DUKE A. ta ENERGY

VIA ELECTRONIC FILING AND OVERNIGHT DELIVERY The Honorable Jocelyn G. Boyd Chief Clerk & Adminislrator

April 28, 2016

Public Service Commission of South Carolina IOI Executive Center Drive, Suite 100 Columbia, South Carolina 29211

Charles A. Castle Associate General Counsel

Duke Energy Corporation 550 Soulh Tryon Streel

Charlotte, NC 28202

Mailing Address: OEC45A I P.O. Box 1321

Charlolle, NC 28201

o. 704.382.4499 I 980.373.8534

[email protected]

RE: Duke Energy Progress, LLC Annual Review of Base Rates for Fuel Costs Docket No. 2016-1-E

Dear Mrs. Boyd:

Enclosed for filing on behalf of Duke Energy Progress, LLC ("DEP"), please find the Direct Testimony and Exhibits of the following witnesses:

1. Kenneth D. Church, 2. T. Preston Gillespie, Jr., 3. Swati V. Daji, 4. Kimberly D. McGee, 5. Joseph A. Miller, Jr., and 6. Emily 0. Felt

The Company respectfully requests that Exhibit 3 of T. Preston Gillespie, Jr. be accepted by the Commission under seal and maintained as confidential pursuant to Order No. 2005-226. Company witness Gillespie's Exhibit 3 contains certain proprietary and confidential information relating to sensitive outage information that if disclosed, could negatively impact DEP's ability to safely and reliably provide effective service to its customers. The Company requests that the Commission grant the Company's request for confidential treatment, pursuant to 26 S.C. Code Ann. Regs. 103-804(S)(2)(2015 Supp.) and the Freedom of Information Act, S.C. Code Ann. § 30-4-10 et seq., and protect this information from public disclosure.

DUKEta ENERGY.

Charles A. CastleAssociate General Caunsel

Duke Energy Corgoration550 South Tryon Street

Charlotte, NC 28202

Mailing Address,DEC45A1 P.O. Box 1321

Charlotte, NC 28201

rx 704. 382. 4499f'80.373.8534

alex.caslleaduke-energy.corn

April 28, 2016

VIA ELECTRONIC FILING ANDOVERNIGHT DELIVERYThe Honorable Jocelyn G. BoydChief Clerk & AdministratorPublic Service Commission of South Carolina101 Executive Center Drive, Suite 100Columbia, South Carolina 29211

RE: Duke Energy Progress, LLC Annual Review of Base Rates for Fuel CostsDocket No. 2016-1-E

Dear Mrs. Boyd:

Enclosed for filing on behalf of Duke Energy Progress, LLC ("DEP"), please find theDirect Testimony and Exhibits of the following witnesses:

1.

2.

4.

6.

Kenneth D. Church,T. Preston Gillespie, Jr.,Swati V. Daji,Kimberly D. McGee,Joseph A. Miller, Jr., andEmily O. Felt

The Company respectfully requests that Exhibit 3 of T. Preston Gillespie, Jr. be acceptedby the Commission under seal and maintained as confidential pursuant to Order No. 2006-226.Company witness Gillespie's Exhibit 3 contains certain proprietary and confidential informationrelating to sensitive outage information that if disclosed, could negatively impact DEP's abilityto safely and reliably provide effective service to its customers. The Company requests that theCommission grant the Company's request for confidentiai treatment, pursuant to 26 S.C. CodeAnn. Regs. 103-804(S)(2)(2015 Supp.) and the Freedom of Information Act, S.C. Code Ann. Ii

30-4-10 et seq., and protect this information from public disclosure.

2 0 1 6

P a g c 2

B y c o p y o f t h i s l e t t e r , I a m s e r v i n g a l l p a r t i e s o f r e c o r d v i a e l e c t r o n i c m a i l . P l e a s e

c o n t a c t m e i f y o u h a v e a n y q u e s t i o n s c o n c e r n i n g t h i s l i l i n g .

C h a r l e s A. C a s t l e

E n c l o s u r e s

c c : S e r v i c e L i s t

Jocelyn Ci. BoydApril 28, 2016Page 2

By copy of this letter, I am serving all parties of record via electronic mail. Pleasecontact me if you have any questions concerning this it ling.

Very truly yours,

Charles A. Castle

Enclosurescc: Service List,

BEFORE THE PUBLIC SERVICE COMMISSION OF

SOUTH CAROLINA

DOCKET NO. 2016-1-E

In the Matter of ) Annual Review of Base Rates ) DIRECT TESTIMONY OF For Fuel Costs for ) KENNETH D. CHURCH FOR Duke Energy Progress, LLC ) DUKE ENERGY PROGRESS, LLC )

DIRECT TESTIMONY OF KENNETH D. CHURCH Page 2 DUKE ENERGY PROGRESS, LLC DOCKET NO. 2016-1-E

Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. 1

A. My name is Kenneth D. Church and my business address is 526 South Church 2

Street, Charlotte, North Carolina. 3

Q. BY WHOM ARE YOU EMPLOYED AND IN WHAT CAPACITY? 4

A. I am the Manager of Nuclear Fuel Engineering’s Fuel Management & Design for 5

Duke Energy Progress, LLC (“DEP” or the “Company”) and Duke Energy 6

Carolinas, LLC (“DEC”). 7

Q. WHAT ARE YOUR PRESENT RESPONSIBILITIES AT DEP? 8

A. I am responsible for nuclear fuel procurement and spent fuel management, as well as 9

the fuel mechanical design and reload licensing analysis for the nuclear units owned 10

and operated by DEP and DEC. 11

Q. PLEASE SUMMARIZE YOUR EDUCATIONAL BACKGROUND AND 12

PROFESSIONAL EXPERIENCE. 13

A. I graduated from North Carolina State University with a Bachelor of Science degree 14

in mechanical engineering. I began my career with DEC in 1991 as an engineer and 15

worked in various roles, including nuclear fuel assembly and control component 16

design, fuel performance, and fuel reload engineering. I assumed the commercial 17

responsibility for purchasing uranium, conversion services, enrichment services, and 18

fuel fabrication services at DEC in 2001. Beginning in 2011, I incrementally 19

assumed responsibility at DEC for spent nuclear fuel management along with the 20

nuclear fuel mechanical design and reload licensing analysis functions. 21

Subsequently, I assumed the same responsibilities for DEP following the merger 22

between Duke Energy Corporation and Progress Energy, Inc. 23


I have served as Chairman of the Nuclear Energy Institute’s Utility Fuel 1

Committee, an association aimed at improving the economics and reliability of 2

nuclear fuel supply and use, and currently serve on the World Nuclear Fuel Market’s 3

Board of Governors, an organization that promotes efficiencies in the nuclear fuel 4

markets. I am currently a registered professional engineer in the state of North 5

Carolina. 6

Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS 7

PROCEEDING? 8

A. The purpose of my testimony is to (1) provide information regarding DEP’s nuclear 9

fuel purchasing practices, (2) provide costs for the March 1, 2015 through February 10

29, 2016 review period (“review period”), and (3) describe changes forthcoming for 11

the July 1, 2016 through June 30, 2017 billing period (“billing period”). 12

Q. YOUR TESTIMONY INCLUDES TWO EXHIBITS. WERE THESE 13

EXHIBITS PREPARED BY YOU OR AT YOUR DIRECTION AND UNDER 14

YOUR SUPERVISION? 15

A. Yes. These exhibits were prepared at my direction and under my supervision, and 16

consist of Church Exhibit 1, which is a Graphical Representation of the Nuclear Fuel 17

Cycle, and Church Exhibit 2, which sets forth the Company’s Nuclear Fuel 18

Procurement Practices. 19

Q. PLEASE DESCRIBE THE COMPONENTS THAT MAKE UP NUCLEAR 20

FUEL. 21

A. In order to prepare uranium for use in a nuclear reactor, it must be processed from an 22

ore to a ceramic fuel pellet. This process is commonly broken into four distinct 23


industrial stages: 1) mining and milling; 2) conversion; 3) enrichment; and 4) 1

fabrication. This process is illustrated graphically in Church Exhibit 1. 2

Uranium is often mined by either surface (i.e., open cut) or underground 3

mining techniques, depending on the depth of the ore deposit. The ore is then sent to 4

a mill where it is crushed and ground-up before the uranium is extracted by leaching, 5

the process in which either a strong acid or alkaline solution is used to dissolve the 6

uranium. Once dried, the uranium oxide (“U3O8”) concentrate – often referred to as 7

yellowcake – is packed in drums for transport to a conversion facility. Alternatively, 8

uranium may be mined by in situ leach (“ISL”) in which oxygenated groundwater is 9

circulated through a very porous ore body to dissolve the uranium and bring it to the 10

surface. ISL may also use slightly acidic or alkaline solutions to keep the uranium in 11

solution. The uranium is then recovered from the solution in a mill to produce U3O8. 12

After milling, the U3O8 must be chemically converted into uranium 13

hexafluoride (“UF6”). This intermediate stage is known as conversion and produces 14

the feedstock required in the isotopic separation process. 15

Naturally occurring uranium primarily consists of two isotopes, 0.7% 16

Uranium-235 (“U-235”) and 99.3% Uranium-238. Most of this country’s nuclear 17

reactors (including those of the Company) require U-235 concentrations in the 3-5% 18

range to operate a complete cycle of 18 to 24 months between refueling outages. 19

The process of increasing the concentration of U-235 is known as enrichment. Gas 20

centrifuge is the primary technology used by the commercial enrichment suppliers. 21

This process first applies heat to the UF6 to create a gas, then, using the mass 22

differences between the uranium isotopes, the natural uranium is separated into two 23


gas streams, one being enriched to the desired level of U-235, known as low 1

enriched uranium, and the other being depleted in U-235, known as tails. 2

Once the UF6 is enriched to the desired level, it is converted to uranium 3

dioxide powder and formed into pellets. This process and subsequent steps of 4

inserting the fuel pellets into fuel rods and bundling the rods into fuel assemblies for 5

use in nuclear reactors is referred to as fabrication. 6

Q. PLEASE PROVIDE A SUMMARY OF DEP’S NUCLEAR FUEL 7

PROCUREMENT PRACTICES. 8

A. As set forth in Church Exhibit 2, DEP’s nuclear fuel procurement practices involve 9

computing near and long-term consumption forecasts, establishing nuclear system 10

inventory levels, projecting required annual fuel purchases, requesting proposals 11

from qualified suppliers, negotiating a portfolio of long-term contracts from diverse 12

sources of supply, and monitoring deliveries against contract commitments. 13

For uranium concentrates, conversion, and enrichment services, long-term 14

contracts are used extensively in the industry to cover forward requirements and 15

ensure security of supply. Throughout the industry, the initial delivery under new 16

long-term contracts commonly occurs several years after contract execution. DEP 17

relies extensively on long-term contracts to cover the largest portion of its forward 18

requirements. By staggering long-term contracts over time for these components of 19

the nuclear fuel cycle, DEP’s purchases within a given year consist of a blend of 20

contract prices negotiated at many different periods in the markets, which has the 21

effect of smoothing out DEP’s exposure to price volatility. Diversifying fuel 22

suppliers reduces DEP’s exposure to possible disruptions from any single source of 23


supply. Due to the technical complexities of changing fabrication services suppliers, 1

DEP generally sources these services to a single domestic supplier on a plant-by-2

plant basis using multi-year contracts. 3

Q. PLEASE DESCRIBE DEP’S DELIVERED COST OF NUCLEAR FUEL DURING 4

THE REVIEW PERIOD. 5

A. Staggering long-term contracts over time for each of the components of the nuclear 6

fuel cycle means DEP’s purchases within a given year consist of a blend of contract 7

prices negotiated at many different periods in the markets. DEP mitigates the impact 8

of market volatility on the portfolio of supply contracts by using a mixture of pricing 9

mechanisms. Consistent with its portfolio approach to contracting, DEP entered into 10

several long-term contracts during the review period. 11

DEP’s portfolio of diversified contract pricing yielded an average unit cost 12

of $38.33 per pound for uranium concentrates during the review period, representing 13

a decrease of 6% per pound from the prior review period. 14

A majority of DEP’s enrichment purchases during the review period were 15

delivered under long-term contracts negotiated prior to the review period. The 16

staggered portfolio approach has the effect of smoothing out DEP’s exposure to 17

price volatility. The average unit cost of DEP’s purchases of enrichment services 18

during the review period decreased 0.5% to $133.27 per Separative Work Unit. 19

Delivered costs for fabrication and conversion services have a limited impact 20

on the overall fuel expense rate given that the dollar amounts for these purchases 21

represent a substantially smaller percentage (15% and 5%, respectively, for the fuel 22

batches recently loaded into DEP’s reactors) of DEP’s total direct fuel cost relative 23

to uranium concentrates or enrichment, which are 43% and 37%, respectively. 24


Q. PLEASE DESCRIBE THE LATEST TRENDS IN NUCLEAR FUEL 1

MARKET CONDITIONS. 2

A. Prices in the uranium concentrate markets remain relatively low with the continued 3

lack of demand due to the March 2011 event at Fukushima. Industry consultants, 4

however, believe market prices need to increase from current levels in order to 5

provide the economic incentive for the exploration, mine construction, and 6

production necessary to support future industry uranium requirements. 7

Market prices for enrichment services have declined primarily due to 8

reduced demand and increased supplier inventories following the Fukushima event. 9

Additionally, the transition by enrichment suppliers from gaseous diffusion 10

technology to the more cost efficient gas centrifuge technology was a market driver. 11

Fabrication is not a service for which prices are published; however, industry 12

consultants expect fabrication prices will continue to generally trend upward. For 13

conversion services, market prices declined during the review period on relatively 14

low demand. 15

Q. WHAT CHANGES DO YOU SEE IN DEP’S NUCLEAR FUEL COST IN 16

THE BILLING PERIOD? 17

A. The Company anticipates a decrease in nuclear fuel costs on a cents per kilowatt 18

hour (“kWh”) basis through the next billing period. Because fuel is typically 19

expensed over two to three operating cycles (roughly three to six years), DEP’s 20

nuclear fuel expense in the upcoming billing period will be determined by the cost of 21

fuel assemblies loaded into the reactors during the review period, as well as prior 22

periods. The fuel residing in the reactors during the billing period will have been 23


obtained under historical contracts negotiated in various market conditions. Each of 1

these contracts contribute to a portion of the uranium, conversion, enrichment, and 2

fabrication costs reflected in the total fuel expense. 3

The average fuel expense is expected to increase from 0.624 cents per kWh 4

incurred in the review period, to approximately 0.704 cents per kWh in the billing 5

period. This change reflects the discharge of fuel with a lower cost basis from the 6

reactors and its replacement with fuel procured under new contracts negotiated in 7

higher markets. 8

Q. WHAT STEPS IS DEP TAKING TO PROVIDE STABILITY IN ITS 9

NUCLEAR FUEL COSTS AND TO MITIGATE PRICE INCREASES IN 10

THE VARIOUS COMPONENTS OF NUCLEAR FUEL? 11

A. As I discussed earlier and as described in Church Exhibit 2, for uranium 12

concentrates, conversion, and enrichment services, DEP relies extensively on 13

staggered long-term contracts to cover the largest portion of its forward 14

requirements. By staggering long-term contracts over time and incorporating a 15

range of pricing mechanisms, DEP’s purchases within a given year consist of a 16

blend of contract prices negotiated at many different periods in the markets, which 17

has the effect of smoothing out DEP’s exposure to price volatility. 18

Although costs of certain components of nuclear fuel are expected to 19

increase in future years, nuclear fuel costs on a cents per kWh basis will likely 20

continue to be a fraction of the cents per kWh cost of fossil fuel. Therefore, 21

customers will continue to benefit from DEP’s diverse generation mix and the strong 22

performance of its nuclear fleet through lower fuel costs than would otherwise result 23


absent the significant contribution of nuclear generation to meeting customers’ 1

demands. 2

Q. DOES THIS CONCLUDE YOUR PRE-FILED DIRECT TESTIMONY? 3

A. Yes, it does. 4

The Nuclear Fuel Cycle Uranium Mining and Milling

U3O8

Conversion to UF6

Natural UF6

Enrichment Fuel Fabrication

UO2 Fuel Rods

Light Water Power Reactors

Producers sell U3O8 to utilities and traders.

55 Gal. drums = 850 lbs U3O8

14 Ton cylinders = 8,200 kg UF6

Spent Fuel

Spent Fuel Storage at Reactors

Waste Management/ Reprocessing

Low Enriched UF6

Church E

xhibit 1

Church Exhibit 2

Duke Energy Progress Nuclear Fuel Procurement Practices The Company’s nuclear fuel procurement practices are summarized below. • Near and long-term consumption forecasts are computed based on factors such as: nuclear

system operational projections given fleet outage/maintenance schedules, adequate fuel cycle design margins to key safety licensing limitations, and economic tradeoffs between required volumes of uranium and enrichment necessary to produce the required volume of enriched uranium.

• Nuclear system inventory targets are determined and designed to provide: reliability, insulation from market volatility, and sensitivity to evolving market conditions. Inventories are monitored on an ongoing basis.

• On an ongoing basis, existing purchase commitments are compared with consumption and inventory requirements to ascertain additional needs.

• Qualified suppliers are invited to make proposals to satisfy additional or future contract needs.

• Contracts are awarded based on the most attractive evaluated offer, considering factors such as price, reliability, flexibility and supply source diversification/portfolio security of supply.

• For uranium concentrates, conversion and enrichment services, long term supply contracts are relied upon to fulfill the largest portion of forward requirements. By staggering long-term contracts over time, the Company’s purchases within a given year consist of a blend of contract prices negotiated at many different periods in the markets, which has the effect of smoothing out the Company’s exposure to price volatility. Due to the technical complexities of changing suppliers, fabrication services are generally sourced to a single domestic supplier on a plant-by-plant basis using multi-year contracts.

• Spot market opportunities are evaluated from time to time to supplement long-term contract supplies as appropriate based on comparison to other supply options.

• Delivered volumes of nuclear fuel products and services are monitored against contract commitments. The quality and volume of deliveries are confirmed by the delivery facility to which Duke Energy Progress has instructed delivery. Payments for such delivered volumes are made after Duke Energy Progress’ receipt of such delivery facility confirmations.


SOUTH CAROLINA

DOCKET NO. 2016-1-E

In the Matter of ) DIRECT TESTIMONY OF Annual Review of Base Rates ) T. PRESTON GILLESPIE, JR FOR for Fuel Costs for ) DUKE ENERGY PROGRESS, LLC Duke Energy Progress, LLC )

DIRECT TESTIMONY OF T. PRESTON GILLESPIE Page 2 DUKE ENERGY PROGRESS, INC. DOCKET NO. 2016-1-E


A. My name is T. Preston Gillespie, Jr. and my business address is 526 South Church 2



A. I am Senior Vice President of Nuclear Operations for Duke Energy Corporation 5

(“Duke Energy”) and have executive accountability for Duke Energy’s nuclear fleet, 6

including Duke Energy Progress, LLC’s (“DEP” or the “Company”) Brunswick 7

Nuclear Station (“Brunswick”) located just North of Southport, North Carolina, 8

Sharon Harris Nuclear Station (“Harris”) in New Hill, North Carolina, and Robinson 9

Nuclear Station (“Robinson”) near Hartsville, South Carolina.. 10

Q. WHAT ARE YOUR RESPONSIBILITIES AS SENIOR VICE PRESIDENT 11

OF NUCLEAR OPERATIONS? 12

A. As Senior Vice President of Nuclear Operations, I am responsible for providing 13

executive oversight for the safe and reliable operation of Duke Energy’s six 14

operating nuclear stations. 15

Q. PLEASE SUMMARIZE YOUR EDUCATIONAL BACKGROUND AND 16


A. I have a Bachelor’s degree in Mechanical Engineering from Clemson University. I 18

am a registered professional engineer in South Carolina, and held a senior operator 19

license from the U.S. Nuclear Regulatory Commission (“NRC”). I began my career 20

with Duke Energy Carolinas, LLC (formerly known as Duke Power Company) in 21

1986 as an assistant engineer at Oconee Nuclear Station (“Oconee”). Since that 22

time, I have held various roles of increasing responsibility in engineering, work 23


management, and operations, including operations shift manager, and nuclear 1

engineering manager in 2004 responsible for managing the nuclear and electrical 2

engineering activities at Oconee. I was named operations manager at Catawba 3

Nuclear Station in 2007, and in 2008 I became plant manager at Oconee, 4

transitioning to Site Vice President in September 2010. I became Senior Vice 5

President of Nuclear Operations responsible for Oconee and Robinson in March 6

2013, and assumed responsibility for the remaining nuclear facilities in September 7

2014. 8


PROCEEDING? 10

A. The purpose of my testimony is to describe and discuss the performance of 11

Brunswick, Harris, and Robinson for the period of March 1, 2015 through February 12

29, 2016 (the “review period”). 13

Q. YOUR TESTIMONY INCLUDES THREE EXHIBITS. WERE THESE 14

EXHIBITS PREPARED BY YOU OR AT YOUR DIRECTION AND UNDER 15

YOUR SUPERVISION? 16

A. Yes. These exhibits were prepared at my direction and under my supervision. 17

Q. PLEASE PROVIDE A DESCRIPTION OF THE EXHIBITS. 18

A. The exhibits and descriptions are as follows: 19

Gillespie Exhibit 1 - Calculation of the nuclear capacity factor for the 20

review period pursuant to S.C. Code § 58-27-865 21

Gillespie Exhibit 2 - Nuclear outage data for the review period 22


Gillespie Exhibit 3 - Nuclear outage data through the billing period 1 1

Q. PLEASE DESCRIBE DEP’S NUCLEAR GENERATION PORTFOLIO. 2

A. The Company’s nuclear generation portfolio consists of approximately 3,539 3

megawatts (“MWs”) of generating capacity, made up as follows: 4

Brunswick - 1,870 MWs 5

Harris - 928 MWs 6

Robinson - 741 MWs 7

Q. PLEASE PROVIDE A GENERAL DESCRIPTION OF DEP’S NUCLEAR 8

GENERATION ASSETS. 9

A. The Company’s nuclear fleet consists of three generating stations and a total of four 10

units. Brunswick is a boiling water reactor facility with two units and was the first 11

nuclear plant built in North Carolina. Unit 2 began commercial operation in 1975, 12

followed by Unit 1 in 1977. The operating licenses for Brunswick were renewed in 13

2006 by the NRC, extending operations up to 2036 and 2034 for Units 1 and 2, 14

respectively. Harris is a single unit pressurized water reactor that began commercial 15

operation in 1987. The NRC issued a renewed license for Harris in 2008, extending 16

operation up to 2046. Robinson is also a single unit pressurized water reactor that 17

began commercial operation in 1971. The license renewal for Robinson Unit 2 was 18

issued by the NRC in 2004, extending operation up to 2030. 19

Q. WERE THERE ANY CAPACITY CHANGES WITHIN DEP’S NUCLEAR 20

PORTFOLIO DURING THE REVIEW PERIOD? 21

A. Yes. On July 31, 2015, DEP finalized the purchase of ownership for portions of 22

Brunswick Units 1 and 2, and Harris Unit 1 from North Carolina Eastern Municipal 23 1 This data is provided in confidential and publicly redacted versions for security purposes.


Power Agency (“NCEMPA”). This purchase, brought DEP’s ownership to 100% of 1

these units and added 493 MWs of reliable, efficient, cost effective, and greenhouse 2

gas emission-free base load generation to DEP’s nuclear portfolio. 3

Q. WHAT ARE DEP’S OBJECTIVES IN THE OPERATION OF ITS 4

NUCLEAR GENERATION ASSETS? 5

A. The primary objective of DEP’s nuclear generation department is to safely provide 6

reliable and cost-effective electricity to DEP’s Carolinas customers. The Company 7

achieves this objective by focusing on a number of key areas. Operations personnel 8

and other station employees are well-trained and execute their responsibilities to the 9

highest standards in accordance with detailed procedures. The Company maintains 10

station equipment and systems reliably, and ensures timely implementation of work 11

plans and projects that enhance the performance of systems, equipment, and 12

personnel. Station refueling and maintenance outages are conducted through the 13

execution of well-planned, well-executed, and high quality work activities, which 14

effectively ready the plant for operation until the next planned outage. 15

Q. PLEASE DISCUSS THE PERFORMANCE OF DEP’S NUCLEAR FLEET 16

DURING THE REVIEW PERIOD. 17

A. The Company operated its nuclear stations in a reasonable and prudent manner 18

during the review period, providing 44% of the total power generated by DEP. The 19

four nuclear units operated at an actual system average capacity factor of 91.2%. 20

For continuous operating days, Brunswick set a record for the longest dual unit 21

continuous run at 314 days and 22 hours. Harris also set a record for all months in 22

March 2015 producing net generation of 716,758 MW hours. Additionally, 23


Robinson participated in the Southern Exposure emergency response exercise which 1

was the largest integrated exercise ever conducted within the nuclear industry. This 2

exercise allowed interaction between government agencies that will advance 3

national readiness in the event of an accident at a commercial nuclear power plant. 4

As shown on Gillespie Exhibit 1, DEP achieved a net nuclear capacity 5

factor, excluding reasonable outage time, of 101.84% for the review period. This 6

capacity factor is above the 92.5% set forth in S.C. Code § 58-27-865(F), which 7

states in pertinent part: 8

There shall be a rebuttable presumption that an electrical utility made 9 every reasonable effort to minimize cost associated with the 10 operation of its nuclear generation facility or system, as applicable, if 11 the utility achieved a net capacity factor of ninety-two and one-half 12 percent or higher during the period under review. The calculation of 13 the net capacity factor shall exclude reasonable outage time 14 associated with reasonable refueling, reasonable maintenance, 15 reasonable repair, and reasonable equipment replacement outages; 16 the reasonable reduced power generation experienced by nuclear 17 units as they approach a refueling outage; the reasonable reduced 18 power generation experienced by nuclear units associated with 19 bringing a unit back to full power after an outage.... 20

21

The performance results discussed above support DEP’s continued 22

commitment for achieving high performance without compromising safety and 23

reliability. 24

Q. WHAT IMPACTS A UNIT’S AVAILABILITY AND WHAT IS DEP’S 25

PHILOSOPHY FOR SCHEDULING REFUELING AND MAINTENANCE 26

OUTAGES? 27

A. In general, refueling requirements, maintenance requirements, prudent maintenance 28

practices, and NRC operating requirements impact the availability of DEP’s nuclear 29


system. Prior to a planned outage, DEP develops a detailed schedule for the outage 1

and for major tasks to be performed including sub-schedules for particular activities. 2

The Company’s scheduling philosophy is to plan for a best possible outcome 3

for each outage activity within the outage plan. For example, if the “best ever” time 4

a particular outage task was performed is 10 days, then 10 days or less becomes the 5

goal for that task in each subsequent outage. Those individual goals are 6

incorporated into an overall outage schedule. The Company aggressively works to 7

meet, and measures itself against, that schedule. Further, to minimize potential 8

impacts to outage schedules, “discovery activities” (walk-downs, inspections, etc.) 9

are scheduled at the earliest opportunities so that any maintenance or repairs 10

identified through those activities can be promptly incorporated into the outage plan. 11

Those discovery activities also have pre-planned contingency actions to ensure that, 12

when incorporated into the schedule, the activities required for appropriate repair 13

can be performed as efficiently as possible. 14

As noted, the Company uses the schedule for measuring outage planning and 15

execution, and driving continuous improvement efforts. However, in order to 16

provide reasonable, rather than best ever, total outage time for planning purposes, 17

particularly with the dispatch and system operating center functions, DEP also 18

develops an allocation of outage time which incorporates reasonable schedule losses. 19

The development of each outage allocation is dependent on maintenance and repair 20

activities included in the outage, as well as major projects to be implemented during 21

the outage. Both schedule and allocation are set aggressively to drive continuous 22

improvement in outage planning and execution. 23


Q. HOW DOES DEP HANDLE OUTAGE EXTENSIONS AND FORCED 1

OUTAGES? 2

A. When an outage extension becomes necessary, DEP believes that work completed in 3

the extension results in longer continuous run times and fewer forced outages, 4

thereby reducing fuel costs in the long run. Therefore, if an unanticipated issue that 5

has the potential to become an on-line reliability issue is discovered while a unit is 6

off-line for a scheduled outage and repair cannot be completed within the planned 7

work window, the outage is usually extended to perform necessary maintenance or 8

repairs prior to returning the unit to service. In the event that a unit is forced off-9

line, every effort is made to safely perform the repair and return the unit to service as 10

quickly as possible. 11

Q. DOES DEP PERFORM POST-OUTAGE CRITIQUES AND CAUSE 12

ANALYSES FOR INTERNAL IMPROVEMENT EFFORTS? 13

A. Yes. The nuclear industry recognizes that constant focus on raising standards and 14

excellence in operations results in improved nuclear safety and reliability. As such, 15

DEP applies self-critical analysis to each outage and, using the benefit of hindsight, 16

identifies every potential cause of an outage delay or event resulting in a forced or 17

extended outage, and applies lessons learned to drive continuous improvement. The 18

Company also evaluates the performance of each function and discipline involved in 19

outage planning and execution from the perspective of identifying areas in which it 20

can utilize self-critical observation for improvement efforts. Given this focus on 21

identifying opportunities for improvement, these critiques and cause analyses do not 22

document the broader context of the outage extension or event, or account for the 23


Company’s attempt to achieve “best ever” outage time, and thus rarely reflect 1

strengths and successes. 2

Q. WHAT OUTAGES WERE REQUIRED FOR REFUELING AND 3

MAINTENANCE AT DEP’S NUCLEAR FACILITIES DURING THE 4

REVIEW PERIOD? 5

A. There were three refueling and maintenance outages during the review period, all of 6

which occurred during the spring of 2015. The initial outage occurred at Brunswick 7

Unit 2. In addition to refueling and maintenance activities, major work completed 8

during the outage included reliability improvements to the emergency diesel 9

generator with governor replacement, and installations of an automatic voltage 10

regulator and jet air assist system. The 2E and 2F transformers were replaced and 11

Fukushima modifications completed along with completion of a 10 year integrated 12

leak rate test. There were also installations of an on-line Noble Chemistry System 13

and Electrochemical probe. Emergent work required during installation and testing 14

of the voltage regulator and governor work were leading drivers for an outage 15

extension of just under 8 days. In total, DEP completed 16,492 activities within this 16

outage. Also of note, DEP delayed the start of this outage by one week to 17

accommodate weather conditions and the resulting demand on the electric grid. This 18

delay provided net savings of $8.6 million in fuel and fuel-related costs within the 19

review period. 20

The Harris outage followed Brunswick, and, in addition to refueling and 21

maintenance activities, major work efforts included replacing eight large 22

transformers, four of which were safety related. Fukushima modifications, molded 23


case circuit breakers, and reactor coolant pump seals were also installed along with 1

replacement of the pressurizer manway gasket. Upgrades were completed for the 2

service water system and protective relaying for auxiliary and startup transformers. 3

A 10 year internal inspection for the emergency diesel fuel storage and day tanks 4

was performed along with a 100% steam generator Eddy current test and inspection. 5

Just over 9 additional outage days were required for reactor head volumetric 6

inspection and repair work along with emergent replacement of the ‘A’ emergency 7

service water pump. In total, DEP completed 16,258 activities within this outage. 8

The Robinson outage followed Harris and also involved improvements to 9

plant reliability beyond the refueling and maintenance activities. Replacement 10

efforts included reactor coolant pump seal and ‘C’ motor, vessel hold down spring 11

and incore instrument thimbles, the pressurizer manway gasket, and safety injection 12

system cold leg isolations. In addition, there were 300 reactor protection and 13

safeguards system relay replacements, and implementation of Fukushima 14

modifications. Fuel cleaning was performed to reduce risk of abnormal power 15

distribution in the core during the next fuel cycle, which is an increased designed 16

cycle length, and internal inspections were completed for the motor control center 17

and North service water header piping. A 15 day extension was required due to 18

emergent work efforts with the main feedwater tee replacement and residual reheat 19

removal piping modification. In total, DEP completed 10,021 activities within the 20

outage. 21


A. Yes, it does. 23

Gillespie Exhibit 1

1 Nuclear System Actual Net Generation During Review Period 28,209,337 MWH

2 Total Number of Hours during Review Period 8,784

3 Nuclear System MDC during Review Period 3,539 MW

4 Reasonable Nuclear System Reductions 3,387,363 MWH

5 Nuclear System Capacity Factor ((L1/(L2a*L3a)-L4)*100 101.84 %

DUKE ENERGY PROGESS, LLCSOUTH CAROLINA ANNUAL REVIEW OF BASE RATES FOR FUEL COSTS

NUCLEAR CAPACITY FACTOR PURSUANT TO S.C. CODE ANN. § 58-27-865(F)REVIEW PERIOD OF MARCH 2015 THROUGH FEBRUARY 2016

Gillespie Exhibit 2

Nuclear outages lasting one week or more during the Review Period

Station/Unit Date of Outage Explanation of Outage

Brunswick 1 2/7/2016-2/14/2016 Maintenance Outage

Brunswick 2 3/1/20151-4/5/2015 Scheduled Refueling - EOC 21

Harris 1 4/2/2015-5/15/2015 Scheduled Refueling - EOC 19

Robinson 2 5/12/2015-6/25/2015 Scheduled Refueling - EOC 29

Robinson 2 11/17/2015-11/28/2015 Maintenance Outage

1 Outage began in prior review period.


NUCLEAR OUTAGE DATA FOR REVIEW PERIOD OFMARCH 2015 THROUGH FEBRUARY 2016

PUBLICGillespie Exhibit 3

Scheduled nuclear outages lasting one week or more through the Billing Period

Station/Unit Date of Outage1 Explanation of Outage

1 This exhibit represents DEP’s current plan, which is subject to change based on fluctuations in operational and maintenance requirements.

