeding Operations, 66 Fed. Reg. 2960, 3017
(Jan. 12, 2001). This formulation recognizes that some hydrological
connections are too circuitous and attenuated to come under the CWA.
Id.
The County argues that the district court dispensed with the
requirements that a discharge be "from a point source" and "to
navigable water" because the effluent was discharged from a nonpoint
source and because the effluent was discharged into groundwater,
which is not covered by the CWA. Opening Brief (Op. Br.) at 21, 27, 30.
12

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This attempt to bifurcate the movement of the pollutants into two
separate events is inconsistent with the statute's language and purpose.
It also ignores the undisputed fact that the pollutants moved through
that groundwater to the ocean.
The County's argument that no civil penalty should have been
imposed because the County lacked fair notice lacks merit. The County
was on notice both as a general matter through the CWA's language
and EPA's statements in rulemakings—and specifically—through
communications from EPA to the County. In any event, the question of
fair notice goes to the amount of the civil penalty, an amount the
County stipulated to, and is only one of many factors informing a civil -
penalty amount.
ARGUMENT
I. THE DISTRICT COURT'S DECISIONS ARE CONSISTENT WITH THE
LANGUAGE AND PURPOSE OF THE CWA.
The district court's judgment holding the County liable under the
CWA is consistent with the text and purpose of the statute. It is also
consistent with EPA's long -held position governing when the CWA
requires permits for discharges of pollutants that move to jurisdictional
surface waters through groundwater with a direct hydrological
13

111,
_'- t 1: f�- i SM.�ii ia - •
connection. The County cannot recast the nature of the discharges to
avoid that result.
A. Discharges of Pollutants to Jurisdictional Surface Waters
Through Groundwater with a Direct Hydrological
Connection Properly Require CWA Permits.
When Congress prohibited the unpermitted "discharge of any
pollutant," it defined this term broadly as "any addition of any pollutant
to navigable waters from any point source." 33 U.S.C. §§ 1311,
1362(12)(A). As the County concedes, "a point source does not need to
discharge directly into navigable waters to trigger NPDES permitting."
Op. Br. at 27. Because Congress did not limit the term "discharges of
pollutants" to only direct discharges to navigable waters, discharges
through groundwater may fall within the purview of the CWA.
This reading of "discharge of a pollutant" has been applied in
other similar contexts where discharges of pollutants have moved from
a point source to navigable waters over the surface of the ground or by
some other means. In Sierra Club u. Abston Construction, which
addressed discharges from mining operations that traveled to navigable
waters in part through surface runoff, the Fifth Circuit stated that
"[g]ravity flow, resulting in a discharge into navigable body of water,
14

Case QdPt:taJ P1R +4 1'1/G1 1 i Ifo :'; • ;ii Mw i o 1; :::: 12240 R5LgeID# 9149
may be part of a point source discharge if the [discharger] at least
initially collected and channeled the water and other materials."3 620
F.2d at 44-45; see also Friends of Sakonnet v. Dutra, 738 F. Supp. 623,
628, 630 (D.R.I. 1990) (defendant liable for discharge of "raw sewage
[that] was running directly from the leaching field, on the surface of the
ground for approximately 250 feet, into the [surface water]"); O'Leary v.
Moyer's Landfill, Inc., 523 F. Supp. 642, 647 (E.D. Pa. 1981) ("[T]here is
no requirement that the point source need be directly adjacent to the
waters it pollutes.").
That Congress gave the term "discharge of a pollutant" a broad
meaning finds support in cases where CWA liability attached for
discharges from point sources that traveled through other means before
reaching surface waters. See Rapanos, 547 U.S. at 743 (noting that
courts have found violations of Section 301 "even if the pollutants
discharged from a point source do not emit `directly into' covered
3 The County misconstrues the United States' position as amicus curiae
in Abston Construction. See Op. Br. at 30-31. The United States took the
position that discharges of pollutants that traveled indirectly from a
point source to jurisdictional surface waters through surface runoff or
the gravity flow of rainwater come within the scope of the CWA. Brief
for the United States as Amicus Curiae, at 35-36, Sierra Club v. Abston
Constr. Co., No. 77-2530 (5th Cir. 1980).
15