REDACTED


NUCLEAR OUTAGE SCHEDULE THROUGH BILLING PERIOD JULY 2015 THROUGH JUNE 2016

BEFORE THE

PUBLIC SERVICE COMMISSION OF SOUTH CAROLINA

DOCKET NO. 2016-1-E

In the Matter of ) Annual Review of Base Rates ) DIRECT TESTIMONY OF for Fuel Costs for ) SWATI V. DAJI FOR Duke Energy Progress, LLC ) DUKE ENERGY PROGRESS, LLC

DIRECT TESTIMONY OF SWATI V. DAJI Page 2 DUKE ENERGY PROGRESS, LLC DOCKET NO. 2016-1-E


A. My name is Swati V. Daji. My business address is 526 South Church Street, 2

Charlotte, North Carolina 28202. 3


A. I am Senior Vice President, Fuels & Systems Optimization for Duke Energy 5

Corporation (“Duke Energy”). In that capacity, I am responsible for the purchase 6

and delivery of coal, natural gas, and fuel oil to Duke Energy’s regulated generation 7

fleet, including Duke Energy Carolinas, LLC (“Duke Energy Carolinas,” “DEC,” or 8

the “Company”) and Duke Energy Progress, LLC (“DEP”) (collectively, the 9

“Utilities,” or the “Companies”), as well as the power trading and dispatch function 10

related to power, natural gas, and emissions. I am also responsible for procuring and 11

transporting all reagents. In addition, I manage the fleet’s system optimization, 12

energy supply analytics, and contract administration functions. 13

Q. PLEASE BRIEFLY SUMMARIZE YOUR EDUCATIONAL AND 14


A. I have a Bachelor of Science degree in Accounting from the University of Bombay 16

and an MBA in finance from Clemson University. I joined the company in 1991 as 17

a financial analyst for Duke Power. From 1998 to 2004, I held a variety of 18

management positions with Duke Energy North America, including Vice President 19

of Asset Planning, Valuation, and Analysis; Managing Director of Finance 20

Valuation and Treasury Operations; and Managing Director of Budgeting and 21

Forecasting. Between 2004 and 2007, I served as General Manager in both the 22

Treasury and Corporate Risk Management groups for Duke Energy. From October 23


2009 to August 2014, I served as Vice President, Global Risk Management and 1

Insurance, and Chief Risk Officer. I assumed my current position in August 2014. 2


PROCEEDING? 4

A. The purpose of my testimony is to describe DEP’s fossil fuel purchasing practices, 5

provide fossil fuel costs for the period March 1, 2015 through February 29, 2016 6

(“review period”) versus March 1, 2014 through February 28, 2015 (“prior review 7

period”), and describe changes forthcoming for the period July 1, 2016 through 8

June 30, 2017 (“billing period”). I also provide an update on the status of 9

guaranteed merger fuel-related savings that – pursuant to the merger agreement 10

between Duke Energy and Progress Energy, Inc. (“Merger”) – Duke Energy is 11

delivering to its North Carolina and South Carolina customers. 12

Q. PLEASE PROVIDE A DESCRIPTION OF THE EXHIBITS TO YOUR 13

TESTIMONY. 14

A. Daji Exhibit 1 summarizes the Company’s Fossil Fuel Procurement Practices, and 15

Daji Exhibit 2 summarizes total monthly natural gas purchases and monthly contract 16

and spot coal purchases during the review period and the prior review period. 17

Q. WERE THESE EXHIBITS PREPARED BY YOU OR AT YOUR 18

DIRECTION? 19

A. Yes, they were prepared at my direction. 20


Q. PLEASE PROVIDE A SUMMARY OF DEP’S FOSSIL FUEL 1

PROCUREMENT PRACTICES. 2

A. A summary of the Company’s fossil fuel procurement practices is set out in Daji 3

Exhibit 1. 4

Q. HOW DOES THE COMPANY OPERATE ITS PORTFOLIO OF 5

GENERATION ASSETS TO RELIABLY AND ECONOMICALLY SERVE 6

ITS CUSTOMERS? 7

A. Both DEP and DEC utilize the same process to ensure that the assets of the 8

Companies are reliably and economically available to serve their respective 9

customers. To that end, both companies consider factors that include, but are not 10

limited to, the latest forecasted fuel prices, transportation rates, planned maintenance 11

and refueling outages at the generating units, estimated forced outages at generating 12

units based on historical trends, generating unit performance parameters, and 13

expected market conditions associated with power purchases and off-system sales 14

opportunities in order to determine the most economic and reliable means of serving 15

their customers. 16

Q. PLEASE DESCRIBE THE COMPANY’S DELIVERED COST OF COAL 17

AND NATURAL GAS DURING THE REVIEW PERIOD. 18

A. The Company’s average delivered cost of coal per ton for the review period was 19

$81.63 per ton, compared to $89.58 per ton in the prior review period, representing a 20

decrease of 9%. This includes an average transportation cost of $24.18 per ton in the 21

review period, compared to $29.92 per ton in the prior review period, representing a 22

decrease of approximately 19%. The Company’s average price of gas purchased for 23


the review period was $4.30 per Million British Thermal Units (“MMBtu”), 1

compared to $6.13 per MMBtu in the prior review period, representing a decrease of 2

30%. 3

The decrease in coal transportation costs reflects the incorporation of 4

additional lower cost barge movements, where feasible, and reduced rail 5

transportation costs due to lower fuel surcharges caused by the significant drop in 6

fuel oil prices. The cost of gas includes gas supply, transportation, storage and 7

financial hedging, and the decrease in gas costs is primarily reflective of the 8

historically low price of gas during the review period. 9

DEP’s coal burn for the review period was 5.1 million tons, compared to a 10

coal burn of 7.1 million tons in the prior review period, representing a decline of 11

28%. Additionally, the 5.1 million tons burned in the review period represents a 16% 12

decline from the 6.1 million tons originally projected to be burned in the prospective 13

period of the currently billed rate. 14

The Company’s natural gas burn for the review period was 172 MMBtu 15

compared to a gas burn of 137 MMBtu in the prior review period, representing an 16

increase of 26%. Additionally, the 172 MMBtu burned in the review period 17

represented a 30% increase from the 132 MMBtu projected to be burned in the 18

prospective period of the currently billed rate. 19

The decline in coal burns, and the increase in gas burns, was primarily 20

attributable to declining gas prices combined with milder than forecasted weather 21

during the 2015-2016 winter season. 22

Q. PLEASE DESCRIBE THE LATEST TRENDS IN COAL AND NATURAL 23


GAS MARKET CONDITIONS. 1

A. Coal markets continue to be in a state of flux due to a number of factors, including: 2

(1) proposed and imposed U.S. Environmental Protection Agency (“EPA”) 3

regulations for power plants that have resulted in utilities retiring or modifying 4

plants, which lowers total domestic steam coal demand, and can result in plants 5

shifting coal sources to different basins; (2) abundant natural gas supply and storage 6

resulting in lower natural gas prices combined with installation of new combined 7

cycle (“CC”) generation by utilities, especially in the Southeast, which has also 8

lowered overall coal demand; (3) continued softening demand in global markets for 9

both steam and metallurgical coal; (4) increasingly stringent safety regulations for 10

mining operations, which result in higher costs and lower productivity; and (5) the 11

deterioration of the financial health of coal suppliers due to reduced demand and 12

market pricing in combination with increasing production costs. 13

At the same time, the nation’s natural gas supply has grown significantly and 14

has outstripped demand. Over the longer term planning horizon, overall growth in 15

gas supply is expected to continue. Currently observable forward market prices are 16

at historically low price levels as producers continue to look for efficiencies to 17

further enhance economics and lower production costs. In addition to the increase in 18

natural gas supply, new pipeline infrastructure continues to be added to provide for 19

opportunities to move the growing supply to various markets. 20


Q. WHAT ARE THE PROJECTED COAL AND NATURAL GAS 1

CONSUMPTIONS AND COSTS FOR THE BILLING PERIOD? 2

A. DEP’s current coal burn projection for the billing period is 5.4 million tons 3

compared to 5.1 million tons consumed during the review period. DEP’s billing 4

period projections for coal generation may be impacted due to changes from, but not 5

limited to, the following factors: delivered natural gas prices versus the average 6

delivered cost of coal, volatile power prices, and electric demand. Inventory levels 7

were above target at the end of the review period, and future actual inventory levels 8

may be above target levels at the end of 2016 as well. Combining coal and 9

transportation costs, DEP projects average delivered coal costs of approximately 10

$76.62 per ton for the billing period compared to $81.63 per ton in the review 11

period. This cost, however, is subject to change based on, but not limited to, the 12

following factors: (1) exposure to market prices and their impact on open coal 13

positions; (2) the amount of non-Central Appalachian coal DEP is able to consume; 14

(3) performance of contract deliveries by suppliers and railroads which may not 15

occur despite DEP’s strong contract compliance monitoring process; (4) changes in 16

transportation rates; and (5) potential additional costs associated with suppliers’ 17

compliance with legal and statutory changes, the effects of which can be passed on 18

through coal contracts. 19

DEP’s current natural gas burn projection for the billing period is 20

approximately 145 MMBtu, which is a decrease from the 172 MMBtu consumed 21

during the review period. The current average forward Henry Hub price for the 22

billing period is $2.66 per MMBtu compared to $2.48 per MMBtu in the review 23


period, resulting in the Company’s decreased natural gas consumption projection. 1

Although the price of natural gas is currently projected to increase slightly, gas 2

markets remain in a historically low price environment which will affect actual 3

burns. 4

Q. WHAT STEPS IS DEP TAKING TO MANAGE PORTFOLIO FUEL 5

COSTS? 6

A. The Company continues to maintain a comprehensive coal and natural gas 7

procurement strategy that has proven successful over the years in limiting average 8

annual fuel price increases and maintaining average fuel costs at or below those seen 9

in the marketplace. Aspects of this procurement strategy include having an 10

appropriate mix of contract and spot purchases for coal, staggering coal contract 11

expirations which thereby limit exposure to market price changes, diversifying coal 12

sourcing as economics warrant, and pursuing coal contract extension options that 13

provide flexibility to extend terms within a particular price band. The Company 14

expects to address any spot and long-term coal requirements throughout this year 15

with any potential competitively bid purchases, if made, taking into account 16

projected coal burns, as well as coal inventory levels. 17

The Company has implemented natural gas procurement practices that 18

include periodic Request for Proposals (“RFPs”) and short-term market engagement 19

activities to procure and actively manage a reliable, flexible, diverse, and 20

competitively priced natural gas supply that supports DEP’s CC and combustion 21

turbine (“CT”) facilities. The Company procures long-term firm transportation to 22

support its natural gas needs at its generating facilities. In addition, as needed, DEP 23


may procure shorter-term firm pipeline capacity through the capacity release market, 1

as well as delivered market supply options that provide the needed natural gas 2

supply to its generating facilities. 3

Through the Asset Management and Delivered Supply Agreement (“AMA”) 4

between the Utilities, which was implemented on January 1, 2013, DEC serves as 5

the designated Asset Manager that procures and manages the combined gas supply 6

needs for the Utilities, and performs the necessary scheduling and balancing on the 7

pipelines. DEP has a storage agreement which was released to DEC as part of the 8

AMA. As the Asset Manager, DEC procures all the needed supply for the combined 9

Carolinas gas needs, and as part of the AMA, has access to the released storage 10

agreement. On any given day, DEC may utilize the storage to balance and support 11

the Carolinas gas needs. Lastly, DEP continues to maintain a short-term natural gas 12

hedging plan to manage fuel cost price risk and dampen price volatility for 13

customers via a structured execution approach. The strategy incorporates a “dollar-14

cost averaging” approach of hedging that financially “locks-in” natural gas prices at 15

a fixed price over time for a percentage of forecasted natural gas burns. DEP will 16

continue to monitor and make adjustments as necessary to its natural gas hedging 17

program. 18

Q. PLEASE PROVIDE AN UPDATE ON THE STATUS OF THE 19

GUARANTEED MERGER FUEL-RELATED SAVINGS THE COMPANY 20

HAS ACHIEVED THUS FAR FOR ITS RETAIL CUSTOMERS. 21

A. Through February 2016, the combined merger savings from the Utilities’ Joint 22

Dispatch Agreement and fuel procurement activities totaled $644 million, of which 23


DEP’s South Carolina share was $28 million. The Utilities’ customers allocated 1

their share of the combined savings based upon the resource ratios of the combined 2

company. This resource ratio is 39% for DEP and 61% for DEC through February 3

2016. 4


A. Yes, it does. 6

DAJI EXHIBIT 1

1

Duke Energy Progress, Inc. Fossil Fuel Procurement Practices Coal

• Near and long-term consumption forecasts are computed based on factors such as: load projections, fleet maintenance and availability schedules, coal quality and cost, environmental permit and emissions considerations, wholesale energy imports and exports.

• Station and system inventory targets are determined and designed to provide: reliability, insulation from short-term market volatility, and sensitivity to evolving coal production and transportation conditions. Inventories are monitored continuously.

• On a continuous basis, existing purchase commitments are compared with consumption and inventory requirements to ascertain additional needs.

• All qualified suppliers are invited to make proposals to satisfy any additional or future contract needs.

• Contracts are awarded based on the lowest evaluated offer, considering factors such as price, quality, transportation, reliability and flexibility.

• Spot market solicitations are conducted on an on-going basis to supplement contract purchases.

• Delivered coal volume and quality are monitored against contract commitments. Coal and freight payments are calculated based on certified scale weights and coal quality analysis meeting ASTM standards. During the review period the Company utilized both destination and/or origin weights and analysis.

Gas

• Near and long-term consumption forecasts are computed based on factors such as load projections, commodity and emission prices, and fleet maintenance and availability schedules.

• Short-term and Long-term Periodic Requests for Proposals and informal market solicitations will be conducted to potential suppliers to procure a cost competitive, secure and reliable natural gas supply over time to meet forecasted gas usage.

• Short-term and spot purchases are conducted on an on-going basis to supplement term natural gas supply.

• On a continuous basis, existing purchases are compared to forecasted gas usage to ascertain any additional needs.

Fuel Oil • No. 2 diesel is burned primarily for initiation of coal combustion (light-off at

steam plants) and in combustion turbines (peaking assets). • All diesel fuel is moved via pipeline to applicable terminals where it is then

loaded on trucks for delivery into the Company’s storage tanks. Because oil usage is highly variable, the Company relies on a combination of inventory and reliable suppliers who are responsive and can access multiple terminals. Diesel is replaced on an “as needed basis” as called for by station personnel with guidance from fuel procurement staff.

DAJI EXHIBIT 1

2

• Formal solicitation for supply is conducted as needed with an emphasis on maintaining a network of reliable suppliers at a competitive market price in the region of our generating assets.

Daji Exhibit 2Page 1 of 2

Line No. Month

Contract(Tons)

Net SpotPurchase and Sales (Tons)

Total(Tons)

1 March 2015 551,069 12,420 563,4892 April 538,920 0 538,9203 May 499,049 0 499,0494 June 388,031 0 388,0315 July 497,293 0 497,2936 August 531,402 61,083 592,4857 September 578,888 62,257 641,1458 October 556,881 142,145 699,0269 November 335,613 81,620 417,233

10 December 213,630 58,536 272,16611 January 2016 135,132 104,742 239,87412 February 255,566 46,882 302,448

13 Total (Sum L1:L12) 5,081,474 569,685 5,651,159

Line No. MonthContract(Tons)

Net Spot Purchase and Sales (Tons)

Total(Tons)

14 March 2014 510,538 107,296 617,83415 April 486,338 213,283 699,62116 May 538,326 255,466 793,79217 June 448,698 237,887 686,58518 July 508,318 179,100 687,41819 August 538,614 119,962 658,57620 September 480,378 23,705 504,08321 October 455,903 24,978 480,88122 November 377,672 318 377,99023 December 422,545 145,909 568,45424 January 2015 540,700 62,223 602,92325 February 399,242 0 399,242

26 Total (Sum L14:L25) 5,707,272 1,370,127 7,077,399

DUKE ENERGY PROGRESSSummary of Coal Purchases

Twelve Months Ended February 2016 & 2015Tons

Daji Exhibit 2Page 2 of 2

Line No. Month MBTUs

1 March 2015 13,803,942 2 April 12,523,884 3 May 14,416,738 4 June 15,284,136 5 July 15,111,611 6 August 14,768,643 7 September 14,633,497 8 October 10,978,923 9 November 15,252,462

10 December 14,132,589 11 January 2016 15,130,511 12 February 16,389,046

13 Total (Sum L1:L12) 172,425,982

LineNo. Month MBTUs

14 March 2014 10,374,808 15 April 10,077,319 16 May 8,925,276 17 June 12,630,905 18 July 12,928,009 19 August 12,839,579 20 September 11,504,612 21 October 6,607,550 22 November 10,572,085 23 December 13,239,584 24 January 2015 14,294,303 25 February 13,070,342

26 Total (Sum L14:L25) 137,064,372

DUKE ENERGY PROGRESSSummary of Gas Purchases

Twelve Months Ended February 2016 & 2015MBTUs


SOUTH CAROLINA

DOCKET NO. 2016-1-E

In the Matter of Annual Review of Base Rates for Fuel Costs for Duke Energy Progress, LLC

) ) ) )

DIRECT TESTIMONY OF KIMBERLY D. MCGEE FOR DUKE

ENERGY PROGRESS, LLC

DIRECT TESTIMONY OF KIMBERLY D. MCGEE Page 2 DUKE ENERGY PROGRESS, LLC DOCKET NO. 2016-1-E


A. My name is Kimberly D. McGee, and my business address is 550 South Tryon 2



A. I am a Rates Manager supporting both Duke Energy Progress, LLC (“DEP” or the 5

“Company”) and Duke Energy Carolinas, LLC (“DEC”) (collectively, the 6

“Companies”). 7

Q. PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND AND 8


A. I graduated from the University of North Carolina at Charlotte with a Bachelor of 10

Science degree in Accountancy. I am a certified public accountant licensed in the 11

State of North Carolina. I began my career in 1989 with Deloitte and Touche, 12

LLP as a staff auditor. In 1992, I began working with DEC (formerly known as 13

Duke Power Company) as a staff accountant and have held a variety of positions 14

in the finance organization. From 1997 until 2009, I worked for Wachovia Bank 15

(now known as Wells Fargo) in a variety of finance and regulatory positions. I 16

rejoined DEC in January 2009 as a Lead Accountant in Financial Reporting. I 17

joined the Rates Department in 2011 as Manager, Rates and Regulatory Filings. 18

Q. HAVE YOU TESTIFIED BEFORE THIS COMMISSION IN ANY PRIOR 19

PROCEEDINGS? 20

A. Yes. I testified before the Public Service Commission of South Carolina 21

(“PSCSC” or “Commission”) in DEP’s 2015 fuel and environmental cost 22

recovery proceeding in Docket No. 2015-1-E. 23


Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? 1

A. The purpose of my testimony is to provide DEP’s actual fuel, Public Utility 2

Regulatory Policies Act of 1978 (“PURPA”) capacity, environmental, and 3

Distributed Energy Resource Program (“DERP”) cost data for March 1, 2015 4

through February 29, 2016 (the “review period”), the projected fuel, PURPA 5

capacity, environmental and DERP cost information for March 1, 2016 through 6

June 30, 2016 (the “forecast period”), and DEP’s proposed fuel factors by 7

customer class for July 1, 2016 through June 30, 2017 (the “billing period”). I 8

will provide fifteen exhibits to support my testimony. 9

Q. WERE ALL OF YOUR EXHIBITS PREPARED BY YOU OR AT YOUR 10

DIRECTION? 11

A. Yes. 12

Q. WHAT IS THE SOURCE OF THE ACTUAL INFORMATION AND DATA 13

FOR THE REVIEW PERIOD? 14

A. Actual test period kilowatt hour (“kWh”) generation, kW and kWh sales, fuel-15

related revenues, fuel-related expenses, and DERP revenues and expenses were 16

taken from DEP’s books and records. These books, records, and reports of DEP 17

are subject to review by the appropriate regulatory agencies in the three 18

jurisdictions that regulate DEP’s electric rates. 19

In addition, independent auditors perform an annual audit to provide 20

assurance that, in all material respects, internal accounting controls are operating 21

effectively and DEP’s financial statements are accurate. 22


Q. DOES DEP PURCHASE POWER AND HOW ARE THESE COSTS 1

RECORDED? 2

A. Yes. The Company continuously evaluates purchasing power if it can be reliably 3

procured and delivered at a price that is less than the variable cost of DEP’s 4

generation. In accordance with S.C. Code Ann. § 58-27-865(A), DEP recovers 5

from its South Carolina retail customers an amount that is the lower of the 6

purchase price or DEP’s avoided variable cost for generating an equivalent 7

amount of power for its economy purchases. The Company also engages in 8

economy purchases (and economy sales) with DEC as a result of the Joint 9

Dispatch Agreement (“JDA”) described in Company witness Daji’s testimony. 10

According to her testimony, under the joint dispatch process, the energy cost 11

incurred by DEP and DEC to serve their respective native loads is equal to the 12

stand alone costs they would have incurred but for the joint dispatch arrangement, 13

less each utility’s share of the joint dispatch savings. 14

The Company also purchases power from certain suppliers that are treated 15

as firm generation capacity purchases. In accordance with S.C. Code Ann. § 58-16

27-865(A)(2)(a), all amounts paid to these suppliers are recorded as recoverable 17

fuel costs with the exception of capacity charges. 18

Finally, the Company routinely purchases power from qualifying facilities 19

under PURPA. According to revisions in Act 236 that are set forth in S.C. Code 20

Ann. § 58-27-865(A), the avoided cost payments for such purchases are included 21

in fuel recoverable from South Carolina retail customers. In addition, Act 236 22


also made revisions to § 58-27-865(A)(1) relating to the allocation of any capacity 1

costs that are recovered under the fuel factor. 2

Q. PLEASE EXPLAIN MCGEE EXHIBIT NO. 1. 3

A. McGee Exhibit No. 1 is a summary of DEP’s recommended fuel rate components 4

for the billing period. The components include amounts for (1) PURPA 5

purchased power avoided capacity costs, (2) DERP avoided costs, (3) variable 6

environmental costs, (4) DERP incremental costs, and (5) all other fuel costs, 7

which are referred to as “base” fuel costs. McGee Exhibit No. 1 presents 8

proposed fuel rates for residential customers including an amount added to 9

account for the 5% discount provided to residential customers under DEP’s SC 10

Residential Service Energy Conservation Discount Rider RECD-2C. As shown 11

on McGee Exhibit No. 6, this discount impacts approximately 15% of DEP’s 12

South Carolina residential sales. These fuel rate components are supported by 13

McGee Exhibit Nos. 2 through 14 and individually discussed further in my 14

testimony. The following table shows the rates and monthly charges proposed by 15

the Company in this proceeding as reflected in McGee Exhibit No. 1. As 16

reflected in the table, the DERP incremental cost component is computed as a 17

dollar amount per customer account since these amounts are subject to per-18

account cost caps established by Act 236. All other fuel components are 19

computed as a rate per kWh or rate per kW depending on the particular customer 20

class. 21


1

2 3

Pursuant to Act 236, the PURPA capacity components and the 4

DERP avoided cost components are shown separately. Act 236 requires that 5

avoided costs of distributed energy resource programs be allocated and recovered 6

among customer classes using the same method that is used to allocate and 7

recover variable environmental costs. 8

In addition, McGee Exhibit No. 1 includes the projected per-account 9

charge per month of $0.36, $0.70 and $62.58, excluding Gross Receipts Tax 10

(“GRT”), for South Carolina residential, general service, and industrial customers, 11

for the recovery of 100% of the DERP incremental costs, in accordance with S.C. 12

Line No. Fuel Rate Component Residential

General Service

(non demand) Lighting

General Service

(demand)

Base Fuel Costs - McGee Exhibits 2 and 3 1 Base Fuel Cost Component Under/ (Over) Collection at June 2015 (0.020) (0.020) (0.020) (0.020)2 Base Fuel Cost Component Projected Billing Period 2.250 2.250 2.250 2.2503 Total Base Fuel Cost Component 2.230 2.230 2.230 2.2304 Total Base Fuel Cost Component Increased for RECD 2.247

PURPA Purchased Power Capacity Costs - McGee Exhibits 7 and 8 Cents / kW5 PURPA Purchased Power Capacity Under / (Over) Collection at June 2015 0.050 0.023 0.000 8 6 PURPA Purchased Power Capacity Projected Billing Period 0.131 0.105 0.000 227 Total PURPA Power Capacity Component 0.181 0.128 0.000 308 Total PURPA purchased power capacity Component Increased for RECD 0.182

DER Avoided Costs - McGee Exhibits 13 and 14 Cents / kW9 DER Avoided Cost Under / (Over) Collection at June 2015 0.000 0.000 0.000 010 DER Avoid Cost Projected Billing Period 0.000 0.000 0.000 011 Total DER Avoided Cost Component 0.000 0.000 0.000 012 Total DER Avoided Cost Component Increased for RECD 0.000

Environmental Costs - McGee Exhibits 4 and 5 Cents / kW13 Environmental Component Under / (Over) Collection at June 2015 (0.017) (0.016) N/A (4)14 Environmental Component Projected Billing Period 0.059 0.047 N/A 1015 Total Environmental Component 0.042 0.031 N/A 616 Total Environmental Cost Component Increased for RECD 0.042

17 Total Fuel Cost Components billed as Cents per kWh 2.471 2.389 2.230 2.23018 Total Fuel Cost Components billed as Cents per kW 36

Total Distributed Energy Resource Incremental Cost - McGee Exhibits 11-12 Residential Commercial Industrial19 Total DERP Annual Charge-Excluding GRT 4.27$ 8.43$ 750.99$ 20 Total DERP Monthly Charge-Excluding GRT 0.36$ 0.70$ 62.58$

Cents / kWh

Cents / kWh

Cents / kWh

Cents / kWh


Code Ann. § 58-27-865(A)(1). The DERP incremental cost component is shown 1

separately because Act 236 requires that incremental costs of DERP be allocated 2

among customer classes using the same method that is used to allocate variable 3

environmental costs. 4

Q. HOW DID DEP’S FUEL REVENUE BILLINGS COMPARE TO THE 5

FUEL COSTS INCURRED DURING THE MARCH 2015 TO JUNE 2016 6

TIME PERIOD? 7

A. McGee Exhibit No. 2 is a monthly comparison of fuel revenues billed to South 8

Carolina retail customers to the actual and estimated jurisdictional fuel costs 9

attributable to those sales. As shown on Exhibit 2, the projected DEP fuel 10

recovery status at June 30, 2016 is an under-recovery of $1.3 million. 11

Q. PLEASE EXPLAIN MCGEE EXHIBIT NO. 3. 12

A. McGee Exhibit No. 3 presents DEP’s recommended projected base fuel rate of 13

2.250¢/kWh for the billing period for the recovery of South Carolina retail share 14

of $1.4 billion of projected system fuel expense. The South Carolina retail share 15

also incorporates the NEM avoided fuel benefits assigned fully to SC customers. 16

The fuel forecast supporting the projected fuel cost was generated by an 17

hourly dispatch model that considers the latest forecasted fuel prices, outages at 18

the generating plants based on planned maintenance and refueling schedules, 19

forced outages based on historical trends, generating unit performance 20

parameters, and expected market conditions associated with power purchase and 21

off-system sales opportunities. In addition, the forecasting model reflects the 22


joint dispatch of the combined power supply resources of the Companies, as 1

described by Company witness Daji. 2

Q. PLEASE PROVIDE A STATUS UPDATE OF ENVIRONMENTAL COST 3

COLLECTION AND EXPLAIN HOW THESE COSTS HAVE BEEN 4

TREATED IN THIS FILING. 5

A. During the review period, DEP recovered variable environmental costs and the 6

costs of emission allowances through the environmental component of the fuel 7

rate. Environmental costs allocated to the South Carolina retail jurisdiction 8

during the review period were approximately $2.1 million, as shown by month on 9

McGee Exhibit No. 4. The Company currently estimates that its deferred 10

environmental cost balance will be an over-collection of $738,000 at June 30, 11

2016. 12

Q. HAVE YOU PROVIDED A FORECAST OF ENVIRONMENTAL COSTS? 13

A. Yes, McGee Exhibit No. 5 presents DEP’s estimated system environmental costs 14

for the billing period of $21.6 million. The South Carolina retail portion is 15

forecasted to be approximately $2.2 million. 16

Q. PLEASE DESCRIBE EMISSION-REDUCING CHEMICALS THAT DEP 17

WILL INCLUDE IN THE PROPOSED FUEL RATE IN THIS FILING. 18

A. As Company witness Miller explains more specifically in his testimony, DEP uses 19

emission-reducing chemicals at its fossil/hydro plants to help it provide low cost, 20

reliable electric generation for its customers while also complying with state and 21

federal environmental control obligations. As a result, DEP has included the cost 22

of magnesium hydroxide, calcium carbonate, ammonia, urea, limestone, lime and 23


hydrated lime incurred during the review period in its fuel cost recovery 1

application. Mercury and Air Toxics Standards (“MATS”) chemicals that DEP 2

may use in the future to reduce emissions include, but may not be limited to, 3

activated carbon, mercury oxidation chemicals, and mercury re-emission 4

prevention chemicals. 5

Q. HOW DID DEP ALLOCATE ENVIRONMENTAL COSTS? 6

A. Environmental costs were allocated to Residential, General Service (non-7

demand), and General Service (demand) rate classes based upon the firm 8

coincident peak experienced. The 2014 firm coincident peak demand was used to 9

allocate costs for the period March 2015 – December 2015 and the 2015 firm 10

coincident peak demand was used to allocate costs for the period January 2016 – 11

June 2017. This allocation is shown on McGee Exhibit Nos. 4 and 5. 12

Rates were designed based on costs allocated to the respective rate 13

classes and the projected energy consumption for the Residential and General 14

Service (non-demand) schedules. The rate for the General Service (demand) class 15

was based on projected annual demand. All allocations were consistent with the 16

methodology approved by this Commission in Order No. 2007-440, issued in 17

DEP’s 2007 fuel review proceeding. This methodology has been consistently 18

used in each fuel case since the issuance of the 2007 Order. 19


Q. PLEASE PROVIDE A STATUS UPDATE OF PURPA PURCHASED 1

POWER CAPACITY COST COLLECTION AND EXPLAIN HOW THESE 2

COSTS HAVE BEEN TREATED IN THIS FILING? 3

A. Yes. During the review period, DEP recovered PURPA purchased power 4

capacity costs as a component of the fuel rate. PURPA purchased power capacity 5

costs allocated to the South Carolina retail jurisdiction during the review period 6

were approximately $4.0 million, as shown on McGee Exhibit No. 7. The 7

Company currently estimates that its deferred PURPA purchased power capacity 8

cost balance of June 2016 will be an under-recovery of $1.8 million. As a result 9

of changes made in S.C. Code Ann. § 58-27-865(A)(1) by Act 236, the avoided 10

capacity component of these costs are to be allocated and recovered from 11

customers under a separate capacity component of the overall fuel factor based on 12

the same method that is used by the utility to allocate and recovery variable 13

environmental costs. 14

Q. HAVE YOU PROVIDED A FORECAST OF PURPA PURCHASED 15

POWER CAPACITY COSTS? 16

A. Yes, McGee Exhibit No. 8 presents DEP’s estimated purchased power capacity 17

costs for the billing period of $47.9 million. The South Carolina retail portion is 18

forecasted to be approximately $5.0 million. 19

Q. HOW DID DEP ALLOCATE PURPA PURCHASED POWER CAPACITY 20

COSTS? 21

A. PURPA purchased power capacity costs were allocated to Residential, General 22

Service (non-demand), and General Service (demand) rate classes based upon the 23


firm coincident peak demand. The 2014 firm coincident peak demand was used to 1

allocate costs for the period March 2015-December 2015 and the 2015 firm 2

coincident peak demand was used to allocate costs for the period January 2016 – 3

June 2017. This allocation is shown on McGee Exhibit Nos. 7 and 8. 4

Q. ARE DERP COSTS AND ASSOCIATED REVENUES INCLUDED IN 5

THIS FUEL FILING? 6

A. Yes. Pursuant to in S.C. Code Ann. § 58-39-130(A)(2), an electrical utility shall 7

be permitted to recover its costs related to approved DERP. The Commission 8

approved DEP’s recovery of DERP costs in Order No. 2015-843. Beginning in 9

January 2016, revenues were collected from customers on a per account basis, and 10

McGee Exhibit Nos. 9-14 provide details regarding the allocation and recovery of 11

the DERP costs. 12

Q. PLEASE EXPLAIN WHAT IS SHOWN ON MCGEE EXHIBIT NO. 9. 13

A. McGee Exhibit No. 9 provides DEP’s actual DERP incremental and avoided cost 14

for the review period and the estimated DERP incremental and avoided cost for 15

the estimated period by month. Incremental costs that were exclusively assigned 16

to the South Carolina retail jurisdiction, during the review period were 17

approximately $597,000 and $264,000 for the estimated period. 18


A. McGee Exhibit No. 10 provides DEP’s projected DERP incremental and avoided 20

cost for the billing period. Total DERP incremental costs of $889,000 are 21

projected for the billing period. There are no avoided cost projected for the 22

billing period. 23


Q. WHAT INCREMENTAL COSTS ARE INCLUDED ON MCGEE EXHIBIT 1

NOS. 9 AND 10? 2

A. S.C. Code Ann. § 58-39-140 defines “incremental costs” as all reasonable and 3

prudent costs incurred by an electrical utility to implement a distributed energy 4

resource program. This filing includes the following categories of incremental 5

costs: 6

• Costs associated with purchase power agreements (“PPA”) in excess of 7

the Company’s avoided cost rate; 8

• The DERP net energy metering (“NEM”) incentive, which is a credit 9

available to eligible NEM customer-generators, approved in Docket No. 10

2014-246-E; 11

• Avoided capacity costs associated with NEM, recoverable as an 12

incremental cost based on Section 58-40-20(F)(6); 13

• Rebates given to residential and non-residential customers to invest in or 14

lease distributed generation and carrying costs related to the amortization 15

of the rebate amounts; 16

• An incentive utilized to lower the subscription charge customers will pay 17

to participate in a Shared Solar program; 18

• General and administrative costs, which include the cost of developing 19

and implementing programs, cost of incremental labor and additional 20

revenue-grade meters. 21


Q. HAS THE COMPANY COMPUTED AN UPDATED DERP NEM 1

INCENTIVE AS PART OF THIS FUEL FILING? 2

A. Yes. There were no changes to the methodology used to derive the DERP NEM 3

incentive and value of solar calculation, described in the Settlement Agreement in 4

Docket No. 2014-246-E and approved the Commission’s Order No, 2015-194 in 5

Docket 2014-246-E. However, the inputs were updated to reflect more current 6

information. Specifically, the hourly load associated with each rate class and the 7

hourly solar profiles were updated to reflect 2014 values. Additionally, the billing 8

rates were updated to reflect current rates approved effective January 1, 9

2016. The analysis reflects updated avoided energy and capacity costs based on 10

Office of Regulatory Staff’s recommended rates in the current avoided cost 11

Docket No. 1995-1192-E. The calculation of the updated DERP NEM incentive 12

is shown on Exhibit 15 and the impact is reflected in the billing period shown on 13

McGee Exhibit Nos. 10 and 12. 14

Q. HOW DID THE COMPANY ALLOCATE AND RECOVER ITS 15

INCREMENTAL COSTS? 16

A. DEP allocated 100% of DERP incremental costs to Residential, Commercial 17

(General Service/Lighting), and Industrial rate classes based upon the firm peak 18

of each class for the prior year. For recovery purposes, each class’s allocated 19

portion of incremental costs will be divided by the number of accounts subject to 20

DERP in each class. This method results in an annual dollar per account charge 21

for all accounts subject to DERP in each class. The annual charge is a separate 22

fixed monthly component of the fuel factor for each class of customer. 23


One exception to this approach is the allocation of the avoided capacity 1

costs associated with NEM that is included in the DERP incremental costs. This 2

particular incremental cost has been allocated to South Carolina retail based on its 3

pro rata share of system peak demand, rather than 100%. This DERP cost is 4

related to system generation supply resources. Costs and benefits associated with 5

system generation supply resources are traditionally allocated among all of the 6

Company’s rate jurisdictions since such generation supply resources are operated 7

as a portfolio to serve its native load customers in all rate jurisdictions. 8

Q. IS AN OVER/(UNDER) RECOVERY OF DERP INCREMENTAL COSTS 9

COMPUTED IN THIS FILING? 10

A. Yes, McGee Exhibit 11 computes the over/(under) recovery of DERP incremental 11

costs by comparing the actual and estimated expenses incurred during the review 12

period and the estimated period to the revenue collected or estimated during the 13

actual and estimated period. This exhibit establishes the monthly charges by 14

customer class for incremental DERP over/(under) recovery. DEP proposes the 15

per-account charge per month for under recovery of $0.04, $0.07 and $19.63 for 16

South Carolina residential, commercial (general service/lighting) and industrial 17

customers, excluding GRT. 18


A. McGee Exhibit No. 12 shows the calculation of the prospective per-account 20

charge by customer class in order for DEP to recover DERP forecasted 21

incremental costs. DEP proposes the estimated per-account charge per month of 22

$0.31, $0.63 and $42.96 for South Carolina residential, commercial and industrial 23


customers, excluding GRT. 1

Q. WHAT DERP AVOIDED COSTS ARE INCLUDED IN THIS FILING? 2

A. Avoided cost generally refers to the cost the utility avoids when buying power 3

from another entity rather than generating the power itself. Under PURPA, 4

payments made to qualifying facilities for power are based on avoided cost rates. 5

In the DERP context, S.C. Code Ann. §58-39-140(A)(1) states that “avoided cost” 6

for purposes of separating total DERP program costs between incremental and 7

avoided costs is “all costs paid under avoided cost rates, or negotiated rates 8

pursuant to PURPA, which ever is lower”. In S.C. Code Ann. § 58-39-120(B), 9

avoided costs are further defined, indicating that they are to be rates most recently 10

approved by the Commission, or negotiated pursuant to PURPA. 11

This filing does not include any avoided costs amounts related to DERP 12

due to the lack of PPA agreements and Shared Solar agreements during the 13

review, estimated and billing periods. 14

Q. HOW WILL THE COMPANY ALLOCATE AND RECOVER ITS DERP 15

AVOIDED COSTS? 16

A. DEP plans to allocate and recover DERP avoided costs based on the same method 17

that is used by the utility to allocate and recover variable environmental costs. As 18

such, DEP will allocate the South Carolina Retail portion of DERP avoided costs 19

to Residential, General Service - Non Demand, General Service - Demand and 20

Lighting rate classes based upon the firm peak experienced by each class during 21

the review period. The total cost allocated to each class is divided by projected 22

sales to arrive at a cents per kWh or kW, depending on customer class. 23



A. McGee Exhibit No. 13 shows the calculation of the over/ (under) recovery by 2

customer class of total DERP avoided energy and capacity costs. Since there were 3

no avoided costs during the period March 2015 – June 2016, the rates will be set 4

to zero for this filing. 5

Q. HAVE YOU PROVIDED A FORECAST OF DERP AVOIDED COSTS IN 6

MCGEE EXHIBIT NO. 14? 7

A. Yes. The forecast of DERP avoided costs is zero due to the projected timing of 8

PPA contracts and Shared Solar Agreements being outside the billing period. 9

Q. DO YOU BELIEVE DEP’S ACTUAL FUEL COSTS AND DERP COSTS 10

INCURRED DURING THE PERIOD WERE REASONABLE? 11

A. Yes. I believe the costs were reasonable and that DEP has demonstrated that it 12

has met the criteria set forth in S.C. Code Ann. § 58-27-865. These costs also 13

reflect DEP’s continuing efforts to maintain reliable service and an economical 14

generation mix, thereby minimizing the total cost of providing service to DEP’s 15

South Carolina retail customers. I also believe that the DERP costs were 16

reasonable and that DEP has demonstrated that it met the criteria set forth in S.C. 17

Code Ann. § 58-39-130(A)(2). 18

Q. HOW ARE MERGER FUEL-RELATED SAVINGS HANDLED IN DEP’S 19

RECOMMENDED FUEL RATES? 20

A. As Company witness Daji states in her testimony, merger fuel-related savings 21

automatically flow through to DEP’s retail customers through the fuel and fuel-22

related cost component of customers’ rates. Actual merger savings during the 23


review period are included in the true-up portion of the proposed fuel and fuel-1

related cost factors. In addition, in the prospective component of the factors, the 2

projected merger savings related to procuring coal and reagents, lower 3

transportation costs, lower gas capacity costs, and coal blending are reflected in 4

the cost of fossil fuel. Projected joint dispatch savings, which are the result of 5

using the combined systems’ lowest cost available generation to meet total 6

customer demand, are also reflected in the cost of fossil fuel, as well as the 7

projected cost purchases and sales that include the purchases and sales between 8

DEP and DEC. Actual and projected savings related to the procurement of 9

nuclear fuel are reflected in the cost of nuclear fuel. 10

Q. INCLUDING THE DERP INCREMENTAL PER ACCOUNT CHARGES, 11

WHAT IS THE IMPACT TO CUSTOMERS’ BILLS IF THE PROPOSED 12

FUEL, PURPA CAPACITY, DERP AVOIDED COSTS, AND 13

ENVIROMENTAL FACTORS ARE APPROVED BY THE 14

COMMISSION? 15

A. The impact of all components of this filing to customers monthly bills of an 16

average residential customer using 1000 kWh per month is a decrease of $2.77, or 17

2.7%. The impacts for general service-non demand, lighting and general service-18

demand vary by customer, but are approximately decreases of 2.9%, 1.3% and 19

4.5%, respectively. 20

Q. WHAT ARE THE KEY DRIVERS IMPACTING THE PROPOSED FUEL 21

FACTOR? 22

A. A number of factors contribute to the change in the proposed total fuel cost 23


factors for all customer classes. Total base fuel costs projected for the billing 1

period are declining primarily due to lower fuel commodity prices. In addition, 2

there is an over-collection of fuel costs included in the 2016 proposed base fuel 3

rates as compared to an under-collection reflected in existing rates. These two 4

favorable impacts are the most significant drivers of the fuel rate change. 5

Q. IN THE SETTLEMENT AGREEMENT APPROVED IN DOCKET 2015-1-6

E, THE COMPANY AGREED TO CONDUCT A REVIEW OF ITS FUEL 7

COSTS TO DETERMINE THOSE MORE PROPERLY CLASSIFIED AS 8

CAPACITY COSTS IN CONSULTATION WITH PARTIES TO THIS 9

DOCKET. HAS THE COMPANY PERFORMED THIS REVIEW FOR 10

THIS PROCEEDING? 11

A. Yes, DEP performed this review pursuant to the terms of the Settlement 12

Agreement. 13

Q. CAN YOU PLEASE DESCRIBE THE REVIEW CONDUCTED BY THE 14

COMPANY? 15

A. Based on the new language of the South Carolina fuel statute, the Company 16

initiated an evaluation of certain items of fuel and fuel-related costs to determine 17

whether such costs could be characterized as being “capacity costs” under the 18

law. Pursuant to the changes implemented through Act 236, S.C. Code Ann. § 19

58-27-865 was amended to state “if capacity costs are permitted to be recovered 20

through the fuel factor, such costs shall be allocated and recovered from 21

customers under a separate capacity component of the overall fuel factor based on 22

the same method that is used by the utility to allocate and recover variable 23


environmental costs.” No definition of “capacity” is provided, but the term has 1

generally been defined in literature from the National Association of Regulatory 2

Utility Commissioners (“NARUC”) and from other sources as the amount of 3

power produced measured on an instantaneous basis; a maximum that can be 4

produced at one point in time, and is measured in kW. Costs of capacity are 5

typically those associated with this maximum amount of power (kW) being 6

produced, purchased or demanded at a point in time. In this context, the specific 7

items of fuel and fuel-related costs the Company considered for possible re-8

classification as “capacity costs” in its review included the following general 9

categories: 10

1) Ancillary services impacting fuel costs, 11

2) Fuel transportation and delivery costs, and 12

3) Purchased power costs. 13

Q. WHAT WERE THE RESULTS OF THE COMPANY’S REVIEW? 14

A. Based on its review, the Company determined that a change in the classification 15

of these categories of costs, so as to allocate them as “capacity costs,” was not 16

justified at this time. These fuel and fuel-related costs are all principally incurred 17

by the Company based on the quantity of energy produced to serve load, rather 18

than the peak demand of the Company’s system. With the limited exception of 19

capacity charges paid for purchased power, these costs are all currently allocated 20

in the Company’s cost of service study based on energy and will fluctuate over 21

time based on the energy needs of the Company’s customers. It is important to 22

note that the fixed or variable nature of an item of cost is not, by itself, 23


determinative as to whether that cost is capacity or energy-related. Rather, it is 1

the underlying cause for the expense itself that guides the evaluation. 2


A. Yes, it does. 4

Exhibit 1DOCKET NO 2016-1-E

Line No. Description Reference ResidentialGeneral Service (non demand) Lighting

General Service (demand)

Base Fuel Costs1 Base Fuel Cost Component Under/ (Over) Collection at June 2016 Exhibit 2 (0.020) (0.020) (0.020) (0.020)2 Base Fuel Cost Component Projected Billing Period Exhibit 3 2.250 2.250 2.250 2.2503 Total Base Fuel Cost Component Line 1 + Line 2 2.230 [1] 2.230 2.230 2.2304 Total Base Fuel Cost Component Increased for RECD Line 3 / (1-RECD factor) 2.247

PURPA Purchased Power Capacity Cost Cents / kW5 PURPA Purchased Power Capacity Under / (Over) Collection at June 2016 Exhibit 7 0.050 0.023 0.000 86 PURPA Purchased Power Capacity Projected Billing Period Exhibit 8 0.131 0.105 0.000 227 Total PURPA Purchased Power Capacity Cost Component Line 5 + 6 0.181 [1] 0.128 0.000 30 [2]8 Total PURPA Purchased Power Capacity Cost Component Increased for RECD Line 7 / (1- RECD factor) 0.182

Distrbuted Energy Resource Program Avoided Costs Cents / kW9 DERP Avoided Cost Under/ (Over) Collection at June 2016 Exhibit 13 0.000 0.000 0.000 0

10 DERP Avoided Costs Projected Billing Period Exhibit 14 0.000 0.000 0.000 011 Total DERP Avoided Cost Component Line 9 + 10 0.000 [1] 0.000 0.000 0 [3]12 TotalDERP Avoided Cost Component Increased for RECD Line 11 / (1- RECD factor) 0.000

Environmental Costs Cents / kW13 Environmental Component Under / (Over) Collection at June 2016 Exhibit 4 (0.017) (0.016) N/A (4)14 Environmental Component Projected Billing Period Exhibit 5 0.059 0.047 N/A 1015 Total Environmental Component Line 13 + 14 0.042 [1] 0.031 N/A 6 [4]16 Total Environmental Cost Component Increased for RECD Line 15 / (1- RECD factor) 0.042

17 Total Fuel Cost Factor - Cents/ kWh [5]Line 4 + Line 8 + Line 12 +

Line 16 2.471 2.389 2.230 2.23018 Total Demand Fuel Cost Factor - Cents/ kW [5] Line 7 + Line 11 + line 15 36

Notes:

Residential Commercial IndustrialDistributed Energy Resource Program Incremental Cost per Account

DERP Incremental Under/ (Over) Collection at June 201619 Annual Charge Exhibit 11 0.50$ 0.84$ 235.53$ 20 Monthly Charge Exhibit 11 0.04$ 0.07$ 19.63$

DERP Incremental Projected Billing Period21 Annual Charge Exhibit 12 3.77$ 7.59$ 515.46$ 22 Monthly Charge Exhibit 12 0.31$ 0.63$ 42.96$

23 Total DERP Annual Charge - Excluding GRT Line 19 + Line 21 4.27$ 8.43$ 750.99$ 24 Total DERP Monthly Charge - Excluding GRT Line 20 + Line 22 0.36$ 0.70$ 62.58$

25 Total DERP Annual Charge -Including GRT Line 23 / (1-Tax Rate) 4.29$ 8.47$ 754.36$ 26 Total DERP Monthly Charge - Including GRT Line 24 / (1-Tax Rate) 0.36$ 0.71$ 62.86$

Dollars

Cents / kWh

Cents / kWh

Cents / kWh

Cents / kWh

[1] RECD factor is .7577% and is calculated on Exhibit 6[2] The Capacity rate for these customers is 30 cents per kW as calculated on exhibits 7 & 8[3] The Distributed Energy Resource Programs Avoided Costs for these customers is 0 cents per kW as calculated on exhibits 13 & 14

[5] The Fuel Cost Factor and Demand Fuel Cost Factor exclude GRT[4] The Environmental rate for these customers is 6 cents per kW as calculated on exhibits 4 & 5

Customer Class

DUKE ENERGY PROGRESS, INCSOUTH CAROLINA RETAIL FUEL CASE

CALCULATION OF TOTAL FUEL COMPONENTFOR THE BILLING PERIOD JULY 2016 THROUGH JUNE 2017


Page 1

Actual Actual Actual Actual Actual ActualMarch April May June July August

Line No. Description Reference 2015 2015 2015 2015 2015 2015

1 Coal 32,963,479$ 19,413,637$ 37,131,548$ 52,542,250$ 57,652,526$ 53,689,682$ 2 Gas 72,492,716 56,175,643 61,819,122 65,189,830 66,892,591 64,363,714 3 Nuclear Fuel 11,247,689 9,752,181 10,729,640 11,707,949 15,314,346 17,635,952 4 Purchased Power 21,537,649 18,334,842 21,006,260 35,500,072 26,630,955 21,955,063 5 Fuel Expense Recovered Through Intersystem Sales (24,305,392) (15,569,759) (18,710,299) (16,179,885) (20,715,468) (13,098,106) 6 Total Fuel Costs Sum Lines 1 through 5 113,936,141$ 88,106,544$ 111,976,271$ 148,760,216$ 145,774,950$ 144,546,305$ 7 Eliminate Avoided Fuel Benefit of SC NEM8 Adjusted System Fuel Costs Line 6 + Line 7 113,936,141$ 88,106,544$ 111,976,271$ 148,760,216$ 145,774,950$ 144,546,305$

9 Total System KWH Sales 4,845,390,809 3,757,959,729 3,628,900,408 4,978,488,628 5,346,810,378 5,985,422,750 10 Eliminate NEM Solar Generation kWh11 Adjusted System kWh Sales Line 9 + Line 10 4,845,390,809 3,757,959,729 3,628,900,408 4,978,488,628 5,346,810,378 5,985,422,750

12 System Cost per kWh (¢/kWh) Line 8 / Line 11 * 100 2.351 2.345 3.086 2.988 2.726 2.415

13 SC Retail Sales kWH 570,749,238 463,754,149 420,603,466 578,289,954 607,719,653 653,631,427 14 Eliminate the NEM impact15 Adjusted SC Retail Sales Line 13 + Line 14 570,749,238 463,754,149 420,603,466 578,289,954 607,719,653 653,631,427

16 SC Base Fuel Costs Line 12 * Line 15 / 100 13,420,789$ 10,872,861$ 12,978,479$ 17,279,649$ 16,568,813$ 15,785,018$ 17 Assign 100% of Avoided Fuel Benefit of SC NEM18 Adjusted SC Base Fuel Costs Line 16 + Line 17 13,420,789$ 10,872,861$ 12,978,479$ 17,279,649$ 16,568,813$ 15,785,018$

19 Fuel Costs Collected 17,284,234$ 14,041,874$ 12,734,179$ 17,509,896$ 15,125,521$ 16,267,588$ 20 Fuel Benefits Given in DER NEM incentive21 Adjusted Fuel Costs Collected Line 19 + Line 20 17,284,234$ 14,041,874$ 12,734,179$ 17,509,896$ 15,125,521$ 16,267,588$

22 Over / (Under) Current Month Line 21 - Line 18 3,863,445$ 3,169,013$ (244,300)$ 230,247$ (1,443,292)$ 482,570$ 23 Over / (Under) Cumulative Balance - February 2015 Prior Year Annual Filing (20,760,123)$ 24 Adjustment(s)25 Over / (Under) Cumulative Balance Prior Mo Cum Bal + Line 22 + Line 24 (16,896,678)$ (13,727,665)$ (13,971,965)$ (13,741,718)$ (15,185,010)$ (14,702,440)$

Actual Actual Actual Actual Actual Actual Review PeriodSeptember October November December January February Twelve Months

Line No. Class Reference 2015 2015 2015 2015 2016 2016 Ended Feb-16

26 Coal 26,558,903$ 20,289,740$ 21,921,155$ 14,547,351$ 41,946,876$ 28,868,493$ 407,525,639$ 27 Gas 61,724,041 51,440,329 58,150,513 54,887,385 65,970,601 61,601,694 740,708,178 28 Nuclear Fuel 17,000,285 17,772,029 15,058,832 17,697,268 17,325,851 14,855,532 176,097,554 29 Purchased Power 20,467,340 14,384,101 17,360,782 18,744,097 18,520,351 25,628,749 260,070,261 30 Fuel Expense Recovered Through Intersystem Sales (12,444,610) (11,915,036) (9,801,902) (12,965,903) (6,517,748) (9,814,074) (172,038,183) 31 Total Fuel Costs Sum Lines 26 through 30 113,305,959$ 91,971,163$ 102,689,380$ 92,910,198$ 137,245,931$ 121,140,394$ 1,412,363,450$ 32 Eliminate Avoided Fuel Benefit of SC NEM -$ -$ -$ 230$ 162$ 393$ 33 Adjusted System Fuel Costs Line 31 + Line 32 113,305,959$ 91,971,163$ 102,689,380$ 92,910,198$ 137,246,161$ 121,140,556$ 1,412,363,842$

34 Total System KWH Sales 5,526,400,413 4,506,558,036 4,068,338,456 4,554,249,791 5,548,083,471 5,382,673,888 58,129,276,757 35 Eliminate NEM Solar Generation kWh - - - 5,723 4,026 9,749 36 Adjusted System kWh Sales Line 34 + Line 35 5,526,400,413 4,506,558,036 4,068,338,456 4,554,249,791 5,548,089,194 5,382,677,914 58,129,286,506


38 SC Retail Sales kWH 560,668,824 488,426,474 474,177,711 438,667,815 555,252,619 601,562,765 6,413,504,095 39 Eliminate the NEM impact - - - 5,723 4,026 9,749 40 Adjusted SC Retail Sales Line 38 + Line 39 560,668,824 488,426,474 474,177,711 438,667,815 555,258,342 601,566,791 6,413,513,844

41 SC Base Fuel Costs Line 37 *Line 40 / 100 11,495,207$ 9,967,951$ 11,968,772$ 8,949,161$ 13,735,734$ 13,538,640$ 156,561,074$ 42 Assign 100% of Avoided Fuel Benefit of SC NEM -$ -$ -$ (230)$ (162)$ (392)$ 43 Adjusted SC Base Fuel Costs Line 41 + Line 42 11,495,207$ 9,967,951$ 11,968,772$ 8,949,161$ 13,735,504$ 13,538,478$ 156,560,682$

44 Fuel Costs Collected 13,953,808$ 12,155,439$ 11,801,560$ 10,919,093$ 13,821,292$ 14,975,023$ 170,589,507$ 45 Fuel Benefits Given in DER NEM incentive -$ -$ (60)$ (42)$ (102)$ 46 Adjusted Fuel Costs Collected Line 44 + Line 45 13,953,808$ 12,155,439$ 11,801,560$ 10,919,093$ 13,821,232$ 14,974,981$ 170,589,405$