"11
'11W. R. '; • " .i1 fll =' - P- • 1
waters, but pass `through conveyances' in between") (citing Sierra Club
v. El Paso Gold Mines, Inc., 421 F.3d 11335 1137 (10th Cir. 2005)
(defendant could be liable for discharges conveyed from its point -source
mine shaft to jurisdictional surface water through a tunnel that
defendant did not own); United States v. Velsicol Chem. Corp., 438 F.
Supp. 945, 946-47 (W.D. Tenn. 1976) (holding that CWA covered
pollutants discharged from defendant's point source to jurisdictional
surface waters conveyed through a sewer system that the defendant did
not own)).
Because courts have interpreted the term "discharge of a
pollutant" to cover discharges over the ground and through other
means, exempting discharges through groundwater could lead to absurd
results. As one court noted, "it would hardly make sense for the CWA to
encompass a polluter who discharges pollutants via a pipe running from
the factory directly to the riverbank, but not a polluter who dumps the
same pollutants into a man-made settling basin some distance short of
the river and then allows the pollutants to seep into the river via the
groundwater." N. Cal. River Watch v. Mercer Fraser Co., No. 04-4620,
2005 WL 2122052, at *2 (N.D. Cal. Sept. 1, 2005).
16

A ,ill 'ii &KNIP • `"II (ll +�':a I it �'�: 1'�:: i s . �lj m . •
The County concedes that discharges need not be direct and that a
discharge through a conveyance requires a permit. Op. Br. at 27. The
County argues, however, that the conveyance itself must be a point
source and that because groundwater is not a point source, the district
court "impermissibly `transform[s] a nonpoint source into a point
source."' Id. at 27-28, 33. The County's interpretation is flawed.
Contrary to the County's argument, the district court did not eliminate
the requirement that a discharge be "from a point source." All it said
was that pollutants from a point source need not be emitted directly
into covered waters. The case law does not require the means by which
the pollutant discharged from a point source reaches a water of the
United States to be a point source.
While the County's statement that the statutory definition of
"navigable waters" does not include groundwater is accurate, Op. Br. at
21, it is beside the point. There is no dispute that groundwater itself is
not a "navigable water," 80 Fed. Reg. 37,054, 37,055 (June 29, 2015),
but the district court's decisions hinge on the movement of pollutants to
jurisdictional surface waters through groundwater with a direct
17

'� �.� , i a � �: � ., i : : • �i'n`' , : - � -
hydrological connection. Such an addition of pollutants to navigable
waters falls squarely within the CWA's scope.
The County relies on the treatment of groundwater in legislative
history, Op. Br. at 21-23, but this "only supports the unremarkable
proposition with which all courts agree—that the CWA does not
regulate `isolated/nontributary groundwater' which has no [effect] on
surface water." Bosma, 143 F. Supp. 2d at 1180. It does not undermine
the conclusion that discharges of pollutants through groundwater to
jurisdictional surface waters are subject to the NPDES program.
The County contends that case law does not support the district
court's interpretation, Op. Br. at 35-37, but this argument largely
ignores the majority of the courts that have addressed this issue and
concluded that discharges that move from a point source to
jurisdictional surface waters via groundwater with a hydrological
connection are subject to regulation under the CWA. See, e.g., Sierra
Club v. Va. Elec. & Power Co., No. 15-112, 2015 WL 6830301 (E.D. Va.
Nov. 6, 2015); Yadkin Riverkeeper v. Duke Energy Carolinas, LLC, No.
14-753, 2015 WL 6157706 (M.D.N.C. Oct. 20, 2015); S.F. HerringAss'n
v. Pac. Gas & Elec. Co., 81 F. Supp. 3d 847 (N.D. Cal. 2015); Hernandez
100