47 Over / (Under) Recovered Current Month Line 46 - Line 43 2,458,601$ 2,187,488$ (167,212)$ 1,969,932$ 85,729$ 1,436,503$ 14,028,724$ 48 Adjustment(s) 49,799$ 44,768$ 159$ 94,726$ 49 Over / (Under) Recovered Cumulative Balance Prior Mo Cum Bal + Line 47 + Line 48 (12,243,839)$ (10,006,552)$ (10,128,996)$ (8,159,064)$ (8,073,335)$ (6,636,673)$ (6,636,673)$


CALCULATION OF BASE FUEL OVER / (UNDER) RECOVERYACTUAL COSTS AND REVENUES MARCH 2015 - FEBRUARY 2016


Page 2

Estimated Estimated Estimated Estimated Sixteen MonthsMarch April May June Ended

Line No. Class Reference 2016 2016 2016 2016 June 2016

50 Coal 6,997,344$ 16,026,251$ 21,076,715$ 38,397,596$ 490,023,545$ 51 Gas 54,192,469 46,524,014 51,617,437 55,418,269 948,460,368 52 Nuclear Fuel 13,385,668 17,569,468 18,256,802 17,586,057 242,895,549 53 Purchased Power 30,256,708 20,882,248 21,353,905 24,035,598 356,598,720 54 Fuel Expense Recovered Through Intersystem Sales (15,521,039) (12,058,549) (12,524,902) (10,735,247) (222,877,920) 55 Total Fuel Costs Sum Lines 50 through 54 89,311,151$ 88,943,432$ 99,779,957$ 124,702,273$ 1,815,100,262$ 56 Eliminate Avoided Fuel Benefit of SC NEM 265$ 1,049$ 1,294$ 1,539$ 4,540 57 Adjusted System Fuel Costs Line 55 + Line 56 89,311,416$ 88,944,481$ 99,781,251$ 124,703,812$ 1,815,104,802$

58 Projected Total System KWH Sales 4,720,617,141 4,312,137,696 4,721,331,352 5,515,688,799 77,399,051,745 59 Eliminate NEM Solar Generation kWh 6,592 26,161 32,268 38,374 113,143 60 Adjusted Projected System kWh Sales Line 58 + Line 59 4,720,623,733 4,312,163,857 4,721,363,619 5,515,727,173 77,399,164,888

61 System Cost per kWh (¢/kWh) Line 57 / Line 60 * 100 1.892 2.063 2.113 2.261 2.345

62 Projected SC Retail Sales 462,889,901 459,376,756 502,773,736 580,364,203 8,418,908,692 63 Eliminate the NEM impact 6,592 26,161 32,268 38,374 113,143 64 Adjusted Projected SC Retail Sales Line 62 + Line 63 462,896,493 459,402,917 502,806,004 580,402,577 8,419,021,835

65 SC Base Fuel Costs Line 61 * Line 64 / 100 8,757,729$ 9,475,835$ 10,626,297$ 13,122,189$ 198,543,124$ 66 Assign 100% of Avoided Fuel Benefit of SC NEM (265)$ (1,049)$ (1,294)$ (1,539)$ (4,539) 67 Adjusted SC Base Fuel Costs Line 65 + Line 66 8,757,463$ 9,474,786$ 10,625,003$ 13,120,650$ 198,538,584$

68 Projected Fuel Costs Collected 11,522,105$ 11,433,887$ 12,514,038$ 14,445,265$ 220,504,803$ 69 Fuel Benefits Given in DER NEM incentive (69)$ (397)$ (490)$ (582)$ (1,639) 70 Adjusted Projected Fuel Costs Collected Line 68 + Line 69 11,522,036$ 11,433,491$ 12,513,549$ 14,444,683$ 220,503,163$

71 Over / (Under) Recovered Current Month Line 70 - Line 67 2,764,573$ 1,958,704$ 1,888,546$ 1,324,033$ 21,964,579$ 72 Adjustment(s) 94,726 73 Over / (Under) Recovered Cumulative Balance Prior Mo Cum Bal + Line 71 + Line 72 (3,872,100)$ (1,913,395)$ (24,850)$ 1,299,183$ 1,299,182$

74 SC Projected SC Retail Sales July 2016 - June 2017 6,488,354,470

75 SC Base Fuel Increment / (Decrement) Calculated Rate (cents / kWh) -Line 73 / Line 74 * 100 (0.020) ¢/kWh

SOUTH CAROLINA RETAIL FUEL CASE

ESTIMATED COSTS AND REVENUES MARCH 2016 - JUNE 2016CALCULATION OF BASE FUEL OVER / (UNDER) RECOVERY

DUKE ENERGY PROGRESS, INC


July August September October November DecemberLine No. Description Reference 2016 2016 2016 2016 2016 2016

1 Coal WP1 45,924,779$ 47,286,514$ 31,695,619$ 23,339,676$ 26,300,882$ 48,892,716$ 2 Gas WP2 62,277,466 61,042,779 53,919,437 42,932,878 36,261,042 39,472,250 3 Nuclear Fuel WP3 18,112,841 18,000,667 17,411,299 14,167,836 17,347,249 18,791,304 4 Purchased Power WP5 26,980,870 26,554,899 22,609,063 26,841,085 23,510,427 20,636,493 5 Fuel Expense Recovered Through Intersystem Sales WP6 (11,317,574) (11,227,547) (10,105,731) (3,855,905) (4,617,155) (5,051,009) 6 Total Fuel Costs Sum Lines 1 through 5 141,978,382$ 141,657,312$ 115,529,687$ 103,425,570$ 98,802,445$ 122,741,754$ 7 Eliminate Avoided Fuel Benefit of SC NEM WP15 1,463$ 1,664$ 1,865$ 2,066$ 2,267$ 2,468$ 8 Adjusted System Fuel Costs Line 6 + Line 7 141,979,845$ 141,658,976$ 115,531,552$ 103,427,636$ 98,804,712$ 122,744,222$

9 Projected Total System Sales WP8 6,131,619,391 6,070,851,379 5,145,308,592 4,506,286,142 4,666,907,710 5,612,506,214 10 Eliminate NEM Solar Generation kWh WP15 44,481 50,587 56,693 62,800 68,903 75,010 11 Adjusted Projected System kWh Sales Line 9 + Line 10 6,131,663,872 6,070,901,966 5,145,365,285 4,506,348,942 4,666,976,613 5,612,581,224


13 Adjusted Projected SC Retail Sales WP8a 619,256,568 628,023,721 524,294,731 478,417,213 497,092,942 537,661,547 14 SC Base Fuel Costs Line 12 * Line 13 / 100 14,339,004$ 14,654,362$ 11,772,261$ 10,980,411$ 10,523,971$ 11,758,377$ 15 Assign 100% of Avoided Fuel Benefit of SC NEM (Note 1) WP15 (1,111)$ (1,263)$ (1,416)$ (1,568)$ (1,721)$ (1,873)$ 16 Adjusted SC Base Fuel Costs Line 14 + Line 15 14,337,893$ 14,653,099$ 11,770,845$ 10,978,843$ 10,522,250$ 11,756,504$

Billing PeriodJanuary February March April May June Twelve Months

Line No. Description Reference 2017 2017 2017 2017 2017 2017 Ended Jun-17

17 Coal 51,388,570$ 40,590,529$ 29,396,479$ 20,395,897$ 17,082,631$ 34,728,205$ 417,022,498$ 18 Gas 40,275,976 38,240,661 49,218,720 46,680,249 50,976,497 54,222,534 575,520,488$ 19 Nuclear Fuel 18,739,932 15,648,569 13,632,196 13,876,108 18,441,735 17,441,511 201,611,248$ 20 Purchased Power 24,747,647 24,076,200 30,047,689 26,046,995 24,834,713 28,423,801 305,309,884$ 21 Fuel Expense Recovered Through Intersystem Sales (6,214,202) (3,177,423) (2,489,520) (8,340,498) (14,364,698) (11,075,378) (91,836,640)$ 22 Total Fuel Costs Sum Lines 17 through 21 128,937,923$ 115,378,536$ 119,805,564$ 98,658,751$ 96,970,878$ 123,740,673$ 1,407,627,478$ 23 Eliminate Avoided Fuel Benefit of SC NEM 4,171$ 5,874$ 7,577$ 9,281$ 10,984$ 12,687$ 62,368 24 Adjusted System Fuel Costs Line 22 + Line 23 128,942,094$ 115,384,410$ 119,813,141$ 98,668,032$ 96,981,862$ 123,753,360$ 1,407,689,846$

25 Projected Total System Sales 5,790,398,433 5,046,328,688 4,928,235,091 4,343,473,542 4,764,742,801 5,570,177,980 62,576,835,962 26 Eliminate NEM Solar Generation kWh 126,774 178,545 230,315 282,085 333,855 385,626 1,895,674 27 Adjusted Projected System kWh Sales Line 25 + Line 26 5,790,525,207 5,046,507,233 4,928,465,406 4,343,755,627 4,765,076,656 5,570,563,606 62,578,731,637

28 System Cost per kWh (¢/kWh) Line 24 / Line 27 * 100 2.227 2.286 2.431 2.271 2.035 2.222 2.249

29 Adjusted Projected SC Retail Sales 594,079,252 525,295,116 527,892,801 463,565,806 507,559,686 587,110,761 6,490,250,144 30 SC Base Fuel Costs Line 28 * Line 29 / 100 13,228,821$ 12,010,459$ 12,833,304$ 10,529,857$ 10,330,177$ 13,043,012$ 146,004,016$ 31 Assign 100% of Avoided Fuel Benefit of SC NEM (Note 1) (3,165)$ (4,457)$ (5,749)$ (7,041)$ (8,333)$ (9,625)$ (47,322)$ 32 Adjusted SC Base Fuel Costs Line 30 + Line 31 13,225,656$ 12,006,002$ 12,827,555$ 10,522,816$ 10,321,844$ 13,033,387$ 145,956,694$

33 Projected SC Retail Sales 6,488,354,470 34 Adjusted SC System Cost per kWh (¢/kWh) Line 32 / Line 33 * 100 2.250


PROJECTED BILLING PERIOD BASE FUEL COSTSFOR THE 12 MONTHS JULY 2016 THROUGH JUNE 2017

Note 1: Equals total NEM avoided fuel benefit less portion included in DERP NEM Incentive.

Exhibit 4

Page 1a of 3DOCKET NO 2016-1-E

Line No. Residential1 Winter 2015 Firm Coincident Peak (CP) kWs 58.89%2 Winter 2014 Firm Coincident Peak (CP) kWs 59.70%



3 Total Reagents 1,638,493$ 1,082,992$ 2,034,376$ 2,966,636$ 3,319,892$ 3,097,803$ 4 Emission Allowances 6,417 4,083 6,743 26,652 12,988 (126,520) 5 Off-System Sales (202,288) (132,201) (205,351) (174,675) (219,121) (299,268) 6 Net Environmental Costs Sum Lines 3 thru 5 1,442,623$ 954,875$ 1,835,768$ 2,818,613$ 3,113,759$ 2,672,014$

7 Total System Sales kWh 4,845,390,809 3,757,959,729 3,628,900,408 4,978,488,628 5,346,810,378 5,985,422,750 8 Environmental System Costs Incurred ¢/kwh Line 6 / Line 7*100 0.030 0.025 0.051 0.057 0.058 0.045 9 SC Retail Sales kWh 570,749,238 463,754,149 420,603,466 578,289,954 607,719,653 653,631,427

10 SC Environmental Costs Line 8 * Line 9 / 100 169,930$ 117,837$ 212,773$ 327,404$ 353,910$ 291,794$ 11 Residential Environmental Cost Allocated by Firm CP Line 10 * Line 2 101,446$ 70,348$ 127,023$ 195,457$ 211,281$ 174,198$

12 SC Residential kWh Sales 221,639,208 131,947,547 112,305,130 182,767,188 222,381,186 207,728,757 13 SC Residential Environmental Costs Incurred ¢/kwh Line 11 / Line 12 * 100 0.046 0.053 0.113 0.107 0.095 0.084 14 SC Residential Environmental Costs Billed ¢/kwh 2014-1-E / 2015-1-E 0.042 0.042 0.042 0.042 0.073 0.073

15 SC Residential Environmnental Costs Over / (Under) Recovery (Line 14 - Line 13) * Line 12 / 100 (9,052)$ (15,368)$ (80,243)$ (119,300)$ (47,984)$ (21,681)$ 16 Prior Year Balance and Misc. Adjustment(s) Prior Year Annual Filing 49,089$ 17 Cumulative SC Residential Environmental Costs Over / (Under) Recovery Line 15 + Prior Month Cum. Bal 40,037$ 24,669$ (55,574)$ (174,874)$ (222,858)$ (244,539)$


Line No. Description Reference 2015 2015 2015 2015 2016 2016 Ended Feb-16

18 Total Reagents 1,598,089$ 1,099,582$ 901,137$ 452,022$ 1,341,488$ 1,319,097$ 20,851,608$ 19 Emission Allowances 5,450 4,940 (55,594) 2,072 - 5,930 (106,840) 20 Off-System Sales (208,940) (208,309) (119,912) (109,062) (152,996) (127,616) (2,159,740) 21 Net Environmental Costs Sum Lines 18 thru 20 1,394,599$ 896,213$ 725,631$ 345,032.36$ 1,188,492$ 1,197,411$ 18,585,028$

22 Total System Sales 5,526,400,413 4,506,558,036 4,068,338,456 4,554,249,791 5,548,083,471 5,382,673,888 58,129,276,757 23 Environmental System Costs Incurred ¢/kwh Line 21 / Line 22 * 100 0.025 0.020 0.018 0.008 0.021 0.022 24 SC Retail Sales kWh 560,668,824 488,426,474 474,177,711 438,667,815 555,252,619 601,562,765 6,413,504,095 25 SC Environmental Costs Line 23 * Line 24 / 100 141,486$ 97,133$ 84,575$ 33,234$ 118,944$ 133,822$ 2,082,841$ 26 Residential Environmental Cost Allocated by Firm CP Line 25 * Line 2 (or line 1) 84,466$ 57,987$ 50,490$ 19,840$ 70,048$ 78,810$ 1,241,395$

27 SC Residential kWh Sales 195,480,622 133,938,974 108,712,645 157,778,056 209,289,664 219,545,903 2,103,514,88028 SC Residential Environmental Costs Incurred ¢/kwh Line 26 / Line 27 * 100 0.043 0.043 0.046 0.013 0.033 0.036 0.059 29 SC Residential Environmental Costs Billed ¢/kwh 2015-1-E 0.073 0.073 0.073 0.073 0.074 0.073

30 SC Residential Environmnental Costs Over / (Under) Recovery (Line 29 - Line 28) * Line 27 / 100 59,057$ 40,333$ 29,327$ 96,051$ 84,039$ 82,486$ 97,665$ 31 Cumulative SC Residential Environmental Costs Over / (Under) Recovery Line 30 + Prior Month Cum. Bal (185,482)$ (145,149)$ (115,822)$ (19,771)$ 64,268$ 146,754$ 146,754$ 32 Adjustment(s) -$

33Adjusted Cumulative SC General Service (non-demand) Environmental Costs Over / (Under) Recovery Line 31 + Line 32 146,754$


CALCULATION OF ENVIRONMENTAL OVER / (UNDER) RECOVERY - RESIDENTIALACTUAL AND ESTIMATED COSTS AND REVENUES MARCH 2015 - JUNE 2016



CALCULATION OF ENVIRONMENTAL OVER / (UNDER) RECOVERY - RESIDENTIALACTUAL AND ESTIMATED COSTS AND REVENUES MARCH 2015 - JUNE 2016

Exhibit 4Page 1b of 3

DOCKET NO 2016-1-E


Line No. Description Reference 2016 2016 2016 2016 June 2016

34 Total Reagents 426,245$ 786,859$ 1,041,184$ 1,943,058$ 25,048,954$ 35 Emission Allowances (216,529) 5,877 7,149 11,730 (298,613)$ 36 Off-System Sales (75,739) (6,354) (20,982) (7,270) (2,270,085)$ 37 Net Environmental Costs Sum Lines 34 thru 36 133,977$ 786,382$ 1,027,351$ 1,947,518$ 22,480,256$

38 Projected Total System Sales 4,720,617,141 4,312,137,696 4,721,331,352 5,515,688,799 77,399,051,745 39 Environmental System Costs Incurred ¢/kwh Line 37 / Line 38 * 100 0.003 0.018 0.022 0.035 40 Projected SC Retail Sales kWh 462,889,901 459,376,756 502,773,736 580,364,203 8,418,908,692 41 SC Environmental Costs Line 39 * Line 40/ 100 13,137$ 83,774$ 109,402$ 204,919$ 2,494,074$ 42 Residential Environmental Cost Allocated by Firm CP Line 41 * Line 1 7,737$ 49,336$ 64,429$ 120,681$ 1,483,577$

43 Projected SC Residential kWh Sales 178,105,018 129,239,846 149,734,652 197,082,411 2,757,676,807 44 SC Residential Environmental Costs Incurred ¢/kwh Line 42 / Line 43 * 100 0.004 0.038 0.043 0.061 45 SC Residential Environmental Costs Billed ¢/kwh 2015-1-E 0.073 0.073 0.073 0.073

46 SC Residential Environmnental Costs Over / (Under) Recovery (Line 45 - Line 44) * Line 43 / 100 123,085$ 45,593$ 45,554$ 24,081$ 335,979$ 47 Cumulative SC Residential Environmental Costs Over / (Under) Recovery Line 46 + Prior Month Cum. Bal 269,839$ 315,433$ 360,987$ 385,068$ 385,068$ 48 Adjustment(s) -$


50 SC Projected Residential kWh Sales July 2016 - June 2017 2,239,987,48351 SC Projected Residential Environmental Fuel Cost ¢/kWh (-Line 49 / Line 50 * 100) (0.017)

Exhibit 4Page 2a of 3

DOCKET NO 2016-1-E

Line No. General Service (non demand)1 Winter 2015 Firm Coincident Peak (CP) kWs 5.70%2 Winter 2014 Firm Coincident Peak (CP) kWs 4.92%




7 Total System Sales kWh 4,845,390,809 3,757,959,729 3,628,900,408 4,978,488,628 5,346,810,378 5,985,422,750 8 Environmental System Costs Incurred ¢/kwh Line 6 / Line 7 * 100 0.030 0.025 0.051 0.057 0.058 0.045 9 SC Retail Sales kWh 570,749,238 463,754,149 420,603,466 578,289,954 607,719,653 653,631,427

10 SC Environmental Costs Line 8 * Line 9 / 100 169,930$ 117,837$ 212,773$ 327,404$ 353,910$ 291,794$ 11 General Service (non-demand) Environmental Cost Allocated by Firm CP Line 10 * Line 2 8,359$ 5,797$ 10,467$ 16,106$ 17,410$ 14,354$ 12 General Service (non-demand) kWh Sales 26,606,311 19,929,445 19,896,310 27,223,146 32,425,658 31,395,925 13 General Service (non-demand) Environmental Costs Incurred ¢/kwh Line 11 / Line 12 * 100 0.031 0.029 0.053 0.059 0.054 0.046 14 General Service (non-demand) Environmental Costs Billed ¢/kwh 2014-1-E / 2015-1-E 0.039 0.039 0.039 0.039 0.040 0.040

15 General Service (non-demand) Environmental Costs Over / (Under) Recovery (Line 14 - Line 13) * Line 12/ 100 2,017$ 1,975$ (2,707)$ (5,489)$ (4,440)$ (1,796)$ 16 Prior Year Balance and Misc. Adjustment(s) Prior Year Annual Filing 17,644$

17 Cumulative SC General Service (non-demand) Environmental Costs Over / (Under) Recovery Line 15 + Prior Month Cum Bal 19,661$ 21,636$ 18,929$ 13,440$ 9,000$ 7,204$



18 Total Reagents 1,598,089$ 1,099,582$ 901,137$ 452,022$ 1,341,488$ 1,319,097$ 20,851,608$ 19 Emission Allowances 5,450 4,940 (55,594) 2,072 - 5,930 (106,840) 20 Off-System Sales (208,940) (208,309) (119,912) (109,062) (152,996) (127,616) (2,159,740) 21 Net Environmental Costs Sum Lines 18 thru 20 1,394,599$ 896,213$ 725,631$ 345,032$ 1,188,492$ 1,197,411$ 18,585,028$

22 Total System Sales 5,526,400,413 4,506,558,036 4,068,338,456 4,554,249,791 5,548,083,471 5,382,673,888 58,129,276,757 23 Environmental System Costs Incurred ¢/kwh Line 21 / Line 22 * 100 0.025 0.020 0.018 0.008 0.021 0.022 24 SC Retail Sales kWh 560,668,824 488,426,474 474,177,711 438,667,815 555,252,619 601,562,765 6,413,504,095 25 SC Environmental Costs Line 23 * Line 24 / 100 141,486$ 97,133$ 84,575$ 33,234$ 118,944$ 133,822$ 2,082,841$ 26 General Service (non demand) Environmental Cost Allocated by Firm CP Line 25 * Line 2 (or line 1) 6,960$ 4,778$ 4,160$ 1,635$ 6,784$ 7,632$ 104,442$ 27 General Service (non-demand) kWh Sales 30,858,252 22,008,427 17,208,126 21,028,126 24,359,429 24,957,497 297,896,65228 General Service (non-demand) Environmental Costs Incurred ¢/kwh Line 26 / Line 27 * 100 0.023 0.022 0.024 0.008 0.028 0.031 0.035 29 General Service (non-demand) Environmental Costs Billed ¢/kwh 2015-1-E 0.040 0.040 0.040 0.040 0.040 0.040

30 General Service (non-demand) Environmnental Costs Over / (Under) Recovery (Line 29 - Line 28) * Line 27 / 100 5,383$ 4,025$ 2,723$ 6,776$ 2,860$ 2,351$ 13,678$

31 Cumulative SC General Service (non-demand) Environmental Costs Over / (Under) Recovery Line 30 + Prior Month Cum Bal 12,587$ 16,612$ 19,335$ 26,111$ 28,971$ 31,322$ 31,322$ 32 Adjustment(s) -$



CALCULATION OF ENVIRONMENTAL OVER / (UNDER) RECOVERY - GENERAL SERVICE (NON-DEMAND)ACTUAL AND ESTIMATED COSTS AND REVENUES MARCH 2015 - JUNE 2016



CALCULATION OF ENVIRONMENTAL OVER / (UNDER) RECOVERY - GENERAL SERVICE (NON-DEMAND)ACTUAL AND ESTIMATED COSTS AND REVENUES MARCH 2015 - JUNE 2016


DOCKET NO 2016-1-EEstimated Estimated Estimated Estimated Sixteen Months

March April May June Ended Line No. Description Reference 2016 2016 2016 2016 June 2016


38 Projected Total System Sales 4,720,617,141 4,312,137,696 4,721,331,352 5,515,688,799 77,399,051,745 39 Environmental System Costs Incurred ¢/kwh Line 37 / Line 38 * 100 0.003 0.018 0.022 0.035 40 Projected SC Retail Sales kWh 462,889,901 459,376,756 502,773,736 580,364,203 8,418,908,692 41 SC Environmental Costs Line 39 * Line 38 / 100 13,137$ 83,774$ 109,402$ 204,919$ 2,494,074$ 42 General Service (non demand) Environmental Cost Allocated by Firm CP Line 41 * Line 1 749$ 4,778$ 6,239$ 11,687$ 127,895$

43 Projected General Service (non-demand) kWh Sales 22,659,459 20,047,256 22,391,158 24,854,739 387,849,263.81 44 General Service (non-demand) Environmental Costs Incurred ¢/kwh Line 43 / Line 44 *100 0.003 0.024 0.028 0.047 45 General Service (non-demand) Environmental Costs Billed ¢/kwh 2015-1-E 0.040 0.040 0.040 0.040

46 General Service (non-demand) Environmnental Costs Over / (Under) Recovery (Line 46 - Line 45) * Line 44 / 100 8,315$ 3,241$ 2,717$ (1,745)$ 26,207$

47 Cumulative SC General Service (non-demand) Environmental Costs Over / (Under) Recovery Line 47 + Prior Month Cum. Bal 39,637$ 42,878$ 45,595$ 43,851$ 43,851$ 48 Adjustment(s) -$


50 SC Projected General Service (non-demand) kWh Sales July 2016 - June 2017 270,532,255

51SC General Service (non-demand) Environmental Increment / (Decrement) Calculated Rate (¢/kwh) (-Line 49 / Line 50 * 100) (0.016)

Exhibit 4

Page 3a of 3DOCKET NO 2016-1-E

Line No. General Service (demand)1 Winter 2015 Firm Coincident Peak (CP) kWs 35.41%2 Winter 2014 Firm Coincident Peak (CP) kWs 35.38%




7 Total System Sales kWh 4,845,390,809 3,757,959,729 3,628,900,408 4,978,488,628 5,346,810,378 5,985,422,750 8 Environmental System Costs Incurred ¢/kwh Line 6 / Line 7 * 100 0.030 0.025 0.051 0.057 0.058 0.045 9 SC Retail Sales kWh 570,749,238 463,754,149 420,603,466 578,289,954 607,719,653 653,631,427

10 SC Environmental Costs Line 8 * Line 9 / 100 169,930$ 117,837$ 212,773$ 327,404$ 353,910$ 291,794$ 11 SC General Service (demand) Environmental Cost Allocated by Firm CP Line 10 * Line 2 (or Line 1) 60,124$ 41,693$ 75,283$ 115,841$ 125,220$ 103,242$ 12 SC General Service (Demand) kW Sales 716,188 622,719 626,808 765,123 673,007 709,940 13 SC General Service (demand) Environmental Costs Incurred ¢ / kW Line 11 / Line 12 * 100 8 7 12 15 19 15 14 SC General Service (demand) Environmental Costs Billed ¢ / kW 2014-1-E / 2015-1-E 14 14 14 14 10 10

15 SC General Service (demand) Environmnental Costs Over / (Under) Recovery (Line 14 - Line 13) * Line 12 / 100 40,142$ 45,488$ 12,470$ (8,724)$ (57,919)$ (32,248)$ 16 Prior Year Balance and Misc. Adjustment(s) Prior Year Annual Filing (6,101)$ 17 Cumulative SC Environmental Costs Over / (Under) Recovery Line 15 + Prior Month Cum Bal 34,041$ 79,529$ 91,999$ 83,275$ 25,356$ (6,892)$



18 Total Reagents 1,598,089$ 1,099,582$ 901,137$ 452,022$ 1,341,488$ 1,319,097$ 20,851,608$ 19 Emission Allowances 5,450 4,940 (55,594) 2,072 - 5,930 (106,840) 20 Off-System Sales (208,940) (208,309) (119,912) (109,062) (152,996) (127,616) (2,159,740) 21 Net Environmental Costs Sum Lines 18 thru 20 1,394,599$ 896,213$ 725,631$ 345,032$ 1,188,492$ 1,197,411$ 18,585,028$

22 Total System Sales kWh 5,526,400,413 4,506,558,036 4,068,338,456 4,554,249,791 5,548,083,471 5,382,673,888 58,129,276,757 23 Environmental System Costs Incurred ¢/kwh Line 21 / Line 22 * 100 0.025 0.020 0.018 0.008 0.021 0.022 0.032 24 SC Retail Sales kWh 560,668,824 488,426,474 474,177,711 438,667,815 555,252,619 601,562,765 6,413,504,095 25 SC Environmental Costs Line 23 * Line 24 / 100 141,486$ 97,133$ 84,575$ 33,234$ 118,944$ 133,822$ 2,050,518$ 26 General Service (demand) Environmental Cost Allocated by Firm CP Line 25 * Line 2 (or line 1) 50,060$ 34,367$ 29,924$ 11,759$ 42,112$ 47,380$ 737,004$ 27 SC General Service (Demand) kW Sales 728,426 664,967 639,469 655,825 696,329 712,432 8,211,23428 SC General Service (demand) Environmental Costs Incurred ¢ / kW Line 26 / Line 27 * 100 7 5 5 2 6 7 9 29 SC General Service (demand) Environmental Costs Billed ¢ / kW 10 10 10 10 10 10 10

30 SC General Service (demand) Environmnental Costs Over / (Under) Recovery (Line 29 - Line 28) * Line 27 / 100 22,782$ 32,129$ 34,023$ 53,824$ 27,521$ 23,863$ 193,351$

31 Cumulative SC General Service (demand) Environmental Costs Over / (Under) Recovery Line 30 + Prior Month Cum Bal 15,890$ 48,019$ 82,042$ 135,866$ 163,387$ 187,250$ 187,250$ 32 Adjustment(s) -$



CALCULATION OF ENVIRONMENTAL OVER / (UNDER) RECOVERY-GENERAL SERVICE (DEMAND)ACTUAL AND ESTIMATED COSTS AND REVENUES MARCH 2015 - JUNE 2016



CALCULATION OF ENVIRONMENTAL OVER / (UNDER) RECOVERY-GENERAL SERVICE (DEMAND)ACTUAL AND ESTIMATED COSTS AND REVENUES MARCH 2015 - JUNE 2016


DOCKET NO 2016-1-EEstimated Estimated Estimated Estimated Sixteen Months

March April May June Ended Line No. Description Reference 2016 2016 2016 2016 June 2016


38 Projected Total System Sales kWh 4,720,617,141 4,312,137,696 4,721,331,352 5,515,688,799 77,399,051,745 39 Environmental System Costs Incurred ¢/kwh Line 37 / Line 38 * 100 0.003 0.018 0.022 0.035 40 Projected SC Retail Sales kWh 462,889,901 459,376,756 502,773,736 580,364,203 8,418,908,692 41 SC Environmental Costs Line 39 * Line 40 / 100 13,137$ 83,774$ 109,402$ 204,919$ 2,461,751$ 42 General Service (demand) Environmental Cost Allocated by Firm CP Line 41 * Line 1 4,651$ 29,660$ 38,734$ 72,552$ 882,601$ 43 Projected SC General Service (Demand) kW Sales 678,920 639,865 687,073 667,260 10,884,351 44 SC General Service (demand) Environmental Costs Incurred ¢ / kW Line 42 / Line 43 * 100 1 5 6 11 45 SC General Service (demand) Environmental Costs Billed ¢ / kW 2015-1-E 10 10 10 10