■ n ■ • .� U • v �• ii n 7 I G1� - � •
Qd�1yi:� J �1 � � � �/ c1 .i if -li IFo ►,riy 0) � 1.� i i� I : C .. i ' G � iv �
v. Esso Std. Oil Co., 599 F. Supp. 2d 175 (D.P.R. 2009); Nw. Envtl. Def.
Ctr. v. Grabhorn, No. 08-548, 2009 WL 3672895 (D. Or. Oct. 30, 2009);
Mercer Fraser, 2005 WL 2122052; Bosma, 143 F. Supp. 2d 1169.
The County's reliance on other case law (Op. Br. at 35-36) is
unavailing for three reasons. First, none of the cases are controlling
precedent. Second, most of these decisions are inapposite because they
do not address the issue of discharges of pollutants that move through
groundwater to jurisdictional surface waters. In Village of Oconomowoc
Lake v. Dayton Hudson, Corp., the court examined whether
groundwater itself was a navigable water, i.e., a water within the
meaning of the CWA. 24 F.3d 962, 965 (7th Cir. 1994). That is distinct
from whether a CWA permit is required when pollutants travel to
jurisdictional surface waters through groundwater with a direct
hydrological connection.
Third, these cases do not foreclose application of the CWA where a
direct hydrological connection to jurisdictional surface waters can be
found. In Rice v. Harken Exploration Co., the court concluded that a
discharge of oil that might reach navigable waters by gradual, natural
seepage was not the equivalent of a discharge to navigable waters. 250
19

G1 11: -1,30111 F • 1:1 n . •
F.3d 264, 271 (5th Cir. 2001). The court suggested, however, that it
would be open to finding a discharge had occurred through groundwater
when it underscored the plaintiffs' failure to provide any "evidence of a
close, direct and proximate link between [the defendant's] discharges of
oil and any resulting actual, identifiable oil contamination of a
particular body of natural surface water." Id. at 272.
B. The District Court's Decisions Give Full Effect to
Congress's Intent to Restore and Maintain the Nation's
Waters.
Congress's purpose in enacting the CWA—to "restore and
maintain the chemical, physical, and biological integrity of the Nation's
waters"—embraced a "broad, systemic view ... of water quality."
United States v. Riverside Bayview Homes, Inc., 474 U.S. 121, 132
(1985). The County attempts to minimalize that goal. Adopting the
County's theory would allow dischargers to avoid responsibility simply
by discharging pollutants from a point source into jurisdictional surface
waters through any means that was not direct.
Courts have viewed the CWA's broad purpose of protecting the
quality of navigable waters as a clear congressional signal that "any
pollutant which enters such waters, whether directly or through
20

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groundwater, is subject to regulation by NPDES permit." Wash.
Wilderness Coal. u. Hecla Mining Co., 870 F. Supp. 983, 990 (E.D.
Wash. 1994). "Stated even more simply, whether pollution is introduced
by a visible, above -ground conduit or enters the surface water through
the aquifer matters little to the fish, waterfowl, and recreational users
which are affected by the degradation to our nation's rivers and
streams." Bosma, 143 F. Supp. 2d at 1179-80.
The state's authority to protect groundwater is in no way impaired
by subjecting point sources to NPDES-permit requirements to protect
surface waters. Thus, the County's argument that it should not be liable
here because "preservation of states' authority over the regulation of
groundwater" is a "co -equal" goal of the CWA misses the mark. Op. Br.
at 34-35. This emphatically is not a case about the regulation of
groundwater. Instead it is about the regulation of discharges of
pollutants to waters of the United States. To the extent the County's
argument relies on the regulatory scheme governing disposal into wells,
Op. Br. at 24-27, that is flawed because the regulation of wells under
the Safe Drinking Water Act's (SDWA) Underground Injection Control
(UIC) program does not preclude or displace regulation under the
21

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CWA's NPDES program.4 See Hudson R. Fishermen's Ass'n v. City of
New York, 751 F. Supp. 1088, 1100 (S.D.N.Y. 1990), aff'd, 940 F.2d 649
(2d Cir. 1991) (objectives of the CWA and the SDWA are not "mutually
exclusive"); see also Bath Petrol. Storage, Inc. v. Sovas, 309 F. Supp. 2d
357, 369 (N.D.N.Y. 2004).
C. The District Court's Finding of Liability Is Consistent with
EPA's Longstanding Position.
EPA's longstanding position has been that point -source discharges
of pollutants moving through groundwater to a jurisdictional surface
water are subject to CWA permitting requirements if there is a "direct
hydrological connection" between the groundwater and the surface
water. EPA has repeatedly articulated this view in multiple rulemaking
preambles. In 1990, EPA stated that "this rulemaking only addresses
discharges to water of the United States, consequently discharges to
ground waters are not covered by this rulemaking (unless there is a
4 The County misconstrues EPA's position in Inland Steel v. EPA, 901
F.2d 1419 (7th Cir. 1990). EPA argued that not all disposals into
injection wells are discharges of pollutants under the CWA, and that
the connection between the wells and navigable waters in that case was
too attenuated to bring the discharges under the purview of the CWA.
Id. at 1422-23. That position (embraced by the Seventh Circuit) does not
mean that "injection into wells is not a discharge of pollutants requiring
a NPDES permit." Op. Br. at 27.
22

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hydrological connection between the ground water and a nearby surface
water body)." NPDES Permit Application Regulations for Storm Water
Discharges, 55 Fed. Reg. 47,990, 47,997 (Dec. 2, 1990).
And in the preamble to its final rule addressing water quality
standards on Indian lands, EPA stated: ,
[T]he Act requires NPDES permits for discharges to
groundwater where there is a direct hydrological connection
between groundwaters and surface waters. In these
situations, the affected groundwaters are not considered
"waters of the United States" but discharges to them are
regulated because such discharges are effectively discharges
to the directly connected surface waters.
56 Fed. Reg. at 64,982.
In 2001, EPA reiterated its position: "As a legal and factual
matter, EPA has made a determination that, in general, collected or
channeled pollutants conveyed to surface waters via ground water can
constitute a discharge subject to the Clean Water Act." 66 Fed. Reg. at
3017. EPA recognized that the determination was "a factual inquiry,
like all point source determinations," adding:
The time and distance by which a point source discharge is
connected to surface waters via hydrologically connected
surface waters will be affected by many site specific factors,
such as geology, flow, and slope. Therefore, EPA is not
proposing to establish any specific criteria beyond confining
23

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the scope of the regulation to discharges to surface water via
a "direct" hydrological connection.
Id. A general hydrological connection between all groundwater and
surface waters is insufficient; there must be evidence showing a direct
hydrological connection between specific groundwater and specific
surface waters. Id.
To the extent there is statutory ambiguity about whether the
CWA applies to discharges to jurisdictional surface waters through
groundwater, EPA's interpretation is entitled to Chevron deference.
Chevron, 467 U.S. at 842-43.
The County's contention that the direct -hydrological -connection
standard is at odds with EPA's recently -stated position on whether
groundwater is a jurisdictional water misinterprets EPA's statements.
Op. Br. at 38-39. The Clean Water Rule, which was promulgated in
June 2015 (and stayed by the Sixth Circuit pending further order of the
court, see In re EPA & Dept of Def. Final Rule, 803 F.3d 804, 809 (6th
Cir. 2015)), expressly excludes groundwater from the definition of
"waters of the United States." 80 Fed. Reg. 37,054. But, as EPA
clarified, the fact that groundwater itself is not jurisdictional under the
CWA does not mean that pollutants that reach waters of the United
24