46 SC General Service (demand) Environmnental Costs Over / (Under) Recovery (Line 45 - Line 44) * Line 43 / 100 63,241$ 34,326$ 29,973$ (5,826)$ 315,065$

47 Cumulative SC General Service (demand) Environmental Costs Over / (Under) Recovery Line 46 + Prior Month Cum Bal 250,491$ 284,817$ 314,790$ 308,964$ 308,964$ 48 Adjustment(s) -$


50 SC Projected General Service (demand) kW Sales July 2016 - June 2017 7,936,241

51 SC General Service (demand) Environmental Increment / (Decrement) Calculated Rate (¢/kwh) (-Line 49 / Line 50*100) (4)


Winter 2015 FirmLine No. Class Coincident Peak (CP) KWs CP %

1 Residential 768,462 58.89%2 General Service (non demand) 74,419 5.70%3 General Service (demand) 461,990 35.41%

Total SC 1,304,870 100.00%


4 Total Reagents 2,363,847$ 2,456,661$ 1,637,072$ 1,187,950$ 1,350,902$ 2,860,901$ 5 Emission Allowances 13,802 14,148 10,065 7,397 7,302 12,846 6 Estimated Off-system Sales (19,962) (10,960) (2,233) (155) (10,422) (20,173) 7 Net Environmental Costs Sum Lines 4 through 6 2,357,687$ 2,459,849$ 1,644,904$ 1,195,192$ 1,347,782$ 2,853,574$ 8 Projected Total System Sales 6,131,619,391 6,070,851,379 5,145,308,592 4,506,286,142 4,666,907,710 5,612,506,2149 Environmental System Costs Incurred ¢/kwh Line 7 / Line 8 * 100 0.038 0.041 0.032 0.027 0.029 0.051

10 Projected SC Retail Sales 619,212,087 627,973,134 524,238,038 478,354,413 497,024,039 537,586,537 11 SC Environmental Costs Line 9 * Line 10 / 100 238,095 254,449 167,594 126,873 143,538 273,326



12 Total Reagents 2,627,822$ 2,054,625$ 1,485,318$ 1,042,791$ 880,309$ 1,772,582$ 21,720,780$ 13 Emission Allowances 10,610 9,099 7,441 5,357 4,996 8,662 111,725 14 Estimated Off-system Sales (81,910) (32,518) (12,390) (3,412) (11,671) (4,472) (210,278) 15 Net Environmental Costs Sum Lines 12 thru 14 2,556,522$ 2,031,206$ 1,480,369$ 1,044,736$ 873,634$ 1,776,772$ 21,622,227$ 16 Projected Total System Sales 5,790,398,433 5,046,328,688 4,928,235,091 4,343,473,542 4,764,742,801 5,570,177,980 62,576,835,96217 Environmental System Costs Incurred ¢/kwh line 15 / Line 16 *100 0.044 0.040 0.030 0.024 0.018 0.032 0.035 18 Projected SC Retail Sales 593,952,477 525,116,572 527,662,486 463,283,721 507,225,831 586,725,135 6,488,354,470 19 SC Environmental Costs Line 17 * Line 18 / 100 262,236 211,366 158,502 111,434 93,002 187,153 2,241,927

SC Environmental Costs Allocated on Firm CP kWs20 Residential Total Line 19 * Line 1 1,320,311$ 21 General Service (non demand) Total Line 19 * Line 2 127,860 22 General Service (demand) Total Line 19 * Line 3 793,755 23 Total SC Sum Lines 20 through 22 2,241,927$

Projected SC Retail Sales kWh (July 2016-June 2017)24 Residential 2,239,987,48325 General Service (non demand) 270,532,25526 General Service (demand) 3,881,738,76527 Lighting 96,095,96828 Total SC Sum Lines 24 through 27 6,488,354,470

Projected Average Environmental Fuel Cost ¢/kWh29 Residential Line 20 / Line 24 * 100 0.05930 General Service (non demand) Line 21 / Line 26 * 100 0.047

Projected Average Environmental Fuel Cost ¢/kW31 Projected SC KW sales (General Service (demand) 7,936,241 32 General Service (demand) Line 22 / Line 31 * 100 10 ¢/kW


PROJECTED BILLING PERIOD ENVIRONMENTAL COSTSFOR THE 12 MONTHS JULY 2016 THROUGH JUNE 2017


Residential Adjustment Factor

(1) Billed kWh (12ME 2/29/16) Per Books 2,130,603,359

(2) Billed RECD kWh (12ME 2/29/16) 322,857,966 (a)

(3) RECD kWh Percent of Total Billed Line 2 / Line 1 15.1534%

(4) RECD Discount RECD Discount 5.0000% (b)

(5) RECD Impact (Weighted Discount) Line 3 X Line 4 0.7577%

Notes:(a) Energy billed and discounted pursuant to Residential Energy Conservation Discount, Rider RECD-2C.(b) Five-percent discount provided under Residential Energy Conservation Discount, Rider RECD-2C.


REVENUE ADJUSTMENT FACTOR FOR RECDFOR THE 12 MONTHS ENDING MARCH 31, 2015 TO FEBRUARY 29, 2016


DOCKET NO 2016-1-E




3 Total PURPA Purchased Power Capacity Costs 2,398,268$ 3,022,484$ 2,668,157$ 3,806,691$ 3,905,862$ 3,797,331$

4 Total System kWh Sales 4,845,390,809 3,757,959,729 3,628,900,408 4,978,488,628 5,346,810,378 5,985,422,750 5 PURPA Purchased Power Costs Incurred (¢/kWh) Line 3 / Line 4 * 100 0.0495 0.0804 0.0735 0.0765 0.0731 0.0634 6 SC Retail Sales kWh 570,749,238 463,754,149 420,603,466 578,289,954 607,719,653 653,631,427 7 SC PURPA Purchased Power Costs Line 5 * Line 6 / 100 282,497$ 372,992$ 309,250$ 442,177$ 443,941$ 414,683$ 8 Residential PURPA Purchased Power Allocated by Firm CP Line 7 * Line 2 (or Line 1) 168,648$ 222,673$ 184,619$ 263,975$ 265,028$ 247,562$ 9 SC Residential kWh Sales 221,639,208 131,947,547 112,305,130 182,767,188 222,381,186 207,728,757

10 SC Residential PURPA Purchased Power Cost Incurred (¢/kWh) Line 8 / Line 9 * 100 0.076 0.169 0.164 0.144 0.119 0.11911 SC Residential Non-Fuel Base Rates Billed (¢/kWh) 0.023 0.023 0.023 0.023 0.142 0.142

12 SC PURPA Purchased Power Over / (Under) Recovery (Line 11 - Line 10)*Line 9 /100 (117,663)$ (192,334)$ (158,805)$ (221,949)$ 50,533$ 47,165$ 13 Prior Year Balance and Misc. Adjustment(s) Prior Year Annual Filing (1,026,881)$

14 Cumulative SC Residential PURPA Purchased Power Over / (Under) Recovery Line 12 + Prior Month Cum Bal (1,144,544)$ (1,336,878)$ (1,495,683)$ (1,717,632)$ (1,667,099)$ (1,619,934)$



15 Total PURPA Purchased Power Capacity Costs 3,069,199$ 3,155,940$ 2,278,754$ 2,203,998$ 2,098,760$ 3,308,313$ 35,713,757$

16 Total System kWh Sales 5,526,400,413 4,506,558,036 4,068,338,456 4,554,249,791 5,548,083,471 5,382,673,888 58,129,276,757 17 PURPA Purchased Power Costs Incurred (¢/kWh) Line 15 / Line 16 * 100 0.0555 0.0700 0.0560 0.0484 0.0378 0.0615 18 SC Retail Sales kWh 560,668,824 488,426,474 474,177,711 438,667,815 555,252,619 601,562,765 6,413,504,095 19 SC PURPA Purchased Power Costs Line 17 * Line 18 / 100 311,379$ 342,045$ 265,596$ 212,290$ 210,044$ 369,734$ 3,976,628$ 20 Residential PURPA Purchased Power Allocated by Firm CP Line 19 * Line 1 185,890$ 204,197$ 158,558$ 126,735$ 123,699$ 217,743$ 2,369,327$

21 SC Residential kWh Sales 195,480,622 133,938,974 108,712,645 157,778,056 209,289,664 219,545,903 2,103,514,880 22 SC Residential PURPA Purchased Power Cost Incurred (¢/kWh) Line 20 / Line 21 * 100 0.095 0.152 0.146 0.080 0.059 0.09923 SC Residential Non-Fuel Base Rates Billed (¢/kWh) 2015-1-E 0.142 0.142 0.142 0.142 0.142 0.142

24 SC PURPA Purchased Power Over / (Under) Recovery (Line 23 - Line 22)*Line 21 /100 91,459$ (14,200)$ (4,318)$ 97,215$ 173,023$ 93,950$ (155,924)$ 25 Cumulative SC Residential PURPA Purchased Power Over / (Under) Recovery Line 24 + Prior Month Cum Bal (1,528,475)$ (1,542,675)$ (1,546,993)$ (1,449,778)$ (1,276,755)$ (1,182,805)$ (1,182,805)$ 26 Adjustment(s)

27 Adjusted Cumulative SC Residential PURPA Purchased Power Over / (Under) Recovery Line 25 + Line 26 (1,182,805)$


CALCULATION OF PURPA PURCHASED POWER CAPACITY COSTS OVER / (UNDER) RECOVERY - RESIDENTIALACTUAL AND ESTIMATED COSTS AND REVENUES MARCH 2015 - JUNE 2016



CALCULATION OF PURPA PURCHASED POWER CAPACITY COSTS OVER / (UNDER) RECOVERY - RESIDENTIALACTUAL AND ESTIMATED COSTS AND REVENUES MARCH 2015 - JUNE 2016


DOCKET NO 2016-1-E



28 Total PURPA Purchased Power Capacity Costs 3,168,497$ 3,666,894$ 3,666,894$ 3,666,894$ 49,882,935$

29 Projected Total System Sales 4,720,617,141 4,312,137,696 4,721,331,352 5,515,688,799 77,399,051,745 30 PURPA Purchased Power Costs Incurred (¢/kWh) Line 28 / Line 29 * 100 0.0671 0.0850 0.0777 0.0665 31 Projected SC Retail Sales kWh 462,889,901 459,376,756 502,773,736 580,364,203 8,418,908,692 32 SC PURPA Purchased Power Costs Line 30 * Line 31 / 100 310,694$ 390,638$ 390,487$ 385,833$ 5,454,280$ 33 Residential PURPA Purchased Power Allocated by Firm CP Line 32 * Line 1 182,973$ 230,054$ 229,965$ 227,224$ 3,239,543$

34 Projected SC Residential kWh Sales 178,105,018 129,239,846 149,734,652 197,082,411 2,757,676,807 35 SC Residential PURPA Purchased Power Cost Incurred (¢/kWh) Line 33 / Line 34 * 100 0.103 0.178 0.154 0.11536 SC Residential Non-Fuel Base Rates Billed (¢/kWh) 2015-1-E 0.142 0.142 0.142 0.142

37 SC PURPA Purchased Power Over / (Under) Recovery (Line 36 - Line 35)*Line 34 /100 69,832$ (46,609)$ (17,429)$ 52,518$ (97,612)$ 38 Cumulative SC Residential PURPA Purchased Power Over / (Under) Recovery Line 37 + Prior Month Cum Bal (1,112,973)$ (1,159,582)$ (1,177,011)$ (1,124,493)$ (1,124,493)$ 39 Adjustment(s)

40 Adjusted Cumulative SC Residential PURPA Purchased Power Over / (Under) Recovery Line 38 + Line 39 (1,124,493)$

41 SC Projected Residential kWh Sales July 2016 - June 2017 2,239,987,483 42 SC Projected Residential PURPA Purchased Power Capacity Fuel Cost ¢/kWh (-Line 40 / Line 41 * 100) 0.050


DOCKET NO 2016-1-E





4 Total System kWh Sales 4,845,390,809 3,757,959,729 3,628,900,408 4,978,488,628 5,346,810,378 5,985,422,750 5 PURPA Purchased Power System Costs Incurred (¢/kWh) Line 3 / Line 4 * 100 0.0495 0.0804 0.0735 0.0765 0.0731 0.0634 6 SC Retail Sales kWh 570,749,238 463,754,149 420,603,466 578,289,954 607,719,653 653,631,427 7 SC PURPA Purchased Power Costs Incurred Line 5 * Line 6 / 100 282,497$ 372,992$ 309,250$ 442,177$ 443,941$ 414,683$ 8 General Service (Non-Demand) PURPA Purchased Power Allocated by Firm CP Line 7 * Line 2 (or Line 1) 13,897$ 18,349$ 15,213$ 21,752$ 21,839$ 20,399$

9 SC General Service (Non-Demand)kWh Sales 26,606,311 19,929,445 19,896,310 27,223,146 32,425,658 31,395,925

10 SC General Service (Non-Demand)PURPA Purchased Power Cost Incurred (¢/kWh) Line 8 / Line 9 * 100 0.052 0.092 0.076 0.080 0.067 0.065 11 SC General Service (Non-Demand) Non-Fuel Base Rates Billed (¢/kWh) 0.023 0.023 0.023 0.023 0.106 0.106

12 SC PURPA Purchased Power Over / (Under) Recovery (Line 11 - Line 10)*Line 9 /100 (7,777)$ (13,765)$ (10,637)$ (15,491)$ 12,533$ 12,880$ 13 Prior Year Balance and Misc. Adjustment(s) Prior Year Annual Filing (112,468)$

14 Cumulative SC General Service (Non-Demand) PURPA Purchased Power Over / (Under) Recovery Line 12 + Prior Month Cum Bal (120,245)$ (134,010)$ (144,647)$ (160,138)$ (147,605)$ (134,725)$

Actual Actual Actual Actual Actual Actual Review Period

September October November December January February Twelve MonthsLine No. Description Reference 2015 2015 2015 2015 2016 2016 Ended Feb-16


16 Total System kWh Sales 5,526,400,413 4,506,558,036 4,068,338,456 4,554,249,791 5,548,083,471 5,382,673,888 58,129,276,757 17 PURPA Purchased Power System Costs Incurred (¢/kWh) Line 15 / Line 16 * 100 0.0555 0.0700 0.0560 0.0484 0.0378 0.0615 0.0614 18 SC Retail Sales kWh 560,668,824 488,426,474 474,177,711 438,667,815 555,252,619 601,562,765 6,413,504,095 19 SC PURPA Purchased Power Costs Incurred Line 17 * Line 18 / 100 311,379$ 342,045$ 265,596$ 212,290$ 210,044$ 369,734$ 3,976,628$ 20 General Service (Non-Demand) PURPA Purchased Power Allocated by Firm CP Line 19 * Line 1 15,318$ 16,826$ 13,065$ 10,443$ 11,979$ 21,085$ 200,165$

21 SC General Service (Non-Demand)kWh Sales 30,858,252 22,008,427 17,208,126 21,028,126 24,359,429 24,957,497 297,896,652 22 SC General Service (Non-Demand)PURPA Purchased Power Cost Incurred (¢/kWh) Line 20 / Line 21 * 100 0.050 0.076 0.076 0.050 0.049 0.084 0.06723 SC General Service (Non-Demand) Non-Fuel Base Rates Billed (¢/kWh) 2015-1-E 0.106 0.106 0.106 0.106 0.106 0.106

24 SC PURPA Purchased Power Over / (Under) Recovery (Line 23 - Line 22)*Line 21 /100 17,392$ 6,503$ 5,175$ 11,847$ 13,942$ 5,369$ 37,971$

25 Cumulative SC General Service (Non-Demand) PURPA Purchased Power Over / (Under) Recovery Line 24 + Prior Month Cum Bal (117,333)$ (110,830)$ (105,655)$ (93,808)$ (79,866)$ (74,497)$ (74,497)$ 26 Adjustment(s)

27 Adjusted Cumulative SC Residential PURPA Purchased Power Over / (Under) Recovery Line 25 + Line 26 (74,497)$


CALCULATION OF PURPA PURCHASED POWER CAPACITY COSTS OVER / (UNDER) RECOVERY - GENERAL SERVICE (NON-DEMAND)ACTUAL AND ESTIMATED COSTS AND REVENUES MARCH 2015 - JUNE 2016



CALCULATION OF PURPA PURCHASED POWER CAPACITY COSTS OVER / (UNDER) RECOVERY - GENERAL SERVICE (NON-DEMAND)ACTUAL AND ESTIMATED COSTS AND REVENUES MARCH 2015 - JUNE 2016


DOCKET NO 2016-1-E




29 Projected Total System Sales 4,720,617,141 4,312,137,696 4,721,331,352 5,515,688,799 77,399,051,745 30 PURPA Purchased Power System Costs Incurred (¢/kWh) Line 28 / Line 29 * 100 0.0671 0.0850 0.0777 0.0665 31 Projected SC Retail Sales kWh 462,889,901 459,376,756 502,773,736 580,364,203 8,418,908,692 32 SC PURPA Purchased Power Costs Incurred Line 30 * Line 31 / 100 310,694$ 390,638$ 390,487$ 385,833$ 5,454,280$ 33 General Service (Non-Demand) PURPA Purchased Power Allocated by Firm CP Line 32 * Line 1 17,719$ 22,279$ 22,270$ 22,005$ 284,437$

34 Projected SC General Service (Non-Demand)kWh Sales 22,659,459 20,047,256 22,391,158 24,854,739 387,849,264 35 SC General Service (Non-Demand)PURPA Purchased Power Cost Incurred (¢/kWh) Line 33 / Line 34 * 100 0.078 0.111 0.099 0.08936 SC General Service (Non-Demand) Non-Fuel Base Rates Billed (¢/kWh) 2015-1-E 0.106 0.106 0.106 0.106

37 SC PURPA Purchased Power Over / (Under) Recovery (Line 36 - Line 35)*Line 34 /100 6,300$ (1,029)$ 1,465$ 4,341$ 49,048$

38 Cumulative SC General Service (Non-Demand) PURPA Purchased Power Over / (Under) Recovery Line 37 + Prior Month Cum Bal (68,197)$ (69,226)$ (67,761)$ (63,420)$ (63,420)$ 39 Adjustment(s)

40 Adjusted Cumulative SC Residential PURPA Purchased Power Over / (Under) Recovery Line 38 + Line 39 (63,420)$

41 SC Projected General Service (Non-Demand)kWh Sales July 2016 - June 2017 270,532,255 42 SC Projected General Service (Non-Demand)PURPA Purchased Power Capacity Fuel Cost ¢/kWh (-Line 40 / Line 41 * 100) 0.023


DOCKET NO 2016-1-E





4 Total System kWh Sales 4,845,390,809 3,757,959,729 3,628,900,408 4,978,488,628 5,346,810,378 5,985,422,750 5 PURPA Purchased Power Capacity Costs Incurred (¢/kWh) Line 3 / Line 4 * 100 0.0495 0.0804 0.0735 0.0765 0.0731 0.0634 6 SC Retail Sales kWh 570,749,238 463,754,149 420,603,466 578,289,954 607,719,653 653,631,427 7 SC PURPA Purchased Power Capacity Costs Line 5 * Line 6 / 100 282,497.25$ 372,992$ 309,250$ 442,177$ 443,941$ 414,683$

8 SC General Service (Demand) PURPA Purchased Power Capacity Allocated by Firm CP Line 7 * Line 2 (or Line 1) 99,952$ 131,971$ 109,418$ 156,450$ 157,074$ 146,722$

9 SC General Service (Demand) kW Sales 716,188 622,719 626,808 765,123 673,007 709,940

10 SC General Service (Demand) PURPA Purchased Power Capacity Costs Incurred (¢/kW) Line 8 / Line 9 * 100 14 21 17 20 23 21

11 SC General Service (Demand) Non-Fuel Base Rates Billed (¢/kW) 10 11 10 11 21 21

12 SC General Service (Demand) PURPA Purchased Power Capacity Costs Over / (Under) Recovery (Line 12 - Line 11) * Line 9 /100 (27,594)$ (62,059)$ (44,845)$ (73,615)$ (15,743)$ 2,365$ 13 Prior Year Balance and Misc. Adjustment(s) Prior Year Annual Filing (676,800)$

14Cumulative SC General Service (Demand) PURPA Purchased Power Capacity Costs Over / (Under) Recovery Line 13 + Prior Month Cum Bal (704,394)$ (766,453)$ (811,298)$ (884,913)$ (900,656)$ (898,291)$




16 Total System kWh Sales 5,526,400,413 4,506,558,036 4,068,338,456 4,554,249,791 5,548,083,471 5,382,673,888 58,129,276,757 17 PURPA Purchased Power Capacity Costs Incurred (¢/kWh) Line 15 / Line 16 * 100 0.0555 0.0700 0.0560 0.0484 0.0378 0.0615 18 SC Retail Sales kWh 560,668,824 488,426,474 474,177,711 438,667,815 555,252,619 601,562,765 6,413,504,095 19 SC PURPA Purchased Power Capacity Costs Line 17 * Line 18/ 100 311,379$ 342,045$ 265,596$ 212,290$ 210,044$ 369,734$ 3,976,628$

20 SC General Service (Demand) PURPA Purchased Power Capacity Allocated by Firm CP Line 19 * Line 1 110,171$ 121,021$ 93,972$ 75,111.96$ 74,366$ 130,905$ 1,407,135$

21 SC General Service (Demand) kW Sales 728,426 664,967 639,469 655,825 696,329 712,432 8,211,234

22 SC General Service (Demand) PURPA Purchased Power Capacity Costs Incurred (¢/kW) Line 20 / Line 21 * 100 15 18 15 11 11 18

23 SC General Service (Demand) Non-Fuel Base Rates Billed (¢/kW) 2015-1-E 21 21 21 21 21 21

24 SC General Service (Demand) PURPA Purchased Power Capacity Costs Over / (Under) Recovery (Line 23 - Line 22) * Line 21 / 100 42,798$ 18,622$ 40,317$ 62,626$ 69,770$ 18,303$ 30,945$

25Cumulative SC General Service (Demand) PURPA Purchased Power Capacity Costs Over / (Under) Recovery Line 24 + Prior Month Cum Bal (855,493)$ (836,871)$ (796,554)$ (733,928)$ (664,158)$ (645,855)$ (645,855)$

26 Adjustment(s)

27Cumulative SC General Service (Demand) PURPA Purchased Power Capacity Costs Over / (Under) Recovery Line 27 + Line 28 (645,855)$


CALCULATION OF PURPA PURCHASED POWER CAPACITY COSTS OVER / (UNDER) RECOVERY - GENERAL SERVICE (DEMAND)ACTUAL AND ESTIMATED COSTS AND REVENUES MARCH 2015 - JUNE 2016



CALCULATION OF PURPA PURCHASED POWER CAPACITY COSTS OVER / (UNDER) RECOVERY - GENERAL SERVICE (DEMAND)ACTUAL AND ESTIMATED COSTS AND REVENUES MARCH 2015 - JUNE 2016


DOCKET NO 2016-1-E




29 Projected Total System Sales 4,720,617,141 4,312,137,696 4,721,331,352 5,515,688,799 77,399,051,745 30 PURPA Purchased Power Capacity Costs Incurred (¢/kWh) Line 28 / Line 29 * 100 0.0671 0.0850 0.0777 0.0665 31 Projected SC Retail Sales kWh 462,889,901 459,376,756 502,773,736 580,364,203 8,418,908,692 32 SC PURPA Purchased Power Capacity Costs Line 30 * Line 31 / 100 310,694$ 390,638$ 390,487$ 385,833$ 5,454,280$

33 SC General Service (Demand) PURPA Purchased Power Capacity Allocated by Firm CP Line 32 * Line 1 110,001$ 138,306$ 138,252$ 136,604$ 1,930,298$

34 Projected SC General Service (Demand) kW Sales 678,920 639,865 687,073 667,260 10,884,351

35 SC General Service (Demand) PURPA Purchased Power Capacity Costs Incurred (¢/kW) Line 33 / Line 34 * 100 16 22 20 20

36 SC General Service (Demand) Non-Fuel Base Rates Billed (¢/kW) 2015-1-E 21 21 21 21

37 SC General Service (Demand) PURPA Purchased Power Capacity Costs Over / (Under) Recovery (Line 36 - Line 35) * Line 34 / 100 32,600$ (3,908)$ 6,061$ 3,548$ 69,246$

38Cumulative SC General Service (Demand) PURPA Purchased Power Capacity Costs Over / (Under) Recovery Line 37 + Prior Month Cum Bal (613,255)$ (617,163)$ (611,102)$ (607,554)$ (607,554)$

39 Adjustment(s)

40Adjusted Cumulative SC General Service (Demand) PURPA Purchased Power Capacity Costs Over / (Under) Recovery Line 38 + Line 39 (607,554)$

41 SC Projected General Service (demand) kW Sales July 2016 - June 2017 7,936,241

42SC General Service (demand) Environmental Increment / (Decrement) Calculated Rate (¢/kwh) (-Line 40 / Line 41*100) 8


DOCKET NO 2016-1-E

Line No. Lighting1 Winter 2015 Firm Coincident Peak (CP) kWs 0.00%2 Winter 2014 Firm Coincident Peak (CP) kWs 0.00%




4 Total System kWh Sales 4,845,390,809 3,757,959,729 3,628,900,408 4,978,488,628 5,346,810,378 5,985,422,750 5 PURPA Purchased Power System Costs Incurred (¢/kWh) Line 3 / Line 4 * 100 0.0495 0.0804 0.0735 0.0765 0.0731 0.0634 6 SC Retail Sales kWh 570,749,238 463,754,149 420,603,466 578,289,954 607,719,653 653,631,427 7 SC PURPA Purchased Power Costs Incurred Line 5 * Line 6 / 100 282,497$ 372,992$ 309,250$ 442,177$ 443,941$ 414,683$ 8 SC Lighting PURPA Purchased Power Allocated by Firm CP Line 7 * Line 2 (or Line 1) -$ -$ -$ -$ -$ -$

9 SC Lighting kWh Sales 7,905,463 7,913,293 7,648,551 8,146,238 7,768,123 7,800,156

10 SC Lighting PURPA Purchased Power Cost Incurred (¢/kWh) Line 8 / Line 9 * 100 - - - - - - 11 SC Lighting Non-Fuel Base Rates Billed (¢/kWh) 0.023 0.023 0.023 0.023 (0.044) (0.044)

12 SC Lighting PURPA Purchased Power Over / (Under) Recovery (Line 11 - Line 10)*Line 9 /100 1,818$ 1,820$ 1,759$ 1,874$ (3,418)$ (3,432)$ 13 Prior Year Balance and Misc. Adjustment(s) Prior Year Annual Filing 16,391$

14 Cumulative SC Lighting PURPA Purchased Power Over / (Under) Recovery Line 12 + Prior Month Cum Bal 18,209$ 20,029$ 21,788$ 23,662$ 20,244$ 16,812$




16 Total System kWh Sales 5,526,400,413 4,506,558,036 4,068,338,456 4,554,249,791 5,548,083,471 5,382,673,888 58,129,276,757 17 PURPA Purchased Power System Costs Incurred (¢/kWh) Line 15 / Line 16 * 100 0.0555 0.0700 0.0560 0.0484 0.0378 0.0615 0.0614 18 SC Retail Sales kWh 560,668,824 488,426,474 474,177,711 438,667,815 555,252,619 601,562,765 6,413,504,095 19 SC PURPA Purchased Power Costs Incurred Line 17 * Line 18 / 100 311,379$ 342,045$ 265,596$ 212,290$ 210,044$ 369,734$ 3,976,628$ 20 SC Lighting PURPA Purchased Power Allocated by Firm CP Line 19 * Line 1 -$ -$ -$ -$ -$ -$ -$

21 SC Lighting kWh Sales 8,075,399 7,880,383 7,675,667 7,838,071 7,833,075 7,863,478 94,347,897 22 SC Lighting PURPA Purchased Power Cost Incurred (¢/kWh) Line 20 / Line 21 * 100 0.000 0.000 0.000 0.000 0.000 0.000 0.00023 SC Lighting Non-Fuel Base Rates Billed (¢/kWh) 2015-1-E (0.044) (0.044) (0.044) (0.044) (0.044) (0.044)

24 SC Lighting PURPA Purchased Power Over / (Under) Recovery (Line 23 - Line 22)*Line 21 /100 (3,553)$ (3,467)$ (3,377)$ (3,449)$ (3,447)$ (3,460)$ (20,332)$ 25 Cumulative SC Lighting PURPA Purchased Power Over / (Under) Recovery Line 24 + Prior Month Cum Bal 13,259$ 9,792$ 6,415$ 2,966$ (481)$ (3,941)$ (3,941)$ 26 Adjustment(s)

27 Adjusted Cumulative SC Lighting PURPA Purchased Power Over / (Under) Recovery Line 25 + Line 26 (3,941)$


CALCULATION OF PURPA PURCHASED POWER CAPACITY COSTS OVER / (UNDER) RECOVERY - LIGHTINGACTUAL AND ESTIMATED COSTS AND REVENUES MARCH 2015 - JUNE 2016

Line No. Lighting1 Winter 2015 Firm Coincident Peak (CP) kWs 0.00%2 Winter 2014 Firm Coincident Peak (CP) kWs 0.00%


CALCULATION OF PURPA PURCHASED POWER CAPACITY COSTS OVER / (UNDER) RECOVERY - LIGHTINGACTUAL AND ESTIMATED COSTS AND REVENUES MARCH 2015 - JUNE 2016