Case 2:15-cv J 2L3AG44JK09Mb8� [ 399)9 Ak% ONE0 r: 4 fm@8 8t4ff R&ge[D# 9159
States through groundwater do not require CWA permits. "EPA agrees
that the agency has a longstanding and consistent interpretation that
the Clean Water Act may cover discharges of pollutants from point
sources to surface water that occur via ground water that has a direct
hydrologic connection to the surface water. Nothing in this rule changes
or affects that longstanding interpretation, including the exclusion of
groundwater from the definition of `waters of the United States."' See
EPA, Response to Comments — Topic 10 Legal Analysis (June 30, 2015);
available at http://www.epa.gov/cleanwaterrule/response-comments-
cle an -water -rule -definition-waters-unite d- states. The County
erroneously attempts to conflate the jurisdictional exclusion of
groundwater with the role that groundwater can play as the pathway
through which pollutants from a point source reach jurisdictional
surface waters.5
5 The district court stated that if the proposed Clean Water Rule was
finalized, it "would likely mean that the groundwater under the
[facility] could not itself be considered `waters of the United States"' and
that this would affect whether Plaintiffs could also prevail under
Healdsburg. Hawaii 1, 24 F. Supp. 3d at 1001. But the court erred in
attempting to apply Healdsburg because the jurisdictional status of
groundwater itself is irrelevant to whether discharges that move
through groundwater to jurisdictional waters require NPDES permits.
25

Ifs `� 'n1 fel i'w I v ��i0 Ute:. G' G �Si •
II. THE COUNTY IS LIABLE FOR UNPERMITTED DISCHARGES DUE TO
THE "DIRECT HYDROLOGICAL CONNECTION" BETWEEN THE
GROUNDWATER AND THE OCEAN.
Discharges of pollutants from a point source that move through
groundwater are subject to CWA permitting requirements if there is a
direct hydrological connection between the groundwater and a
jurisdictional surface water.6 Ascertaining whether there is a direct
hydrological connection is a fact -specific determination. 66 Fed. Reg. at
3017. To qualify as "direct," a pollutant must be able to proceed from
the point of injection to the surface water without significant
interruption. Relevant evidence includes the time it takes for a
pollutant to move to surface waters, the distance it travels, and its
traceability to the point source. These factors will be affected by the
type of pollutant, geology, direction of groundwater flow, and evidence
that the pollutant can or does reach jurisdictional surface waters. Id.
Here, the district court correctly held that the County discharged
pollutants to the ocean through groundwater. In Hawaii I, the court
6 Some courts refer to a "hydrological connection." The more accurate
formulation, however, is a "direct hydrological connection," which
recognizes that some connections are too circuitous and attenuated to
be under the CWAs purview.
26

11111
'1gil i it '1? If► !'; • Dict (l) �'� i o - • •
determined that a direct hydrological connection exists between the
groundwater and the ocean. The tracer -dye study clearly established
that the discharges moved from wells 3 and 4 to the ocean in relatively
short order.7 Hawaii I, 24 F. Supp. 3d at 984. The study concluded that
after 84 days, the dye began to appear along the North Kaanapah
Beach, half a mile from the facility. Id. The tracer -dye study also
estimated that 64% of the treated effluent from wells 3 and 4 followed
this route to the ocean. Id.
Although the court's ultimate conclusion was correct, the court's
alternative explanation for the County's liability under the "significant
_f
nexus" standard from Rapanos and Healdsburg was erroneous. Hawaii
I, 24 F. Supp. 3d at 1004. Rapanos and Healdsburg applied the
"significant nexus" standard in determining whether the receiving
waters were "waters of the United States." In contrast, here, there is no
dispute that the Pacific Ocean (the receiving water in this case), as a
"territorial sea," is a "navigable water" under the CWA. This Court
7 Although this tracer -dye study simplified the analysis, such studies
are not the only means of demonstrating a direct hydrological
connection. It also is not necessary to trace the exact pathway that the
pollutants take to establish that a direct hydrological connection exists.
27

3 ,1 I/ .i1. Ifs .• ii " ?it �) �r'e]
• • II a �"�: 1'�" G - G' • �Sa °i •
should clarify that the "significant nexus" standard has no relevance
here.
In Hawaii II, the district court correctly held the County
discharged pollutants from wells 1 and 2 to the ocean through
groundwater. But the court's opinion did not go into great detail about
the movement through groundwater because the County "expressly
conced[ed] that pollutants introduced by the County into wells 1 and 2
were making their way to the ocean" and "acknowledge [d] that there is
a hydrogeologic connection between wells 1 and 2 and the ocean."
Hawaii II, 2015 WL 328227, at *2.
There was additional evidence that a direct hydrological
connection existed between wells 1 and 2 and the Pacific Ocean. First,
the tracer -dye study models indicated that in some circumstances
treated effluent from well 2 would move along flowpaths that were
similar to those traveled by the dye injected into wells 3 and 4 and
would emerge at the same submarine springs. SER 237, 240, 243.
Because wells 3 and 4 are located between the springs and well 2, the
flowpath for these discharges would be affected by the amount of
effluent injected into each well. SER 237. When most of the effluent was
M

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injected into wells 3 and 4, the effluent from well 2 would travel
northwesterly from the wells and not toward the springs; however,
when well 2 received all of the effluent, the study indicated that the
discharges would emerge at the springs. SER 240, 243. There was no
dispute that given the proximity of wells 1 and 2, the modeling for well
2 predicts the pathways for discharges from well 1. ER 443, SER 189.
Second, Plaintiffs' expert stated that the effluent discharged from
wells 1 and 2 "will be conveyed ... relatively quickly (i.e., with first
arrival at the ocean in a matter of months)" and concluded that "[s]ince
the aquifer material and hydraulic gradient in the area of all four ...
wells are similar, the groundwater flow will also be similar." SER 183.
Although the County's expert argued that the point of entry for
pollutants into the ocean from wells 1 and 2 could not be identified, the
County did not dispute that the study showed effluent emerging at the
same springs where the effluent from wells 3 and 4 emerged. Haw.
Wildlife Fund v. Cty. of Maui, No. 12-198, ECF No. 136, at 16.
Any fears about the implications of point -source discharges to
jurisdictional surface waters through groundwater with a direct
hydrological connection being subject to NPDES-permit requirements
29

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are unwarranted. Op. Br. at 43-44. EPA and states have been issuing
permits for this type of discharge from a number of industries, including
chemical plants, concentrated animal feeding operations, mines, and oil
and gas waste -treatment facilities. See, e.g., NPDES Permit No.
NM0022306, available at https://www.env.nm.gov/swqb/Permits/;
NPDES Permit No. WA0023434, available at
https://yosemite.epa. gov/r10/water.nsf/NPDES+Permits/CurrentOR&W
A821.
Further, only those discharges that move through groundwater
with a direct hydrological connection to surface waters are affected.
That not all discharges through groundwater are subject to NPDES-
permit requirements is shown by cases where the hydrological
connections were too attenuated. In McClellan Ecological Seepage
Situation (MESS) v. Weinberger, the court agreed with the plaintiff that
discharges through groundwater may be subject to the CWA and
allowed the parties to submit evidence on the issue. 707 F. Supp. 1182,
1196 (E.D. Cal. 1988). Based on evidence indicating that it would take
"literally dozens, and perhaps hundreds, of years for any pollutants in
the groundwater to reach surface waters," the court found that there
30

u114 (I) i 1.. i, �r � �: � ., c c . �i'i - : � - � • •
were no regulated discharges. MESS v. Cheney, 763 F. Supp. 431, 437
(E.D. Cal. 1989). And even after allowing the plaintiff an opportunity to
provide more testimony at trial, the court ruled that the plaintiff had
failed to meet its burden. MESS v. Cheney, No. 86-475, 20 Envtl. L.
Rep. 20,877 (E.D. Cal. Apr. 30, 1990), vacated on other grounds, 47 F.3d
325, 331 (9th Cir. 1995).
Likewise, in Greater Yellowstone Coalition v. Larson, evidence
indicated that the connection to surface waters was too attenuated. 641
F. Supp. 2d 1120 (D. Idaho 2009), aff'd 628 F.3d 1143, 1153 (9th Cir.
2010). In that case, federal agencies determined that a CWA Section
401 certification was not required for a mining operation. Under Section
401, "[a]ny applicant for a Federal license or permit to conduct any
activity ... which may result in any discharge into the navigable
waters, shall provide the licensing or permitting agency a certification
from the State ... that any such discharge will comply with the
applicable provisions." 33 U.S.C. § 1341(a)(1). The agencies based their
determination on evidence that before reaching surface waters, the
pollutants would pass through hundreds of feet of overburden and
bedrock, and then travel underground through soil and rock for one to
31