DOCKET NO 2016-1-E




29 Projected Total System Sales 4,720,617,141 4,312,137,696 4,721,331,352 5,515,688,799 77,399,051,745 30 PURPA Purchased Power System Costs Incurred (¢/kWh) Line 28 / Line 29 * 100 0.0671 0.0850 0.0777 0.0665 31 Projected SC Retail Sales kWh 462,889,901 459,376,756 502,773,736 580,364,203 8,418,908,692 32 SC PURPA Purchased Power Costs Incurred Line 30 * Line 31 / 100 310,694$ 390,638$ 390,487$ 385,833$ 5,454,280$ 33 SC Lighting PURPA Purchased Power Allocated by Firm CP Line 32 * Line 1 -$ -$ -$ -$ -$

34 Projected SC Lighting kWh Sales 7,802,806 7,525,256 7,993,191 8,602,346 126,271,495 35 SC Lighting PURPA Purchased Power Cost Incurred (¢/kWh) Line 33 / Line 34 * 100 0.000 0.000 0.000 0.00036 SC Lighting Non-Fuel Base Rates Billed (¢/kWh) 2015-1-E (0.044) (0.044) (0.044) (0.044)

37 SC Lighting PURPA Purchased Power Over / (Under) Recovery (Line 36 - Line 35)*Line 34 /100 (3,433)$ (3,311)$ (3,517)$ (3,785)$ (34,379)$ 38 Cumulative SC Lighting PURPA Purchased Power Over / (Under) Recovery Line 37 + Prior Month Cum Bal (7,374)$ (10,685)$ (14,203)$ (17,988)$ (17,988)$ 39 Adjustment(s) 17,988$

40 Adjusted Cumulative SC Lighting PURPA Purchased Power (Under) Recovery Amount Line 38 + Line 39 0$



1 Residential 768,462 58.89%2 General Service (Non-Demand) 74,419 5.70%3 General Service (Demand) 461,990 35.41%4 Lighting 0 0.00%5 Total SC 1,304,870 100.00%



7 Projected Total System Sales 6,131,619,391 6,070,851,379 5,145,308,592 4,506,286,142 4,666,907,710 5,612,506,214 8 PURPA Purchased Power System Costs Incurred (¢/Kwh) Line 6 / Line 7 *100 0.060 0.060 0.071 0.081 0.079 0.0659 Projected SC Retail Sales 619,212,087 627,973,134 524,238,038 478,354,413 497,024,039 537,586,537

10 SC Purchased Power Capacity Costs Line 8 * Line 9 /100 370,308$ 379,306$ 373,607$ 389,251$ 390,523$ 351,229$




12 Projected Total System Sales 5,790,398,433 5,046,328,688 4,928,235,091 4,343,473,542 4,764,742,801 5,570,177,980 62,576,835,962 13 PURPA Purchased Power System Costs Incurred (¢ per Kwh) Line 11 / Line 12 *100 0.075 0.086 0.088 0.099 0.091 0.077 0.07714 Projected SC Retail Sales 593,952,477 525,116,572 527,662,486 463,283,721 507,225,831 586,725,135 6,488,354,470 15 SC Purchased Power Capacity Costs Line 13 * Line 14 /100 442,588$ 448,990$ 461,978$ 460,221$ 459,323$ 454,488$ 4,965,523$

SC PURPA Purchased Power Capacity Costs Allocated on Firm CP kWs 16 Residential Total Line 15 * Line 1 2,924,286$ 17 General Service (Non-Demand) Total Line 15 * Line 2 283,191$ 18 General Service (Demand) Total Line 15 * Line 3 1,758,046$ 19 Lighting Total Line 15 * Line 4 -$ 20 Total SC Sum Lines 16 through 19 4,965,523$

Projected SC Retail Sales kWh (July 2016-June 2017)21 Residential 2,239,987,48322 General Service (Non-Demand) 270,532,25523 General Service (Demand) 3,881,738,76524 Lighting 96,095,96825 Total SC Sum Lines 21 through 24 6,488,354,470

SC PURPA Purchased Power Capacity Costs ¢/kWh26 Residential Line 16 / Line 21 * 100 0.13127 General Service (Non-Demand) Line 17 / Line 23 * 100 0.10528 Lighting Line 19 / Line 24 * 100 0.000

29 Projected SC KW Sales (General Service demand) 7,936,241

30General Service Demand charge for PURPA Purchased Power Capacity Costs Line 18 / Line 29 * 100 22


PROJECTED PURPA PURCHASED POWER CAPACITY COSTS FOR THE 12 MONTHS JULY 2016 THROUGH JUNE 2017




DERP Incremental Costs1 Purchased Power Agreements -$ -$ -$ -$ -$ -$ 2 DER NEM Incentive - - - - - - 3 Solar Rebate Program - - - - - - 4 Shared Solar Program - - - - - - 5 Carrying Costs on Deferred Amounts - - - - - - 6 NEM Avoided Capacity Costs - - - - - - 7 NEM Meter Costs - - - - - - 8 General and Administrative Expenses 12,235 13,236 9,086 14,798 25,958 36,632 9 Total DER Incremental Costs Sum Lines 1 through 8 12,235$ 13,236$ 9,086$ 14,798$ 25,958$ 36,632$

DERP Avoided Cost - Energy & Capacity10 Purchased Power Agreements -$ -$ -$ -$ -$ -$ 11 Shared Solar Program - - - - - - 12 Total DERP Avoided Cost Sum Lines 10 through 11 -$ -$ -$ -$ -$ -$



DERP Incremental Costs13 Purchased Power Agreements -$ -$ -$ -$ -$ -$ -$ 14 DER NEM Incentive - - - - 310 218 528 15 Solar Rebate Program - - 33 39 205 242 519 16 Shared Solar Program - - - - - - - 17 Carrying Costs on Deferred Amounts - - 17 36 121 220 392 18 NEM Avoided Capacity Costs - - - - 5 3 8 19 NEM Meter Costs - - - - 70 56 126 20 General and Administrative Expenses 67,184 119,211 81,683 116,039 34,635 64,603 595,300 21 Total DER Incremental Costs Sum Lines 13 through 20 67,184$ 119,211$ 81,733$ 116,114$ 35,346$ 65,341$ 596,873$

DERP Avoided Cost - Energy & Capacity22 Purchased Power Agreements -$ -$ -$ -$ -$ -$ -$ 23 Shared Solar Program - - - - - - - 24 Total DERP Avoided Cost Sum Lines 22 through 23 -$ -$ -$ -$ -$ -$ -$

Estimated Estimated Estimated Estimated Sixteen Months

March April May June EndedLine No. Description Reference 2016 2016 2016 2016 June 2016

DERP Incremental Costs25 Purchased Power Agreements -$ -$ -$ -$ -$ 26 DER NEM Incentive 357 1,551 1,551 1,551 5,538$ 27 Solar Rebate Program 253 903 903 903 3,480$ 28 Shared Solar Program - - - - -$ 29 Carrying Costs on Deferred Amounts 242 725 725 725 2,808$ 30 NEM Avoided Capacity Costs 6 28 28 28 99$ 31 NEM Meter Costs 90 129 129 129 602$ 32 General and Administrative Expenses 53,526 66,376 66,376 66,376 847,955$ 33 Total DER Incremental Costs Sum Lines 25 through 32 54,472$ 69,712$ 69,712$ 69,712$ 860,482$

DERP Avoided Cost - Energy & Capacity34 Purchased Power Agreements -$ -$ -$ -$ -$ 35 Shared Solar Program - - - - - 36 Total DERP Avoided Cost Sum Lines 34 through 35 -$ -$ -$ -$ -$


DISTRIBUTED ENERGY RESOURCE PROGRAM INCREMENTAL AND AVOIDED COSTS ACTUAL COSTS MARCH 2015 - JUNE 2016



DERP Incremental Costs1 Purchased Power Agreements -$ -$ -$ -$ -$ -$ 2 DER NEM Incentive 3,201 3,201 3,201 3,201 3,201 3,201 3 Solar Rebate Program 2,365 2,365 2,365 2,365 2,365 2,365 4 Shared Solar Program - - - - - - 5 Carrying Costs on Deferred Amounts 2,134 2,134 2,134 2,134 2,134 2,134 6 NEM Avoided Capacity Costs 28 28 28 28 28 28 7 NEM Meter Costs 219 219 219 219 219 219 8 General and Administrative Expenses 66,376 66,376 66,376 66,376 66,376 66,376 9 Total DER Incremental Costs Sum Lines 1 through 8 74,323$ 74,323$ 74,323$ 74,323$ 74,323$ 74,323$

DERP Avoided Cost - Energy & Capacity 10 Purchased Power Agreements11 Shared Solar Program12 Total DERP Avoided Cost Sum Lines 10 through 11 -$ -$ -$ -$ -$ -$



DERP Incremental Costs13 Purchased Power Agreements -$ -$ -$ -$ -$ -$ -$ 14 DER NEM Incentive 13,914 13,914 13,914 13,914 13,914 13,914 102,686 15 Solar Rebate Program 12,783 12,783 12,783 12,783 12,783 12,783 90,890 16 Shared Solar Program - - - - - - - 17 Carrying Costs on Deferred Amounts 11,066 11,066 11,066 11,066 11,066 11,066 79,198 18 NEM Avoided Capacity Costs 344 344 344 344 344 344 2,235 19 NEM Meter Costs 373 373 373 373 373 373 3,552 20 General and Administrative Expenses 35,280 35,280 35,280 35,280 35,280 35,280 609,939 21 Total DER Incremental Costs Sum Lines 13 through 20 73,760$ 73,760$ 73,760$ 73,760$ 73,760$ 73,760$ 888,500$

DERP Avoided Cost - Energy & Capacity 22 Purchased Power Agreements -$ 23 Shared Solar Program - 24 Total DERP Avoided Cost Sum Lines 22 through 23 -$ -$ -$ -$ -$ -$ -$


PROJECTED DISTRIBUTED ENERGY RESOURCE PROGRAM INCREMENTAL AND AVOIDED COSTS FOR THE 12 MONTHS JULY 2016 THROUGH JUNE 2017

Exhibit 11Page 1 of 3

DOCKET NO 2016-1-E

Winter 2014 Firm Winter 2015 Firm

Line No. Class Coincident Peak (CP) KWs CP %Coincident Peak (CP)

KWs CP %1 Residential 781,405 59.70% 768,462 58.89%2 Commercial (General Service Demand /Non-Demand) 352,120 26.90% 337,401 25.86%3 Industrial (General Service Demand /Non-Demand) 175,382 13.40% 199,008 15.25%4 Lighting 0 0.00% 0 0.00%5 Total SC 1,308,908 100.00% 1,304,870 100.00%



6 Total DERP Incremental Costs Exhibit 9 12,235$ 13,236$ 9,086$ 14,798$ 25,958$ 36,632$

7 Incremental Costs Allocated to Residential Customers Line 6 * Line 1 7,304$ 7,902$ 5,424$ 8,835$ 15,497$ 21,869$

8 Revenue Collected -$ -$ -$ -$ -$ -$ 9 SC DERP Incremental - Residential Costs Over / (Under) Recovery Line 8 - Line 7 (7,304)$ (7,902)$ (5,424)$ (8,835)$ (15,497)$ (21,869)$

10 Over / (Under) Cumulative Balance - February 2015 2015-1-E (36,990)$

11 Cumulative SC Residential DERP Avoided Costs Over / (Under) Recovery Prior Mo. Cum. Bal + Line 9 (44,294)$ (52,196)$ (57,620)$ (66,455)$ (81,951)$ (103,820)$



12 Total DERP Incremental Costs Exhibit 9 67,184$ 119,211$ 81,733$ 116,114$ 35,346$ 65,341$ 596,873.47$

13 Incremental Costs Allocated to Residential Customers Line 12 * Line 1 40,108$ 71,168$ 48,794$ 69,319$ 20,816$ 38,480$ 355,514.88$

14 Revenue Collected -$ -$ -$ 44$ 79,383$ 79,594$ 159,020.86$

15 SC DERP Incremental - Residential Costs Over / (Under) Recovery Line 14 - Line 13 (40,108)$ (71,168)$ (48,794)$ (69,275)$ 58,567$ 41,114$ (196,494)$

16 Cumulative SC Residential DERP Avoided Costs Over / (Under) RecoveryPrior Mo. Cum. Bal + Line 15 (143,928)$ (215,096)$ (263,890)$ (333,165)$ (274,597)$ (233,484)$ (233,484)$

Estimated Estimated Estimated Estimated Sixteen March April May June Months Ended


17 Total DERP Incremental Costs Exhibit 9 54,472$ 69,712$ 69,712$ 69,712$ 860,482$

18 Incremental Costs Allocated to Residential Customers Line 17 * Line 1 32,080 41,055 41,055 41,055 510,759$

19 Revenue Collected 79,667$ 79,880$ 79,938$ 79,894$ 478,399$

20 SC DERP Incremental - Residential Costs Over / (Under) Recovery Line 19 - Line 18 47,587$ 38,825$ 38,883$ 38,840$ (32,359)$

21 Cumulative SC Residential DERP Avoided Costs Over / (Under) RecoveryPrior Mo. Cum. Bal + Line 20 (185,897)$ (147,072)$ (108,189)$ (69,349)$ (69,349)$

22 SC Projected Residential Accts Jul'16 - Jun'17 138,656

23SC Residential DERP Incremental Annual Increment / (Decrement) ($ per Account) -Line 21 / Line 22 * 100 0.50$

24SC Residential DERP Incremental Monthly Increment / (Decrement) ($ per Account) Line 23 / 12 0.04$

DUKE ENERGY PROGRESS, INC.SOUTH CAROLINA RETAIL FUEL CASE

DISTRIBUTED ENERGY RESOURCE PROGRAM INCREMENTAL COSTS OVER / (UNDER) RECOVERY - RESIDENTIALACTUAL COSTS MARCH 2015 - JUNE 2016


DOCKET NO 2016-1-E







7 Incremental Costs Allocated to Commercial Customers Line 6 * Line 2 3,291$ 3,561$ 2,444$ 3,981$ 6,983$ 9,855$

8 Revenue Collected -$ -$ -$ -$ -$ -$ 9 SC DERP Incremental - Commercial Costs Over / (Under) Recovery Line 8 - Line 7 (3,291)$ (3,561)$ (2,444)$ (3,981)$ (6,983)$ (9,855)$


11 Cumulative SC Commercial DERP Avoided Costs Over / (Under) RecoveryPrior Mo. Cum. Bal + Line 9 (26,307)$ (29,868)$ (32,313)$ (36,294)$ (43,277)$ (53,131)$




13 Incremental Costs Allocated to Commercial Customers Line 12 * Line 2 18,074$ 32,070$ 21,988$ 31,237$ 9,139$ 16,895$ 159,517.95$

14 Revenue Collected -$ -$ -$ 11$ 38,658$ 38,835$ 77,504.33$

15 SC DERP Incremental - Commercial Costs Over / (Under) Recovery Line 14 - Line 13 (18,074)$ (32,070)$ (21,988)$ (31,225)$ 29,519$ 21,940$ (82,013.62)$

16 Cumulative SC Commercial DERP Avoided Costs Over / (Under) RecoveryPrior Mo. Cum. Bal + Line 15 (71,205)$ (103,275)$ (125,263)$ (156,488)$ (126,969)$ (105,030)$ (105,030)$




18 Incremental Costs Allocated to Commercial Customers Line 17 * Line 2 14,085 18,025 18,025 18,025 227,679$


20 SC DERP Incremental - Commercial Costs Over / (Under) Recovery Line 19 - Line 18 24,676$ 18,299$ 18,375$ 18,366$ (2,297)$

21 Cumulative SC Commercial DERP Avoided Costs Over / (Under) RecoveryPrior Mo. Cum. Bal + Line 20 (80,354)$ (62,054)$ (43,679)$ (25,313)$ (25,313)$

22 SC Projected Commercial Accts Jul'16 - Jun'17 30,257

23SC Commercial DERP Incremental Annual Increment / (Decrement) ($ per Account) -Line 21 / Line 22 * 100 0.84$

24SC Commercial DERP Incremental Monthly Increment / (Decrement) ($ per Account) Line 23 / 12 0.07$


DISTRIBUTED ENERGY RESOURCE PROGRAM INCREMENTAL COSTS OVER / (UNDER) RECOVERY - COMMERCIALACTUAL COSTS MARCH 2015 - JUNE 2016


DOCKET NO 2016-1-E







7 Incremental Costs Allocated to Industrial Customers Line 6 * Line 3 1,639$ 1,774$ 1,217$ 1,983$ 3,478$ 4,908$

8 Revenue Collected -$ -$ -$ -$ -$ -$ 9 SC DERP Incremental - Industrial Costs Over / (Under) Recovery Line 8 - Line 7 (1,639)$ (1,774)$ (1,217)$ (1,983)$ (3,478)$ (4,908)$


11 Cumulative SC Industrial DERP Avoided Costs Over / (Under) Recovery Prior Mo. Cum. Bal + Line 9 (14,815)$ (16,588)$ (17,806)$ (19,789)$ (23,267)$ (28,175)$




13 Incremental Costs Allocated to Industrial Customers Line 12 * Line 3 9,002$ 15,973$ 10,951$ 15,558$ 5,392$ 9,965$ 81,841.64$

14 Revenue Collected -$ -$ -$ -$ 12,003$ 12,489$ 24,492.44$

15 SC DERP Incremental - Industrial Costs Over / (Under) Recovery Line 14 - Line 13 (9,002)$ (15,973)$ (10,951)$ (15,558)$ 6,612$ 2,524$ (57,349)$

16 Cumulative SC Industrial DERP Avoided Costs Over / (Under) RecoveryPrior Mo. Cum. Bal + Line 15 (37,177)$ (53,150)$ (64,102)$ (79,660)$ (73,048)$ (70,525)$ (70,525)$




18 Incremental Costs Allocated to Industrial Customers Line 17 * Line 3 8,308 10,632 10,632 10,632 122,045$


20 SC DERP Incremental - Industrial Costs Over / (Under) Recovery Line 19 - Line 18 3,790$ 1,624$ 1,606$ 1,588$ (48,741)$

21 Cumulative SC Industrial DERP Avoided Costs Over / (Under) RecoveryPrior Mo. Cum. Bal + Line 20 (66,734)$ (65,110)$ (63,504)$ (61,916)$ (61,916)$

22 SC Projected Industrial Accts Jul'16 - Jun'17 263

23SC Industrial DERP Incremental Annual Increment / (Decrement) ($ per Account) -Line 21 / Line 22 * 100 235.53$

24SC Industrial DERP Incremental Monthly Increment / (Decrement) ($ per Account) Line 23 / 12 19.63$


DISTRIBUTED ENERGY RESOURCE PROGRAM INCREMENTAL COSTS OVER / (UNDER) RECOVERY - INDUSTRIALACTUAL COSTS MARCH 2015 - JUNE 2016


July 2016 through June 2017

1 Total DERP Projected Incremental Costs Exhibit 10 888,500

Allocation of DERP Incremental Costs for July 2016 - June 2017Firm Peak Demand -

2015July 2016 through

June 2017Cost Allocated per Firm Peak Demand

2 Residential 58.89% 523,254$ 3 Commercial (General Service Demand /Non-Demand) 25.86% 229,740 4 Industrial (General Service Demand /Non-Demand) 15.25% 135,507 5 Total 100.00% 888,500 888,501$

Total Cost Allocated per Firm Peak Demand

Projected Number of Accounts in Billing

Period$ per Account per

Year$ per Account per

Month10 Residential Line 2 523,254$ 138,656 3.77$ 0.31$ 11 Commercial (General Service Demand /Non-Demand) Line 3 229,740$ 30,257 7.59$ 0.63$ 12 Industrial (General Service Demand /Non-Demand) Line 4 135,507$ 263 515.46$ 42.96$ 13 Total 888,501$ 169,176

DUKE ENERGY PROGRESS, LLCSOUTH CAROLINA RETAIL FUEL CASE

PROJECTED BILLING PERIOD INCREMENTAL COST FACTORS FOR DERP COSTSFOR THE 12 MONTHS JULY 2016 THROUGH JUNE 2017


DOCKET NO 2016-1-E



KWs CP %1 Residential 781,405 59.70% 768,462 58.89%2 General Service Non-Demand 64,389 4.92% 74,419 5.70%3 General Service Demand 463,115 35.38% 461,990 35.41%4 Lighting 0 0.00% 0 0.00%5 Total SC 1,308,909 100.00% 1,304,871 100.00%



6 Total DERP Avoided Costs Exhibit 9 -$ -$ -$ -$ -$ -$

7 Total System kWh Sales 4,845,390,809 3,757,959,729 3,628,900,408 4,978,488,628 5,346,810,378 5,985,422,750 8 DERP Avoided System Costs (¢/kWh) Line 6 / Line 7* 100 - - - 9 SC Retail Sales kWh 570,749,238 463,754,149 420,603,466 578,289,954 607,719,653 653,631,427

10 SC DERP Avoided Costs Line 8 * Line 9 / 100 -$ -$ -$ -$ -$ -$ 11 Residential DER Avoided Costs Allocated by Firm CP Line 10 * Line 1 -$ -$ -$ -$ -$ -$

12 SC Residential kWh Sales 221,639,208 131,947,547 112,305,130 182,767,188 222,381,186 207,728,757 13 SC Residential DERP Avoided Cost (¢/kWh) Line 11 / Line 12 * 100 0.000 0.000 0.000 0.000 0.000 0.00014 SC Residential Rate Billed (¢/kWh) 2015-1-E 0.000 0.000 0.000 0.000 0.000 0.000

15 SC DERP Avoided Costs Over / (Under) Recovery(Line 14 - Line 13)*Line 12 /100 -$ -$ -$ -$ -$ -$

16 Over / (Under) Cumulative Balance - February 2015 2015-1-E -$

17Cumulative SC Residential DERP Avoided Costs Over / (Under) Recovery

Line 15 + Prior Month Cum Bal -$ -$ -$ -$ -$ -$



18 Total DERP Avoided Costs Exhibit 9 -$ -$ -$ -$ -$ -$ -

19 Total System kWh Sales 5,526,400,413 4,506,558,036 4,068,338,456 4,554,249,791 5,548,083,471 5,382,673,888 58,129,276,757 20 DERP Avoided System Costs (¢/kWh) Line 18 / Line 19* 100 - - - - - - 21 SC Retail Sales kWh 560,668,824 488,426,474 474,177,711 438,667,815 555,252,619 601,562,765 6,413,504,095 22 SC DERP Avoided Costs Line 20 * Line 21 / 100 -$ -$ -$ -$ -$ -$ - 23 Residential DER Avoided Costs Allocated by Firm CP Line 22 * Line 1 -$ -$ -$ -$ -$ -$ -

24 SC Residential kWh Sales 195,480,622 133,938,974 108,712,645 157,778,056 209,289,664 219,545,903 2,103,514,880 25 SC Residential DERP Avoided Cost (¢/kWh) Line 23 / Line 24 * 100 0.000 0.000 0.000 0.000 0.000 0.000 0.00026 SC Residential Rate Billed (¢/kWh) 2015-1-E 0.000 0.000 0.000 0.000 0.000 0.000 -

27 SC DERP Avoided Costs Over / (Under) Recovery(Line 26 - Line 25)*Line 24 /100 -$ -$ -$ -$ -$ -$ -$


Line 15 + Prior Month Cum Bal -$ -$ -$ -$ -$ -$ -$


DISTRIBUTED ENERGY RESOURCE PROGRAM AVOIDED COSTS OVER / (UNDER) RECOVERY - RESIDENTIALACTUAL AND ESTIMATED COSTS AND REVENUES MARCH 2015 - JUNE 2016



KWs CP %1 Residential 781,405 59.70% 768,462 58.89%2 General Service Non-Demand 64,389 4.92% 74,419 5.70%3 General Service Demand 463,115 35.38% 461,990 35.41%4 Lighting 0 0.00% 0 0.00%5 Total SC 1,308,909 100.00% 1,304,871 100.00%


DISTRIBUTED ENERGY RESOURCE PROGRAM AVOIDED COSTS OVER / (UNDER) RECOVERY - RESIDENTIALACTUAL AND ESTIMATED COSTS AND REVENUES MARCH 2015 - JUNE 2016


DOCKET NO 2016-1-E



29 Total DERP Avoided Costs Exhibit 9 -$ -$ -$ -$ -$

30 Projected Total System Sales 4,720,617,141 4,312,137,696 4,721,331,352 5,515,688,799 77,399,051,745 31 DERP Avoided System Costs (¢/kWh) Line 29 / Line 30* 100 - - - - 32 Projected SC Retail Sales kWh 462,889,901 459,376,756 502,773,736 580,364,203 8,418,908,692 33 SC DERP Avoided Costs Line 31 * Line 32/ 100 -$ -$ -$ -$ -$ 34 Residential DER Avoided Costs Allocated by Firm CP Line 33 * Line 1 -$ -$ -$ -$ -$

35 Projected SC Residential kWh Sales 178,105,018 129,239,846 149,734,652 197,082,411 2,757,676,807 36 SC Residential DERP Avoided Cost (¢/kWh) Line 34 / Line 35 * 100 0.000 0.000 0.000 0.00037 SC Residential Rate Billed (¢/kWh) 2015-1-E 0.000 0.000 0.000 0.000

38 SC DERP Avoided Costs Over / (Under) Recovery(Line 37 - Line 36)*Line 35 /100 -$ -$ -$ -$ -$


Line 38 + Prior Month Cum Bal -$ -$ -$ -$ -$

40 SC Projected Residential kWh Sales Jul'16 - Jun'17 2,239,987,483

41SC Residential DERP Avoided Costs Increment / (Decrement) (¢/kWh) -Line 39 / Line 40 * 100 0.000


DOCKET NO 2016-1-E


Line No. ClassCoincident Peak (CP)

KWs CP %Coincident Peak

(CP) KWs CP %1 Residential 781,405 59.70% 768,462 58.89%2 General Service Non-Demand 64,389 4.92% 74,419 5.70%3 General Service Demand 463,115 35.38% 461,990 35.41%4 Lighting 0 0.00% 0 0.00%5 Total SC 1,308,909 100.00% 1,304,871 100.00%



6 Total DERP Avoided Costs Exhibit 9 -$ -$ -$ -$ -$ -$

7 Total System kWh Sales 4,845,390,809 3,757,959,729 3,628,900,408 4,978,488,628 5,346,810,378 5,985,422,750 8 DERP Avoided System Costs (¢/kWh) Line 6 / Line 7 * 100 - - - 9 SC Retail Sales kWh 570,749,238 463,754,149 420,603,466 578,289,954 607,719,653 653,631,427

10 SC DERP Avoided Costs Line 8 * Line 9 / 100 -$ -$ -$ -$ -$ -$

11General Service (Non-Demand) DERP Avoided Costs Allocated by Firm CP Line 10 * Line 2 -$ -$ -$ -$ -$ -$

12 SC General Service (Non-Demand)kWh Sales 26,606,311 19,929,445 19,896,310 27,223,146 32,425,658 31,395,925

13 SC General Service (Non-Demand) DERP Avoided Cost (¢/kWh) Line 11 / Line 12 * 100 0.000 0.000 0.000 0.000 0.000 0.00014 SC General Service (Non-Demand) Rate Billed (¢/kWh) 2015-1-E 0.000 0.000 0.000 0.000 0.000 0.000



17Cumulative SC General Service (Non-Demand) DERP Avoided Costs Over / (Under) Recovery




18 Total DERP Avoided Costs Exhibit 9 -$ -$ -$ -$ -$ -$ -$

19 Total System kWh Sales 5,526,400,413 4,506,558,036 4,068,338,456 4,554,249,791 5,548,083,471 5,382,673,888 58,129,276,757 20 DERP Avoided System Costs (¢/kWh) Line 18/ Line 19 * 100 - - - - - - 21 SC Retail Sales kWh 560,668,824 488,426,474 474,177,711 438,667,815 555,252,619 601,562,765 6,413,504,095 22 SC DERP Avoided Costs Line 20 * Line 21 / 100 -$ -$ -$ -$ -$ -$ -$

23General Service (Non-Demand) DERP Avoided Costs Allocated by Firm CP Line 22 * Line 2 -$ -$ -$ -$ -$ -$ -$

24 SC General Service (Non-Demand)kWh Sales 30,858,252 22,008,427 17,208,126 21,028,126 24,359,429 24,957,497 297,896,652

25 SC General Service (Non-Demand) DERP Avoided Cost (¢/kWh) Line 23 / Line 24 * 100 0.000 0.000 0.000 0.000 0.000 0.000 - 26 SC General Service (Non-Demand) Rate Billed (¢/kWh) 2015-1-E 0.000 0.000 0.000 0.000 0.000 0.000 -





DISTRIBUTED ENERGY RESOURCE PROGRAM AVOIDED COSTS OVER / (UNDER) RECOVERY - GENERAL SERVICE (NON-DEMAND)ACTUAL AND ESTIMATED COSTS AND REVENUES MARCH 2015 - JUNE 2016


Line No. ClassCoincident Peak (CP)

KWs CP %Coincident Peak



DISTRIBUTED ENERGY RESOURCE PROGRAM AVOIDED COSTS OVER / (UNDER) RECOVERY - GENERAL SERVICE (NON-DEMAND)ACTUAL AND ESTIMATED COSTS AND REVENUES MARCH 2015 - JUNE 2016


DOCKET NO 2016-1-E



29 Total DERP Avoided Costs Exhibit 9 -$ -$ -$ -$ -$

30 Total Projected System kWh Sales 4,720,617,141 4,312,137,696 4,721,331,352 5,515,688,799 77,399,051,745

31 DERP Avoided System Costs (¢/kWh) Line 29/ Line 30* 100 - - - - 32 Projected SC Retail Sales kWh 462,889,901 459,376,756 502,773,736 580,364,203 8,418,908,692

33 SC DERP Avoided CostsLine 31 * Line 32 / 100

-$ -$ -$ -$ -$

34General Service (Non-Demand) DERP Avoided Costs Allocated by Firm CP Line 33 * Line 2 -$ -$ -$ -$ -$