�IF �'1IC1 �I1 `•? Ifo :'; • `� i�iy IIl 'A• II a �n T a .� •
four miles. Greater Yellowstone, 641 F. Supp. 2d at 1139. Modeling
predicted that the movement of peak concentrations would take
between 60 and 420 years. Id. The court weighed competing evidence
from the plaintiff and ultimately deferred to the agencies'
determination that the hydrological connection was too attenuated. Id.
at 1141.
Unlike MESS and Greater Yellowstone, in which the connection
was too attenuated, the discharges here resulted from a direct
hydrological connection, and thus require a permit.
III. THE DISTRICT COURT CORRECTLY HELD THAT THE COUNTY HAD
FAIR NOTICE FOR PURPOSES OF CIVIL PENALTIES.
In the Argument section of its brief, the County maintains that
this Court should direct the district court to set aside any civil penalties
"imposed on the County regardless of the outcome of the challenge to
the district court's liability rulings" because it lacked fair notice. Op. Br.
at 47. As an initial matter, the County would seemingly be precluded
from appealing the fair -notice issue as to civil penalties because it
stipulated to their amount in the settlement agreement. To the extent
that the County has reserved its right to appeal the issue, however, the
County's argument lacks merit.
32

»1j:�� J � +l� ��' � ��/t:1 .i ll' '� �� ': �� • � :iit ��) ���� ' I it IBJ: ITS. i ti � I�{� n - � � � • •
This Court has held that a party may not be deprived of property
through civil penalties without fair notice. See United States v.
Approximately 64,695 Pounds of Shark Fins, 520 F.3d 976, 980 (9th Cir.
2008). To provide notice, "a statute or regulation must `give the person
of ordinary intelligence a reasonable opportunity to know what is
prohibited so that he may act accordingly."' Id.
This Court looks first to the language of the statute when
determining whether a party had fair notice. Id. As discussed above,
Congress used broad language in the CWA in defining the discharge of
pollutants, and that expansiveness provides a reasonable opportunity
for a person to know what the statute prohibits. The breadth of that
language is only bolstered by the intent of the CWA.
Moreover, EPA has made multiple public statements in
rulemaking preambles that consistently described its interpretation
that discharges of pollutants to jurisdictional surface waters through
groundwater with a direct hydrological connection are subject to
NPDES permitting under the CWA. Further, with respect to specific
communications with the County, EPA sent two letters to the County in
early 2010. In January 2010, EPA stated that it was "investigating the
33

�11
'1/Cci li •ii IFo. t„ai (1) i!.,• i o : 1 .. ! i iii - • • •
possible discharge of pollutants to the coastal waters of the Pacific
Ocean along the Kaanapali coast of Maui.” SER 5. This investigation
was spurred in part by a 2007 study concluding that much of the
nitrogen in Kaanapali coastal waters came from the County's facility
and a 2009 study that found the same nitrogen signature and other
"wastewater presence" in the ocean. Hawaii I, 24 F. Supp. 3d at 984.
The letter continued: "In order to assess the impact of the [facility's]
effluent on the coastal waters and determine compliance with the Act,
EPA is requiring the County to sample the injected effluent, sample the
coastal seeps, conduct an introduced tracer study, and submit reports
on findings to EPA." SER 5. EPA required this sampling, monitoring,
and reporting pursuant to CWA Section 308, under which "the [EPA]
Administrator shall require the owner or operator of any point source"
to provide the information. 33 U.S.C. § 1318(a)(A). The letter provided
notice that there was evidence suggesting a hydrological connection.
In March 2010, EPA responded to the County's request for a UIC
permit renewal under the SDWA "by informing the County that recent
studies `strongly suggest that effluent from the facility's injection wells
is discharging into the near shore coastal zone of the Pacific Ocean."
34

Qy.�l:i:1 J " �1 � �'1 ',1/Ct a ti .•ti Iti �'; • " i;1 O) � �':� it a �'�: 1'� ; : �. ; � ili =' : • - � • • • •
Hawaii I, 24 F. Supp. 3d at 984 (quoting ER 122). As a result, EPA
required the County to apply for a CWA Section 401 water -quality
certification for its injection facilities as a prerequisite to EPA's
issuance of a new UIC permit. ER 121-22; see 33 U.S.C. § 1341(a). The
County's assertion that this letter did not put it on notice of potential
CWA liability because the certification was related to its UIC permit
rather than any obligations under the NPDES program is unavailing.
Op. Br. at 56-57. A UIC permit does not preclude the need for a NPDES
permit where required, and the March 2010 communication reiterated
EPA's position that the discharges might be covered by the CWA,
depending on the results of the ordered sampling, monitoring, and
reporting.
The County was on fair notice. In any event, fair notice is only one
of many factors informing a civil -penalty amount, see 33 U.S.C. §
1319(d), and thus the County's argument that the penalty should be set
aside for lack of fair notice alone is flawed.
35

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CONCLUSION
For the foregoing reasons, the district court's judgment should be
affirmed.
OF COUNSEL:
KARYN WENDELOWSKI
U.S. Environmental
Protection Agency
Office of General Counsel
Washington, D.C.
May 31, 2016
90-12-14672
Respectfully submitted,
JOHN C. CRUDEN
Assistant Attorney General
Is/ Frederick H. Turner
FREDERICK H. TURNER
AARON P. AVILA
R. JUSTIN SMITH
Attorneys, U.S. Dep't of Justice
Env't & Natural Resources Div.
P.O. Box 7415
Washington, DC 20044
[phone]
[e-mail]
36

�1 ■ 1 r • • 1; • V ��� � Ifl 7,;• i, � i I I L7 •
CERTIFICATE OF COMPLIANCE
WITH TYPE VOLUME LIMITATION, TYPEFACE
REQUIREMENTS, AND TYPE -STYLE REQUIREMENTS
This brief complies with the type -volume limitation of Fed. R. App.
P. 32(a)(7)(B) (for amicus briefs as provided by Fed. R. App. P. 29(d))
because it contains 6,904 words, excluding the parts of the brief
exempted by Fed. R. App. P. 32(a)(7)(B)(iii). This brief complies with the
typeface requirements of Fed. R. App. P. 32(a)(5) and the type -style
requirements of Fed. R. App. P. 32(a)(6) because it has been prepared in
a proportionally spaced typeface using Microsoft Word 14 -point Century
Schoolbook.
37
Is/ Frederick H. Turner
FREDERICK H. TURNER
U.S. Department of Justice
Env't & Natural Resources Div.
P.O. Box 7415
Washington, DC 20044
[phone]
[e-mail]

Q�.�3d:7 J ' �t R �n � ',/ � .. 1 � li Ido •:'; • � i:.i�0 �) :AI �� i° : 1'��,: '!' - ? • � '� �' � � - � •
CERTIFICATE OF SERVICE
I hereby certify that on May 31, 2016, I electronically filed the
foregoing brief with the Clerk of the Court for the United States Court
of Appeals for the Ninth Circuit using the appellate CM/ECF system,
which will serve the brief on the other participants in this case.
Is /Frederick H. Turner
FREDERICK H. TURNER
U.S. Department of Justice
Env't & Natural Resources Div.
P.O. Box 7415
Washington, DC 20044
[phone]
[e-mail]