35 Projected SC General Service (Non-Demand)kWh Sales 22,659,459 20,047,256 22,391,158 24,854,739 387,849,264

36 SC General Service (Non-Demand) DERP Avoided Cost (¢/kWh) Line 34 / Line 35 * 100 0.000 0.000 0.000 0.00037 SC General Service (Non-Demand) Rate Billed (¢/kWh) 2015-1-E 0.000 0.000 0.000 0.000




40SC Projected General Service (Non-Demand) kWh Sales Jul'16 - Jun'17 270,532,255

41Cumulative SC General Service (Non-Demand) DERP Avoided Costs Increment / (Decrement) (¢/kWh) -Line 39 / Line 40 * 100

0.000


DOCKET NO 2016-1-E


Line No. Class Coincident Peak (CP) KWs CP %Coincident Peak




6 Total DERP Avoided Costs Exhibit 9 - - - - - -

7 Total System kWh Sales 4,845,390,809 3,757,959,729 3,628,900,408 4,978,488,628 5,346,810,378 5,985,422,750 8 DERP Avoided System Costs (¢/kWh) Line 6 / Line 7 * 100 - - - - - - 9 SC Retail Sales kWh 570,749,238 463,754,149 420,603,466 578,289,954 607,719,653 653,631,427

10 SC DERP Avoided Costs Line 8 * Line 9 / 100 -$ -$ -$ -$ -$ -$ 11 General Service - Demand DERP Avoided Costs Allocated by Firm CP Line 10 * Line 2 -$ -$ -$ -$ -$ -$

12 SC General Service (demand) kW Sales 716,188 622,719 626,808 765,123 673,007 709,940 13 SC General Service Demand DERP Avoided Costs (¢/kWh) Line 11 / Line 12 * 100 0.000 0.000 0.000 0.000 0.000 0.00014 SC General Service Demand Rate Billed (¢/kWh) 2015-1-E 0.000 0.000 0.000 0.000 0.000 0.000

15 SC DERP Avoided Costs Over / (Under) Recovery (Line 14 - Line 13)*Line 12 /100 -$ -$ -$ -$ -$ -$ 16 Over / (Under) Cumulative Balance - February 2015 2015-1-E -$

17 Cumulative SC General Service Demand DERP Avoided Costs Over / (Under) Recovery Line 15 + Prior Month Cum Bal -$ -$ -$ -$ -$ -$



18 Total DERP Avoided Costs Exhibit 9 - - - - - - -

19 Total System kWh Sales 5,526,400,413 4,506,558,036 4,068,338,456 4,554,249,791 5,548,083,471 5,382,673,888 58,129,276,757 20 DERP Avoided System Costs (¢/kWh) Line 18/ Line 19 * 100 - - - - - - 21 DERP Avoided System Costs (¢/kWh) 560,668,824 488,426,474 474,177,711 438,667,815 555,252,619 601,562,765 6,413,504,095 22 SC DERP Avoided Costs Line 20 * Line 21 / 100 -$ -$ -$ -$ -$ -$ -$ 23 General Service - Demand DERP Avoided Costs Allocated by Firm CP Line 22 * Line 2 -$ -$ -$ -$ -$ -$ -$

24 SC General Service (demand) kW Sales 728,426 664,967 639,469 655,825 696,329 712,432 8,211,234 25 SC General Service Demand DERP Avoided Costs (¢/kWh) Line 23 / Line 24 * 100 0.000 0.000 0.000 0.000 0.000 0.000 0.00026 SC General Service Demand Rate Billed (¢/kWh) 2015-1-E 0.000 0.000 0.000 0.000 0.000 0.000

27 SC DERP Avoided Costs Over / (Under) Recovery (Line 26 - Line 25)*Line 24 /100 -$ -$ -$ -$ -$ -$ -$

28 Cumulative SC General Service Demand DERP Avoided Costs Over / (Under) Recovery Line 27 + Prior Month Cum Bal -$ -$ -$ -$ -$ -$ -$


DISTRIBUTED ENERGY RESOURCE PROGRAM AVOIDED COSTS OVER / (UNDER) RECOVERY - GENERAL SERVICE (DEMAND)ACTUAL AND ESTIMATED COSTS AND REVENUES MARCH 2015 - JUNE 2016





DISTRIBUTED ENERGY RESOURCE PROGRAM AVOIDED COSTS OVER / (UNDER) RECOVERY - GENERAL SERVICE (DEMAND)ACTUAL AND ESTIMATED COSTS AND REVENUES MARCH 2015 - JUNE 2016


DOCKET NO 2016-1-E



29 Total DERP Avoided Costs Exhibit 9 - - - - -$

30 Total Projected System kWh Sales 4,720,617,141 4,312,137,696 4,721,331,352 5,515,688,799 77,399,051,745 31 DERP Avoided System Costs (¢/kWh) Line 29/ Line 30* 100 - - - - 32 Projected SC Retail Sales kWh 462,889,901 459,376,756 502,773,736 580,364,203 8,418,908,692 33 SC DERP Avoided Costs Line 31 * Line 32 / 100 -$ -$ -$ -$ -$ 34 General Service - Demand DERP Avoided Costs Allocated by Firm CP Line 33 * Line 2 -$ -$ -$ -$ -$

35 Projected SC General Service (demand) kW Sales 678,920 639,865 687,073 667,260 10,884,351 36 SC General Service Demand DERP Avoided Costs (¢/kWh) Line 34 / Line 35 * 100 - - - - 37 SC General Service Demand Rate Billed (¢/kWh) 2015-1-E - - - -

38 SC DERP Avoided Costs Over / (Under) Recovery (Line 37 - Line 36)*Line 35 /100 -$ -$ -$ -$ -$

39 Cumulative SC General Service Demand DERP Avoided Costs Over / (Under) Recovery Line 38 + Prior Month Cum Bal -$ -$ -$ -$ -$

40 SC Projected General Service - demand KW Sales Jul'16-Jun'17 7,936,241 41 SC General Service-Demand DERP Avoided Cost Increment / (Decrement) (¢/kW) -Line 39 / Line 40 * 100 0


DOCKET NO 2016-1-E






6 Total DERP Avoided Costs Exhibit 9 - - - - - -

7 Total System kWh Sales 4,845,390,809 3,757,959,729 3,628,900,408 4,978,488,628 5,346,810,378 5,985,422,750 8 DERP Avoided Costs (¢/kWh) Line 6 / Line 7 * 100 - - - - - - 9 SC Retail Sales kWH 570,749,238 463,754,149 420,603,466 578,289,954 607,719,653 653,631,427

10 SC DERP Avoided Costs Line 8 * Line 9 / 100 -$ -$ -$ -$ -$ -$ 11 Lighting DERP Avoided Costs Allocated by Firm CP Line 10 * Line 4 -$ -$ -$ -$ -$ -$

12 SC Lighting kWh Sales 7,905,463 7,913,293 7,648,551 8,146,238 7,768,123 7,800,156

13 SC Lighting DERP Avoided Costs (¢/kWh)Line 11 / Line 12 * 100

0.000 0.000 0.000 0.000 0.000 0.00014 SC Lighting Rate Billed (¢/kWh) 2015-1-E 0.000 0.000 0.000 0.000 0.000 0.000



17Cumulative SC Lighting DERP Avoided Costs Over / (Under) Recovery




18 Total DERP Avoided Costs Exhibit 9 - - - - - - -

19 Total System kWh Sales 5,526,400,413 4,506,558,036 4,068,338,456 4,554,249,791 5,548,083,471 5,382,673,888 58,129,276,757 20 DERP Avoided Costs (¢/kWh) Line 18 / Line 19 * 100 - - - - - - 21 SC Retail Sales kWH 560,668,824 488,426,474 474,177,711 438,667,815 555,252,619 601,562,765 6,413,504,095 22 SC DERP Avoided Costs Line 20 * Line 21 / 100 -$ -$ -$ -$ -$ -$ -$ 23 Lighting DERP Avoided Costs Allocated by Firm CP Line 22 * Line 4 -$ -$ -$ -$ -$ -$ -$

24 SC Lighting kWh Sales 8,075,399 7,880,383 7,675,667 7,838,071 7,833,075 7,863,478 94,347,897 25 SC Lighting DERP Avoided Costs (¢/kWh) Line 23 / Line 24 * 100 0.000 0.000 0.000 0.000 0.000 0.000 0.00026 SC Lighting Rate Billed (¢/kWh) 2015-1-E 0.000 0.000 0.000 0.000 0.000 0.000





DISTRIBUTED ENERGY RESOURCE PROGRAM AVOIDED COSTS OVER / (UNDER) RECOVERY - LIGHTINGACTUAL AND ESTIMATED COSTS AND REVENUES MARCH 2015 - JUNE 2016





DISTRIBUTED ENERGY RESOURCE PROGRAM AVOIDED COSTS OVER / (UNDER) RECOVERY - LIGHTINGACTUAL AND ESTIMATED COSTS AND REVENUES MARCH 2015 - JUNE 2016


DOCKET NO 2016-1-E



29 Total DERP Avoided Costs Exhibit 9 - - - - -

30 Total Projected System kWh Sales 0 4,720,617,141 4,312,137,696 4,721,331,352 5,515,688,799 77,399,051,745 31 DERP Avoided Costs (¢/kWh) Line 29 / Line 30* 100 - - - - 32 Projected SC Retail Sales kWH 462,889,901 459,376,756 502,773,736 580,364,203 8,418,908,692 33 SC DERP Avoided Costs Line 31 * Line 32 / 100 -$ -$ -$ -$ -$ 34 Lighting DERP Avoided Costs Allocated by Firm CP Line 33 * Line 4 -$ -$ -$ -$ -$

35 Projected SC Lighting kWh Sales 7,802,806 7,525,256 7,993,191 8,602,346 126,271,495 36 SC Lighting DERP Avoided Costs (¢/kWh) Line 34 / Line 35 * 100 0.000 0.000 0.000 0.00037 SC Lighting Rate Billed (¢/kWh) 2015-1-E 0.000 0.000 0.000 0.000




40 SC Projected Lighting kWh Sales Jul'16-Jun'17 96,095,968

41 SC Lighting DERP Avoided Increment / (Decrement) (¢/kWh) -Line 39 / Line 40 * 100 0.000



1 Residential 768,462 58.89%2 General Service Non-Demand 74,419 5.70%3 General Service Demand 461,990 35.41%4 Lighting 0 0.00%5 Total SC 1,304,870 100.00%


6 Total DERP Avoided Cost Exhibit 10 -$ -$ -$ -$ -$ -$

7 Projected Total System Sales 6,131,619,391 6,070,851,379 5,145,308,592 4,506,286,142 4,666,907,710 5,612,506,214 8 DERP Avoided System Costs (¢/Kwh) Line 6 / Line 7 *100 0.000 0.000 0.000 0.000 0.000 0.0009 Projected SC Retail Sales 619,212,087 627,973,134 524,238,038 478,354,413 497,024,039 537,586,537

10 SC DERP Avoided Costs Line 8 * Line 9 /100 -$ -$ -$ -$ -$ -$


Line No. Description Reference 2017 2017 2017 2017 2017 2017 Ended June 2017

11 Total DERP Avoided Cost Exhibit 10 -$ -$ -$ -$ -$ -$ -$

12 Projected Total System Sales 5,790,398,433 5,046,328,688 4,928,235,091 4,343,473,542 4,764,742,801 5,570,177,980 62,576,835,962 13 DERP Avoided System Costs (¢/Kwh) Line 11 / Line 12 *100 0.000 0.000 0.000 0.000 0.000 0.000 0.00014 Projected SC Retail Sales 593,952,477 525,116,572 527,662,486 463,283,721 507,225,831 586,725,135 6,488,354,470 15 SC DERP Avoided Costs Line 13 * Line 14 /100 -$ -$ -$ -$ -$ -$ -$

SC DERP Avoided Costs Allocated on Firm CP kWs 16 Residential Total Line 15 * Line 1 -$ 17 General Service Non-Demand Total Line 15 * Line 2 -$ 18 General Service Demand Total Line 15 * Line 3 -$ 19 Lighting Total Line 15 * Line 4 -$ 20 Total SC Sum Lines 16 through 19 -$

Projected SC Retail Sales kWh (July 2016-June 2017)21 Residential 2,239,987,48322 General Service Non-Demand 270,532,25523 General Service Demand 3,881,738,76524 Lighting 96,095,96825 Total SC Sum Lines 21 through 24 6,488,354,470

SC DERP Avoided Costs ¢/kWh26 Residential Line 16 / Line 21 * 100 0.00027 General Service Non-Demand Line 17 / Line 23 * 100 0.00028 Lighting Line 19 / Line 24 * 100 0.000

29 Projected SC KW Sales (General Service demand) 7,936,24130 General Service Demand charge for SC DERP AvoidedCosts Line 18 / Line 29 * 100 0


PROJECTED DISTRIBUTED ENERGY RESOURCE PROGRAM AVOIDED COSTS FOR THE 12 MONTHS JULY 2016 THROUGH JUNE 2017


Line Description ReferenceResidential

(Rate Schedule RES)

General Service (Rate Schedule

SCSGS)1 Representative NEM Customer bill without solar 1,727.99$ 1,788.36$ 2 Representative NEM Customer bill WITH solar 1,203.65$ 1,210.42$ 3 Difference Line 1 - 2 524.33$ 577.94$

4 Representative annual solar production kWhs 5605 56055 Value of solar in dollars per kWh Proposed 0.04829 0.048296 Net Benefits delivered by solar production Line 4 * 5 270.63$ 270.63$

7 Under-recovered revenue from NEM Customer Line 3 - 6 253.70$ 307.31$ 8 Annual solar production kWhs Line 4 5605 56059 DERP NEM Incentive in dollars per kWh Line 7 / Line 8 0.04527$ 0.05483$

SOUTH CAROLINA RETAIL FUEL CASEDUKE ENERGY PROGRESS, INC.

DERP NEM Incentive Calculation


SOUTH CAROLINA

DOCKET NO. 2016-1-E

In the Matter of ) DIRECT TESTIMONY OF Annual Review of Base Rates ) JOSEPH A. MILLER, JR. FOR for Fuel Costs for ) DUKE ENERGY PROGRESS, INC. Duke Energy Progress, LLC )

DIRECT TESTIMONY OF JOSEPH A. MILLER, JR. Page 2 DUKE ENERGY PROGRESS, LLC DOCKET NO. 2016-1-E


A. My name is Joseph A. Miller, Jr. and my business address is 526 South Church 2

Street, Charlotte, North Carolina 28202. 3


A. I am Vice President of Central Engineering and Services for Duke Energy Business 5

Services, LLC (“DEBS”). DEBS is a service company subsidiary of Duke Energy 6

Corporation (“Duke Energy”) that provides services to Duke Energy and its 7

subsidiaries, including Duke Energy Progress, LLC (“DEP” or the “Company”) and 8

Duke Energy Carolinas, LLC (“DEC”). 9

Q. PLEASE BRIEFLY DESCRIBE YOUR EDUCATIONAL AND 10

PROFESSIONAL BACKGROUND. 11

A. I graduated from Purdue University with a Bachelor of Science degree in 12

mechanical engineering. I also completed twelve post graduate level courses in 13

Business Administration at Indiana State University. My career began with Duke 14

Energy (d/b/a Public Service of Indiana) in 1991 as a staff engineer at Duke Energy 15

Indiana’s Cayuga Steam Station. Since that time, I have held various roles of 16

increasing responsibility in the generation engineering, maintenance, and operations 17

areas, including the role of station manager, first at Duke Energy Kentucky’s East 18

Bend Steam Station, followed by Duke Energy Ohio’s Zimmer Steam Station. I was 19

named General Manager of Analytical and Investments Engineering in 2010, and 20

became General Manager of Strategic Engineering in 2012 following the merger 21

between Duke Energy and Progress Energy, Inc. I became the Vice President of 22

Central Engineering and Services in 2014. 23


Q. WHAT ARE YOUR DUTIES AS VICE PRESIDENT OF CENTRAL 1

ENGINEERING AND SERVICES? 2

A. In this role, I am responsible for providing direction and oversight for engineering 3

and business services, along with strategic and technical services including 4

environmental compliance planning, for Duke Energy’s fleet of fossil, hydroelectric 5

(“hydro” and collectively, “fossil/hydro”), and solar facilities. 6

Q. HAVE YOU TESTIFIED BEFORE THIS COMMISSION IN ANY PRIOR 7

PROCEEDINGS? 8

A. Yes. I testified before the Public Service Commission of South Carolina in DEP’s 9

2014 and 2015 annual fuel proceedings in Docket Nos. 2014-1-E and 2015-1-E, as 10

well as in DEC’s 2014 and 2015 annual fuel proceedings in Docket Nos. 2014-3-E 11

and 2015-3-E, respectively. I have also testified on multiple occasions on behalf of 12

Duke Energy in proceedings before this and other state commissions. 13


PROCEEDING? 15

A. The purpose of my testimony is to (1) describe DEP’s fossil/hydro generation 16

portfolio and changes made since the 2015 fuel cost recovery proceeding, as well as 17

those expected in the near term, (2) discuss the performance of DEP’s fossil/hydro 18

facilities during the period of March 1, 2015 through February 29, 2016 (the “review 19

period”), (3) provide information on significant fossil/hydro outages that occurred 20

during the review period, and (4) provide information concerning environmental 21

compliance efforts. 22


Q. PLEASE DESCRIBE DEP’S FOSSIL/HYDRO GENERATION 1

PORTFOLIO. 2

A. The Company’s fossil/hydro generation portfolio consists of 9,378 megawatts 3

(“MWs”) of generating capacity, made up as follows: 4

Coal-fired - 3,544 MWs 5

Combustion Turbines - 2,943 MWs 6

Combined Cycle Turbines - 2,620 MWs 7

Hydro - 227 MWs 8

Solar - 44 MWs1 9

The 3,544 MWs of coal-fired generation represent three generating stations 10

and a total of seven units. These units are equipped with emission control 11

equipment, including selective catalytic reduction (“SCR”) equipment for removing 12

nitrogen oxides (“NOx”), flue gas desulfurization (“FGD” or “scrubber”) equipment 13

for removing sulfur dioxide (“SO₂”), and low NOx burners. This inventory of coal-14

fired assets with emission control equipment employed enhances DEP’s ability to 15

maintain current environmental compliance and concurrently utilize coal with 16

increased sulfur content – providing flexibility for DEP to procure the best cost 17

options for coal supply. 18

The Company has a total of 35 simple cycle combustion turbine (“CT”) 19

units, the larger 14 of which provide 2,201 MWs, or 75% of capacity. These 14 20

units are located at the Asheville, Darlington, Richmond County, and Wayne County 21

facilities, and are equipped with water injection and/or low NOx burners for NOx 22 1 This value represents the relative dependable capacity contribution to meeting summer peak demand, based on the Company’s integrated resource planning metrics. The nameplate capacity of the Company’s solar facilities is 100 MWs.


control. The 2,620 MWs shown as “Combined Cycle Turbines” (“CC”) represent 1

four power blocks. The Lee Energy Complex CC power block (“Lee CC”) has a 2

configuration of three CTs and one steam turbine. The two Richmond County 3

power blocks located at the Smith Energy Complex consist of two CTs and one 4

steam turbine each. The Sutton Combined Cycle at Sutton Energy Complex 5

(“Sutton CC”) consists of two CTs and one steam turbine. Within these four CC 6

power blocks, all nine CTs are equipped with low NOx burners, SCR equipment, and 7

carbon monoxide volatile organic compound catalysts. The steam turbines do not 8

combust fuel and, therefore, do not require NOx controls. The Company’s hydro 9

fleet consists of 15 units providing approximately 227 MWs of capacity. The 10

Company's solar fleet consist of three sites providing 44 MWs of capacity. 11

Q. WHAT CHANGES HAVE OCCURRED WITHIN THE FOSSIL/HYDRO 12

PORTFOLIO SINCE DEP’S 2015 ANNUAL FUEL PROCEEDING? 13

A. Changes within the Company’s portfolio since last year’s fuel proceeding include 14

the addition of 208 MWs of capacity from the purchase of North Carolina Eastern 15

Municipal Power Agency's ("NCEMPA's") portions of Roxboro Unit 4 and Mayo 16

Unit 1, bringing DEP's ownership to 100% of both units. The Company has also 17

added three solar sites with a total of 100 MWs of nameplate capacity (Warsaw, 18

Fayetteville, and Camp Lejeune), providing 44 MWs of utility equivalent capacity, 19

and retired Darlington CT Unit 11 in November 2015, reducing capacity by 52 20

MWs. 21


Q. WHAT ARE DEP’S OBJECTIVES IN THE OPERATION OF ITS 1

FOSSIL/HYDRO FACILITIES? 2

A. The primary objective of DEP’s fossil/hydro generation department is to safely 3

provide reliable and cost-effective electricity to DEP’s Carolinas customers. The 4

Company achieves this objective by focusing on a number of key areas. Operations 5

personnel and other station employees are well-trained and execute their 6

responsibilities to the highest standards in accordance with procedures, guidelines, 7

and a standard operating model. Like safety, environmental compliance is a “first 8

principle” and DEP works very hard to achieve high level results. 9

The Company achieves compliance with all applicable environmental 10

regulations and maintains station equipment and systems in a cost-effective manner 11

to ensure reliability. The Company also takes action in a timely manner to 12

implement work plans and projects that enhance the safety and performance of 13

systems, equipment, and personnel, consistent with providing low-cost power 14

options for DEP’s customers. Equipment inspection and maintenance outages are 15

generally scheduled during the spring and fall months when electricity demand is 16

reduced due to weather conditions. These outages are well-planned and executed 17

with the primary purpose of preparing the unit for reliable operation until the next 18

planned outage. 19

Q. HOW MUCH GENERATION DID EACH TYPE OF GENERATING 20

FACILITY PROVIDE FOR THE REVIEW PERIOD? 21

A. For the review period, DEP’s total system generation was 63,610,552 megawatt-22

hours (“MWHs”), of which 35,401,215 MWHs, or approximately 56%, was 23


provided by the fossil/hydro fleet. The breakdown includes a 35% contribution from 1

gas facilities, 19% contribution from coal-fired stations, approximately 1% 2

contribution from hydro facilities, and less than .1% from solar facilities. 3

The Company’s portfolio includes a diverse mix of units that, along with its 4

nuclear capacity, allow DEP to meet the dynamics of customer load requirements in 5

a logical and cost-effective manner. Additionally, DEP has utilized the Joint 6

Dispatch Agreement, which allows generating resources for DEP and DEC to be 7

dispatched as a single system to enhance dispatching at the lowest possible cost. 8

The cost and operational characteristics of each unit generally determine the type of 9

customer load situation (e.g., base and peak load requirements) that a unit would be 10

called upon or dispatched to support. 11

Q. HOW DID DEP COST EFFECTIVELY DISPATCH THE DIVERSE MIX OF 12

GENERATING UNITS DURING THE REVIEW PERIOD? 13

A. The Company, like other utilities across the U.S., has experienced a change in the 14

dispatch order for each type of generating facility due to continued favorable 15

economics resulting from the low pricing of natural gas. Further, the addition of 16

new CC units within DEP’s portfolio in recent years has provided DEP with 17

additional natural gas resources that feature state-of-the-art technology for increased 18

efficiency, fuel flexibility of coal and gas, and significantly reduced emissions. 19

These factors promote the use of natural gas and provide real benefits in both pricing 20

and reduced emissions for customers. Gas fired facilities provided 63% of the DEP 21

Fossil/Hydro generation during the review period. 22


Q. WHAT WAS THE HEAT RATE FOR DEP’S COAL-FIRED AND 1

COMBINED CYCLES UNITS DURING THE REVIEW PERIOD? 2

A. Heat rate is a measure of the amount of thermal energy needed to generate a given 3

amount of electric energy and is expressed as British thermal units (“Btu”) per 4

kilowatt-hour (“kWh”). A low heat rate indicates an efficient fleet that uses less heat 5

energy from fuel to generate electrical energy. Over the review period, the 6

Company’s seven coal units produced 35% of the Fossil/Hydro generation, with the 7

average heat rate for the coal-fired units being 10,467 Btu/kWh. This average heat 8

rate represents a 1% improvement in coal unit heat rate over the previous review 9

period. The most active station during this period was Roxboro, providing 67% of 10

the coal production for the fleet with a heat rate of 10,319 Btu/kWh. During the 11

review period, the Company’s four combined cycle power blocks produced 55% of 12

the Fossil/Hydro generation, with an average heat rate of 7,090 Btu/kWh. 13

Q. PLEASE DISCUSS THE OPERATIONAL RESULTS FOR DEP’S 14

FOSSIL/HYDRO FLEET DURING THE REVIEW PERIOD. 15

A. The Company’s generating units operated efficiently and reliably during the review 16

period. Several key measures are used to evaluate the operational performance 17

depending on the generator type: (1) equivalent availability factor (“EAF”), which 18

refers to the percent of a given time period a facility was available to operate at full 19

power, if needed (EAF is not affected by the manner in which the unit is dispatched 20

or by the system demands; it is impacted, however, by planned and unplanned 21

maintenance (i.e., forced) outage time); (2) equivalent forced outage rate (“EFOR”), 22

which represents the percentage of unit failure (unplanned outage hours and 23


equivalent unplanned derated hours); a low EFOR represents fewer unplanned 1

outage and derated hours, which equates to a higher reliability measure; and, (3) 2

starting reliability (“SR”), which represents the percentage of successful starts. 3

The chart below provides operational results categorized by generator type, 4

as well as results from the most recently published North American Electric 5

Reliability Council (“NERC”) Generating Unit Statistical Brochure (“NERC 6

Brochure”) representing the period 2010 through 2014. The NERC data reported for 7

the coal-fired units represents an average of comparable units based on capacity 8

rating. Overall, the data in the chart reflects that DEP metrics were better than the 9

NERC 5 year comparisons. 10

11

Q. PLEASE DISCUSS SIGNIFICANT OUTAGES OCCURRING AT DEP’S 12

FOSSIL/HYDRO FACILITIES DURING THE REVIEW PERIOD. 13

A. In general, planned maintenance outages for all fossil and hydro units are scheduled 14

for the spring and fall to maximize unit availability during periods of peak demand. 15


Most units had at least one short planned outage during this review period to inspect 1

and maintain plant equipment. 2

Roxboro station had planned maintenance outages on Unit 1 and Unit 4 in 3

the spring. Roxboro Unit 3 had a planned maintenance outage in the fall. The Unit 1 4

outage included maintenance work for the boiler and turbine. The more significant 5

projects completed were generator stator and field rewinds, turbine valve 6

maintenance and boiler inspection. The Unit 4 outage involved HP turbine 7

maintenance, boiler inspection, and circulating water tunnel piping maintenance. 8

The fall Roxboro Unit 3 outage included HP turbine inspection and replacement of 9

HP first stage blades, airheater basket replacements, and burner upgrades. 10

The CT fleet included Asheville Unit 3 in the fall for controls system 11

upgrade and combustion fuel nozzle replacements. 12

There was also a planned outage for a hot gas path inspection at Richmond 13

CC in the fall, which included maintenance activities to ensure reliability of the 14

power block. 15

Q. HOW DOES DEP ENSURE EMISSIONS REDUCTIONS FOR 16

ENVIRONMENTAL COMPLIANCE? 17

A. The Company has installed pollution control equipment on coal-fired units, as well 18

as new generation resources in order to meet various current federal, state, and local 19

reduction requirements for NOx and SO2 emissions. The SCR technology that DEP 20

currently operates on the coal-fired units uses ammonia or urea for NOx removal and 21

the scrubber technology employed uses crushed limestone for SO2 removal. SCR 22

equipment is also an integral part of the design of the newer CC facilities in which 23


aqueous ammonia (19% solution of NH₃) is introduced for NOx removal. 1

Overall, the type and quantity of chemicals used to reduce emissions at the 2

plants varies depending on the generation output of the unit, the chemical 3

constituents in the fuel burned, and/or the level of emissions reduction required. The 4

Company is managing the impacts, favorable or unfavorable, as a result of changes 5

to the fuel mix and/or changes in coal burn due to competing fuels and utilization of 6

non-traditional coals. Overall, the goal is to effectively comply with emissions 7

regulations and provide the most efficient total-cost solution for operation of the 8

unit. The Company will continue to leverage new technologies and chemicals to 9

meet both present and future state and federal emission requirements including the 10

Mercury and Air Toxics Standards (“MATS”) rule. MATS chemicals that DEP may 11

use in the future to reduce emissions include, but may not be limited to, activated 12

carbon, mercury oxidation chemicals, and mercury re-emission prevention 13

chemicals. Company witness McGee provides the cost information for DEP’s 14

chemical use and forecast. 15

Q. DOES THAT CONCLUDE YOUR PRE-FILED DIRECT TESTIMONY? 16

A. Yes, it does. 17


SOUTH CAROLINA DOCKET NO. 2016-1-E

In the Matter of Annual Review of Base Rates for Fuel Costs for Duke Energy Progress, LLC

) ) ) ) ) )

DIRECT TESTIMONY OF

EMILY O. FELT FOR DUKE ENERGY PROGRESS, LLC

DIRECT TESTIMONY OF EMILY O. FELT Page 2 DUKE ENERGY PROGRESS, LLC DOCKET NO. 2016-1-E


A. My name is Emily O. Felt and my business address is 400 South Tryon St., Charlotte, 2

North Carolina, 28202. 3

Q. BY WHOM AND IN WHAT CAPACITY ARE YOU EMPLOYED? 4

A. I am Strategy and Policy Director in the Distributed Energy Resources group at Duke 5

Energy Corporation. I am responsible for the development and execution of strategies 6

related to distributed energy resources (“DER”) for Duke Energy’s South Carolina 7

franchises, Duke Energy Carolinas, LLC (“DEC”) and Duke Energy Progress, LLC 8

(“DEP” or the “Company”). This includes evaluation of legislation and regulation, and 9

implementation of customer programs such as those associated with Act 236 (the “Act”), 10

the South Carolina Distributed Energy Resource Act of 2014. 11

Q. PLEASE BRIEFLY DESCRIBE YOUR EDUCATIONAL BACKGROUND AND 12

WORK EXPERIENCE. 13

A. I received a Bachelor of Arts degree from Stanford University and a Master of Public 14

Administration from Harvard University. I joined Duke Energy Corporation in 2007 as a 15

business development manager assigned to large industrial energy consumers. In 2010, I 16

joined the regulated renewable energy group where I led Duke Energy Carolinas’ 17

compliance with the North Carolina Renewable Energy and Energy Efficiency Portfolio 18

Standard. In 2012, I moved into a strategy and policy role within the same group. In 19

2014, I moved into my current role leading compliance with and implementation of Act 20

236. I currently serve on the Board of Directors of Palmetto Clean Energy and the South 21

Carolina Clean Energy Business Alliance. 22


Q. HAVE YOU TESTIFIED BEFORE THIS COMMISSION BEFORE? 1

A. Yes. I have testified before the Public Service Commission of South Carolina on 2

multiple occasions, in DEC’s and DEP’s 2015 annual fuel proceedings, the 2015 3

Distributed Energy Resource Program (“DERP”) proceedings, and in the 2015 generic 4

proceeding on net energy metering (“NEM”) methodology. 5

Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? 6

A. The purpose of my testimony is to provide support for the DERP costs that are 7

incorporated into the proposed fuel factors prepared by Witness McGee. I will describe 8

the nature of costs filed as well as any changes made to the DERP portfolio made since 9

the 2015 fuel proceeding. 10

Q. DO YOU HAVE ANY EXHIBITS TO YOUR TESTIMONY? 11

A. Yes, Felt Exhibits A and B are clean and red-lined versions of the Company’s proposed 12

2016 Renewable Net Metering Rider RNM, respectively. 13

Q. WERE THOSE EXHIBITS PREPARED BY YOU OR AT YOUR DIRECTION? 14

A. Yes. 15

Q. PLEASE DESCRIBE THOSE DERP COSTS THAT ARE INCLUDED INTHE 16

COMPANY’S PROPOSED FUEL FACTOR. 17

A. Pursuant to Commission Order No. 2015-515, the Company offers its customers a variety 18

of programs to support solar development. As a result, the Company incurred DERP 19

costs totaling $593,873 in the period from March 1, 2015 through February 29, 2016 (the 20

“review period”); anticipates incurring $263,609 during the period March 1, 2016 21

through June 30, 2016 (the “forecast period”); and projects to incur $888,500 in the 22

period July 1, 2016 through June 30, 2017 (the “billing period”). 23


Cost Type

Review PeriodMarch 1, 2015

through February 29, 2016

Forecast PeriodMarch 1, 2016

through June 30, 2016

Billing PeriodJuly 1, 2016

through June 30, 2017

DERP Incremental CostsPurchased Power Agreements $ - $ - $ - DER NEM Incentive $ 528 $ 5,010 $ 102,686 Solar Rebate Program $ 519 $ 2,961 $ 90,890 Shared Solar Program $ - $ - $ - Carrying Costs on Deferred Amounts $ 392 $ 2,415 $ 79,198 NEM Avoided Capacity Costs $ 8 $ 91 $ 2,235 NEM Meter Costs $ 126 $ 477 $ 3,552 General and Administrative Expenses $ 595,300 $ 252,655 $ 609,939

Total DERP Incremental Costs $ 596,873 $ 263,609 $ 888,500

DERP Avoided Costs - Energy & CapacityPurchased Power Agreements $ - $ - $ - Shared Solar Program $ - $ - $ -

Total DERP Avoided Cost $ - $ - $ -

Total DERP Incremental and Avoided Costs 596,873$ 263,609$ 888,500$

Source: McGee Exhibits 9 and 10

These costs represent the avoided and incremental costs associated with the 1

Company’s approved DERP offerings, including the 1) DERP NEM Incentive; 2) Solar 2

Rebate Program; 3) Shared Solar Program; 4) Request for Proposals (“RFP”) of utility-3

scale solar facilities; and 5) General and Administrative Expenses, including incremental 4

labor costs as a direct result of DERP, IT and billing enhancements, and other 5

administrative costs associated with delivering these new programs to customers. Table 6

1, below, is an itemization of the actual and expected DERP costs. 7

Table 1: DERP Cost Summary – Review, Forecast, and Billing Periods 8

9

10

11

12

13

14

15

16

17

18

19

20

21


Q. PLEASE DESCRIBE THE COMPANY’S DERP NEM INCENTIVE AND COSTS. 1

A. The Company’s first DERP offer, the DERP NEM Incentive, is a credit available to 2

eligible NEM customer-generators that enables the customer-generator to receive a full 3

retail rate compensation for each kilowatt-hour generated by their solar facility, for the 4

period of time defined in the settlement agreement reached in Docket No. 2014-246-E. 5

The DERP NEM Incentive approximates the difference between Value of NEM 6

DER, as computed using the methodology approved in Docket No. 2014-246-E, and the 7

retail rate. Settling Parties in that same docket agreed that the DERP NEM Incentive 8

shall be treated as an incremental cost, as defined in S.C. Code Ann. § 58-39-140, 9

effectively socializing the cost of the DERP NEM incentive to all retail customers as a 10

component of the utilities’ respective DERP Programs. The DERP NEM Incentive is 11

available automatically to customers taking service under Rider RNM1. 12

As shown in Line 2 of the above table, the total cost associated with this incentive 13

are expected to grow significantly in the Billing Period. This growth is correlated with an 14

expected increase customers who elect service under Rider RNM-1 and proposed Rider 15

RNM-2 due to the availability of another utility program to support solar development, 16

the Solar Rebate Program, discussed below. 17

1 Renewable Net Metering Rider RNM was approved in Commission Order No. 2015-591.


Q. COMMISSION ORDER 2015-194 REQUIRES THAT THE VALUE OF NEM DER 1

IS COMPUTED ANNUALLY. WHAT IS THE 2016 VALUE AND HOW DID YOU 2

ARRIVE AT THAT NUMBER? 3

A. The value of NEM DER for 2016 is $0.04829 per kWh for Schedules RES, R-TOUD, 4

RTOUE, and SGS and $0.04836 for all other schedules. Felt Exhibits A and B show the 5

Company’s proposed 2016 NEM tariff (RNM-2), which includes a statement of the value 6

of NEM DER as well as an updated excess energy credit which is based on the 7

Company’s new proposed avoided cost rates, currently pending in Docket No. 1995-8

1192-E. 9

Table 2, below, lists the components of value in the standardized methodology. 10

The calculation is consistent with the methodology approved in Docket No. 2014-246-E. 11

The methodology includes all categories of potential costs or benefits to the utility system 12

that are capable of quantification or possible quantification in the future. Where there is 13

currently a lack of capability to accurately quantify a particular category, that category 14

has been included in the methodology as a placeholder. For example, while “Avoided 15

CO2 Emission Cost” is included as a component, its value is currently zero; a zero 16

monetary value for CO2 will be used until state or federal laws or regulations result in an 17

avoidable cost on utility systems for these emissions, per the approved methodology. 18


Table 2: Value of NEM Distributed Energy Resource, by Component 1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

Q. HAVE YOU REVIEWED THE CALCULATION METHODOLOGY OF THE 18

DER NEM INCENTIVE PROVIDED BY WITNESS MCGEE? 19

A. Yes. I have reviewed McGee Exhibit 15 and it is consistent with the methodology 20

approved in Docket No. 2014-246-E. It applies the methodology as set forth on page 21

5, paragraph 9, of the settlement agreement in that docket (Order 2015-194, Order 22

Exhibit 1), using generic customer usage information and estimated solar generation data 23

based on updated load profiles. 24

Components of NEM Distributed Energy Resource Value

Avoided Energy Cost

Avoided Capacity CostAncillary Services

T&D Capacity

Avoided Criteria

Pollutants'voided

CO2 Emissions Cost

Fuel Hedge

Utility Integration & Interconnection CostUtility Administrative Cost

Component value($ per kWh) for

SmallPV'0.03615

$0. 01047

$0.00000

$0.00000

$0.00000

$0.00000

$0.00000

$0.00000

$0.00000

Component value($ per kWh) for

LargePV'0.03613

$0.01055

$0. 00000

$0. 00000

$0.00000

$0. 00000

$0. 00000

$0. 00000

$0. 00000

Engronmental Costs

Line LossesaSubtotal

$0.00000

$0.04662

$0.00167

$0. 00000

$0. 04668

$0.00168

Total Value of NEM Distributed Energy Resource $0.04829 $0. 04836

Notes'voded faerie Pollutants are included m the marginal energy costs.r Late loss factors are 39949k on onpeak marginal energy, 39 f5% for off peak marginal energy and 1389% for marginalcapacity.4 "Small PV" refers to a load shape reflecting generation installed by a low er usage residential or small consnerctatfindustrtatcustomer. "Large PV" refers to a load shape characteristic of generaton by a customer w ilh higher consumption requirementsand apples to all other nonresdentel rate schedules.


Q. PLEASE DESCRIBE THE COMPANY’S SOLAR REBATE PROGRAM, THE 1

ASSOCIATED TIMELINE, AND COSTS. 2

A. Launched in October of 2015, the Company offers a rebate of $1.00 per watt (direct 3

current or “DC”) of solar photovoltaic capacity installed to qualified residential and non-4

residential customers. The rebate itself is provided to the customer or his designated 5

representative upon completion of the solar facility. This rebate, when combined with 6

the State and Federal tax credits for solar PV, and available net metering riders or buy-7

all-sell-all tariffs, is designed spur solar adoption by lowering the cost to install and 8

providing price-certainty over an extended term, consistent with the goal stated in S.C. 9

Code Ann. § 58-39-130(C)(2). 10

Through the Solar Rebate Program, the Company’s goal is to incent the 11

development of 3,250 kilowatts (“kW”)(alternating current or “AC”) of aggregate 12

capacity from facilities equal to or less than 20 kW (AC), and 9,750 kW (AC) of capacity 13

from facilities greater than 20 kW (AC) and less than or equal to 1,000 kW (AC), 14

consistent with the goals of Act 236. 15

To date, the Company has received fewer applicants for rebates in the smaller 16

capacity category (equal to or less than 20 kW) than it had anticipated whereas it has 17

received more interest in rebates for larger capacity than it had expected. We also note 18

that larger solar projects located at commercial or industrial customer sites can take a 19

number of months to complete and for that reason, we anticipate incurring more rebate 20

costs in the billing period rather than in the near term. 21


The incremental costs associated with the Solar Rebate Program and included in 1

this filing are the cost of the rebate itself, carrying costs on deferred amounts, and 2

incremental labor required to manage the program. 3

Q. PLEASE DESCRIBE THE COMPANY’S SHARED SOLAR PROGRAM, THE 4

ASSOCIATED TIMELINE, AND COSTS. 5

A. The Company’s Shared Solar Program, also approved in Order No. 2015-514, is a means 6

for multiple retail customers to subscribe to and share in the economic benefits of one 7

renewable energy facility. To date, the Company has designed the program, filed and 8

received approval for a Shared Solar tariff, embarked upon billing and IT projects to 9

enable the transaction, and solicited competitive bids for shared solar sites. 10

The Company has revised its timeline for introduction of the Shared Solar 11

Program due to longer than anticipated time required for interconnection study. Whereas 12

DEP originally estimated that Shared Solar would be available to customers in mid-2016, 13

it now anticipates the program will be available beginning in July of 2017. 14

The incremental costs associated with the Shared Solar Program are limited to 15

general and administrative (“G&A”) expenses, including labor and IT project costs, 16

required to adapt the Company’s database and billing systems to the Shared Solar 17

transaction. 18

Q. PLEASE DESCRIBE THE RESULTS OF THE COMPANY’S RFP OF UTILITY-19

SCALE SOLAR FACILITIES, THE ASSOCIATED TIMELINE, AND COSTS. 20

A. In the fall of 2015, the Company solicited competitive bids for a total of 13,000 kW (AC) 21

of solar PV from facilities, each greater than 1,000 kW (AC) and equal to or less than 22

10,000 kW (AC) in capacity, located in and interconnected to the Duke Energy Progress, 23


LLC, South Carolina retail service area. 13,000 kW is equal to approximately one 1

percent of the Company’s estimated 5 year average South Carolina retail peak demand, as 2

stated in Order No. 2015-514. The solicitation closed on October 27, 2015, bids 3

underwent initial evaluation in the winter of 2016, and a short list communication was 4

sent to bidders on March 10, 2016. The Company has revised its timeline for 5

energization of this capacity due to longer than anticipated time required for 6

interconnection study. Whereas DEP originally estimated that this capacity would be 7

delivering energy in mid-2016, it now anticipates the program will be available beginning 8

in July of 2017. Thus, there are no incremental or avoided costs associated with 9

purchased power agreements associated with the Company’s approved DERP included in 10

this filing. 11

Q. PLEASE DESCRIBE G&A EXPENSES, INCLUDING INCREMENTAL LABOR 12

COSTS AS A DIRECT RESULT OF DERP, IT AND BILLING 13

ENHANCEMENTS, AND OTHER ADMINISTRATIVE COSTS ASSOCIATED 14

WITH DELIVERING THESE NEW PROGRAMS TO CUSTOMERS. 15

A. As stated previously, included in this filing are incremental labor costs required to 16

manage and implement the NEM program, the Solar Rebate Program, and the Shared 17

Solar Program. Also included are the incremental costs required to adapt the Company’s 18

database and billing systems to the Shared Solar transaction. 19

Q. ARE THERE ANY OTHER DERP COSTS THAT WE SHOULD BE AWARE OF? 20

A. Yes. As noted by Witness McGee in her testimony, the Company seeks recovery of 21

carrying costs on deferred amounts as well as cost avoided capacity associated with NEM 22

generation. Lastly, included in all three periods are costs for revenue-grade meters 23


located at NEM customer-generators’ premises. As the number of customer-generators is 1

expected to grow significantly in the near future, the Company believes that enhanced 2

monitoring of solar PV generation against actual customer loads, in particular, will yield 3

operational benefits in the future. 4

Q. DOES THIS CONCLUDE YOUR TESTIMONY? 5

A. Yes. 6

RIDER RNM-2 Sheet 1 of 3

Duke Energy Progress, LLC RR-22 (South Carolina)

RENEWABLE NET METERING RIDER RNM-2

AVAILABILITY

Available to residential and nonresidential Customers receiving concurrent service from Company, on a metered rate schedule, except as indicated under General Provisions. The renewable net energy metered (NEM) generation, which includes a solar photovoltaic; solar thermal; wind powered; hydroelectric; geothermal; tidal or wave energy; recycling resource; hydrogen fueled or combined heat and power derived from renewable resources; or biomass fueled generation source of energy, is installed on Customer’s side of the delivery point, for Customer’s own use, interconnected with and operated in parallel with Company’s system. The generation must be located at a single premises owned, operated, leased or otherwise controlled by Customer.

Service under this Rider is closed to new participants on and after January 1, 2021, or when the statutory minimum system capacities described in S.C. Code § 58-39-130 have been reached, whichever occurs first. Customers requesting NEM service after January 1, 2021, will receive service in accordance with the NEM tariff in effect at that time. This Rider shall expire and no longer be available for NEM service on and after January 1, 2026.

GENERAL PROVISIONS

1. To qualify for service under this Rider, Customer must comply with all applicable interconnectionstandards and must provide, in writing, the Nameplate Capacity of Customer’s installed renewablegeneration system. Any subsequent change to the Nameplate Capacity must be provided byCustomer to Company in writing by no later than 60 days following the change.

2. To qualify for service under this Rider, a residential customer may be served on an approvedresidential rate schedule, but may not be served under Rider NM. The Nameplate Capacity ofCustomer’s installed generation system and equipment must not exceed 20 kW AC.

3. To qualify for service under this Rider, a nonresidential customer may be served on an approvedgeneral service rate schedule, but may not be served on Schedules SGS-TES, TSS, TFS, LGS-RTP,LGS-CUR-TOU, CSG, CSE, GS, SFLS or Rider NM. The Nameplate Capacity of Customer’sinstalled renewable generation system and equipment must not exceed 1,000 kW AC or 100% ofCustomer’s contract demand which shall approximate Customer’s maximum expected demand.

4. If Customer is not the owner of the premises receiving electric service from Company, Companyshall have the right to require that the owner of the premises give satisfactory written approval ofCustomer’s request for service under this Rider.

5. Customers served under this Rider are not eligible to receive payment from Palmetto Clean Energy(PaCE) for energy generated by Customer’s renewable generation system. All environmentalattributes, including but not limited to “renewable energy certificates” (RECs), “renewable energycredits” or “green tags”, associated with the generation system shall be conveyed to Company untilbilling of a Distributed Energy Resource Program Rider DERP Charge is discontinued on allcustomer bills. Customer certifies that the environmental attributes have not and will not beremarketed or otherwise resold for any purpose, including another distributed energy resourcestandard or voluntary purchase of renewable energy certificates in South Carolina or in any otherstate or country for the Contract Period and any successive contract periods thereto.

6. If the electricity supplied to Customer by Company exceeds the electricity delivered to the grid bythe customer-generator during a monthly billing period, the customer-generator shall be billed for

Felt Exhibit 1


the net electricity in kilowatt hours (kWh) supplied by Company plus any demand or other charges under the applicable rate schedule or riders. If the electricity delivered to the grid by the customer-generator exceeds the electricity in kWh supplied by the utility during a monthly billing period, the customer-generator shall be credited for the excess kWh generated during that billing period.

7. Electricity delivered to the grid by Customer’s renewable generation that exceeds the electricitydelivered by Company is defined as Excess Energy. When used in conjunction with a time of useschedule, the TOU periods shall be specified in the applicable schedule and any Excess Energy shallapply first with the Excess Energy generated On-Peak kWh offsetting On-peak usage and thenoffsetting Off-peak usage. Any excess Off-Peak kWh shall only apply against Off-peak kWh usage.Any Excess Energy not used in the current month to offset usage shall carry forward to the nextbilling month.

8. Excess Energy shall be used to reduce electricity delivered and billed by Company during thecurrent or a future month, except that for the March billing period any carry-over shall becompensated as described in the RATE paragraph below. In the event Company determinesthat it is necessary to increase the capacity of facilities beyond those required to serve Customer’selectrical requirement or to install a dedicated transformer or other equipment to protect the safetyand adequacy of electric service provided to other customers, Customer shall pay the estimated costof the required transformer or other equipment above the estimated cost which Company wouldotherwise have normally incurred to serve Customer’s electrical requirement, in advance ofreceiving service under this Rider.

9. The rates set forth herein are subject to Commission Order No. 2015-194, issued in Docket No.2014-246-E pursuant to the terms of S.C. Code § 58-40-20(F)(4). Eligibility for this rate willterminate as set forth in that Order, and otherwise as specified above. The value of NEM generationeligible for this Rider shall be computed using the methodology contained in Commission Order No.2015-194, in Docket No. 2014-246-E, and shall be updated annually by Company. The value ofNEM generation for 2016 is $0.04829 per kWh for Schedules RES, R-TOUD, R-TOUE, and SGSand $0.04836 for all other schedules.

RATE

All provisions of the applicable schedule and other applicable riders will apply to service supplied under this Rider, except as modified herein. For any bill month during which the Energy Charges are a net credit, the respective Energy Charges for the month shall be zero. Credits shall not offset the Basic Facilities Charge or the Demand Charge (if applicable). In addition to all charges in the applicable rate schedule for Customer’s net electrical usage, the following credit may be applicable annually:

Annual Credit for Excess Generation –

If Customer has Excess Energy after offsetting usage as of the date of the March billing, Company shall pay Customer for the amount of the accumulated Excess Energy times a rate of $0.0429 per kWh, after which the amount of Excess Energy shall be set to zero.

MINIMUM BILL

The monthly minimum bill for customers receiving service under this Rider shall be no less than Basic Facilities Charge from the applicable rate schedule and riders plus, if applicable, any of the following Charges: the Demand Charge, the Off-peak Excess Demand Charge, and the Additional Facilities Charge.


METERING REQUIREMENTS

Customer must provide access and designate a location on the load side of the billing meter for Company to furnish, install, own and maintain metering with 15-minute interval capability to record 100% of Customer’s generator output. At Company’s sole option, the generator meter requirement may be waived for customers served under a net metering rider on or before December 31, 2015. Company will also furnish, install, own and maintain a billing meter to measure the kilowatt demand delivered by Company to Customer, and to measure the net kWh purchased by Customer or delivered to Company. For renewable generation capacity of 20 kW AC or less, the billing meter will be a single, bi-directional meter which records independently the net flow of electricity in each direction through the meter, unless Customer’s overall electrical requirement merits a different meter. For larger renewable generation capacities, Company may elect to require two meters with 15-minute interval capabilities to separately record Customer’s electrical consumption and the total generator output, which will be electronically netted for billing. All metering shall be at a location that is readily accessible by Company.

SAFETY, INTERCONNECTION AND INSPECTION REQUIREMENTS

This Rider is only applicable for installed renewable generation systems and equipment that complies with and meets all safety, performance, interconnection, and reliability standards established by the Commission, the National Electric Code, the National Electrical Safety Code, the Institute of Electrical and Electronic Engineers, Underwriter’s Laboratories, the Federal Energy Regulatory Commission and any local governing authorities. Customer must comply with all liability insurance requirements of the Interconnection Standard.

POWER FACTOR

Customer’s renewable generation must be operated to maintain a 100% power factor, unless otherwise specified by Company. When the average monthly power factor of the power supplied by Customer to Company is other than 100%, the Low Power Factor Adjustment stated in Company’s Service Regulations may be applicable. Company reserves the right to install facilities necessary for the measurement of power factor. Company will not install such equipment, nor charge a Low Power Factor Adjustment if the renewable generation system is less than 20 kW AC and uses an inverter.

CONTRACT PERIOD

Customer shall enter into a contract for service under this Rider for a minimum original term of one (1) year, and shall automatically renew thereafter, except that either party may terminate the contract after one year by giving at least sixty (60) days prior notice of such termination in writing.

Company reserves the right to terminate Customer’s contract under this Rider at any time upon written notice to Customer in the event that Customer violates any of the terms or conditions of this Rider, or operates the renewable generation system and equipment in a manner which is detrimental to Company or any of its customers. In the event of early termination of a contract under this Rider, Customer will be required to pay Company for the costs due to such early termination, in accordance with Company's South Carolina Service Regulations.

Supersedes Rider RNM-1 Effective for service rendered on and after July 1, 2016 SCPSC Docket No. 2016-001-E, Order No. 2016-_______


Duke Energy Progress, LLC RR-22 (South Carolina)

RENEWABLE NET METERING RIDER RNM-12

AVAILABILITY

Available to residential and nonresidential Customers receiving concurrent service from Company, on a metered rate schedule, except as indicated under General Provisions. The renewable net energy metered (NEM) generation, which includes a solar photovoltaic; solar thermal; wind powered; hydroelectric; geothermal; tidal or wave energy; recycling resource; hydrogen fueled or combined heat and power derived from renewable resources; or biomass fueled generation source of energy, is installed on Customer’s side of the delivery point, for Customer’s own use, interconnected with and operated in parallel with Company’s system. The generation must be located at a single premises owned, operated, leased or otherwise controlled by Customer.

Service under this Rider is closed to new participants on and after January 1, 2021, or when the statutory minimum system capacities described in S.C. Code § 58-39-130 have been reached, whichever occurs first. Customers requesting NEM service after January 1, 2021, will receive service in accordance with the NEM tariff in effect at that time. This Rider shall expire and no longer be available for NEM service on and after January 1, 2026.

GENERAL PROVISIONS

1. To qualify for service under this Rider, Customer must comply with all applicable interconnectionstandards and must provide, in writing, the Nameplate Capacity of Customer’s installed renewablegeneration system. Any subsequent change to the Nameplate Capacity must be provided byCustomer to Company in writing by no later than 60 days following the change.

2. To qualify for service under this Rider, a residential customer may be served on an approvedresidential rate schedule, but may not be served under Rider NM. The Nameplate Capacity ofCustomer’s installed generation system and equipment must not exceed 20 kW AC.

3. To qualify for service under this Rider, a nonresidential customer may be served on an approvedgeneral service rate schedule, but may not be served on Schedules SGS-TES, TSS, TFS, LGS-RTP,LGS-CUR-TOU, CSG, CSE, GS, SFLS or Rider NM. The Nameplate Capacity of Customer’sinstalled renewable generation system and equipment must not exceed 1,000 kW AC or 100% ofCustomer’s contract demand which shall approximate Customer’s maximum expected demand.

4. If Customer is not the owner of the premises receiving electric service from Company, Companyshall have the right to require that the owner of the premises give satisfactory written approval ofCustomer’s request for service under this Rider.

5. Customers served under this Rider are not eligible to receive payment from Palmetto Clean Energy(PaCE) for energy generated by Customer’s renewable generation system. All environmentalattributes, including but not limited to “renewable energy certificates” (RECs), “renewable energycredits” or “green tags”, associated with the generation system shall be conveyed to Company untilbilling of a Distributed Energy Resource Program Rider DERP Charge is discontinued on allcustomer bills. Customer certifies that the environmental attributes have not and will not beremarketed or otherwise resold for any purpose, including another distributed energy resourcestandard or voluntary purchase of renewable energy certificates in South Carolina or in any otherstate or country for the Contract Period and any successive contract periods thereto.

6. If the electricity supplied to Customer by Company exceeds the electricity delivered to the grid bythe customer-generator during a monthly billing period, the customer-generator shall be billed for

Felt Exhibit 2


the net electricity in kilowatt hours (kWh) supplied by Company plus any demand or other charges under the applicable rate schedule or riders. If the electricity delivered to the grid by the customer-generator exceeds the electricity in kWh supplied by the utility during a monthly billing period, the customer-generator shall be credited for the excess kWh generated during that billing period.

7. Electricity delivered to the grid by Customer’s renewable generation that exceeds the electricity delivered by Company is defined as Excess Energy. When used in conjunction with a time of use schedule, the TOU periods shall be specified in the applicable schedule and any Excess Energy shall apply first with the Excess Energy generated On-Peak kWh offsetting On-peak usage and then offsetting Off-peak usage. Any excess Off-Peak kWh shall only apply against Off-peak kWh usage. Any Excess Energy not used in the current month to offset usage shall carry forward to the next billing month.

8. Excess Energy shall be used to reduce electricity delivered and billed by Company during the current or a future month, except that for the March billing period any carry-over shall be compensated as described in the RATE paragraph below. In the event Company determines that it is necessary to increase the capacity of facilities beyond those required to serve Customer’s electrical requirement or to install a dedicated transformer or other equipment to protect the safety and adequacy of electric service provided to other customers, Customer shall pay the estimated cost of the required transformer or other equipment above the estimated cost which Company would otherwise have normally incurred to serve Customer’s electrical requirement, in advance of receiving service under this Rider.

9. The rates set forth herein are subject to Commission Order No. 2015-194, issued in Docket No. 2014-246-E pursuant to the terms of S.C. Code § 58-40-20(F)(4). Eligibility for this rate will terminate as set forth in that Order, and otherwise as specified above. The value of NEM generation eligible for this Rider shall be computed using the methodology contained in Commission Order No. 2015-194, in Docket No. 2014-246-E, and shall be updated annually by Company. The value of NEM generation for 2015 2016 is $0.05097 0.04829 per kWh for Schedules RES, R-TOUD, R-TOUE, and SGS and $0.050950.04836 for all other schedules.

RATE

All provisions of the applicable schedule and other applicable riders will apply to service supplied under this Rider, except as modified herein. For any bill month during which the Energy Charges are a net credit, the respective Energy Charges for the month shall be zero. Credits shall not offset the Basic Facilities Charge or the Demand Charge (if applicable). In addition to all charges in the applicable rate schedule for Customer’s net electrical usage, the following credit may be applicable annually:

Annual Credit for Excess Generation –

If Customer has Excess Energy after offsetting usage as of the date of the March billing, Company shall pay Customer for the amount of the accumulated Excess Energy times a rate of $0.045970.0429 per kWh, after which the amount of Excess Energy shall be set to zero.

MINIMUM BILL

The monthly minimum bill for customers receiving service under this Rider shall be no less than Basic Facilities Charge from the applicable rate schedule and riders plus, if applicable, any of the following Charges: the Demand Charge, the Off-peak Excess Demand Charge, and the Additional Facilities Charge.


METERING REQUIREMENTS

Customer must provide access and designate a location on the load side of the billing meter for Company to furnish, install, own and maintain metering with 15-minute interval capability to record 100% of Customer’s generator output. At Company’s sole option, the generator meter requirement may be waived for customers served under a net metering rider on or before December 31, 2015. Company will also furnish, install, own and maintain a billing meter to measure the kilowatt demand delivered by Company to Customer, and to measure the net kWh purchased by Customer or delivered to Company. For renewable generation capacity of 20 kW AC or less, the billing meter will be a single, bi-directional meter which records independently the net flow of electricity in each direction through the meter, unless Customer’s overall electrical requirement merits a different meter. For larger renewable generation capacities, Company may elect to require two meters with 15-minute interval capabilities to separately record Customer’s electrical consumption and the total generator output, which will be electronically netted for billing. All metering shall be at a location that is readily accessible by Company.

SAFETY, INTERCONNECTION AND INSPECTION REQUIREMENTS

This Rider is only applicable for installed renewable generation systems and equipment that complies with and meets all safety, performance, interconnection, and reliability standards established by the Commission, the National Electric Code, the National Electrical Safety Code, the Institute of Electrical and Electronic Engineers, Underwriter’s Laboratories, the Federal Energy Regulatory Commission and any local governing authorities. Customer must comply with all liability insurance requirements of the Interconnection Standard.

POWER FACTOR

Customer’s renewable generation must be operated to maintain a 100% power factor, unless otherwise specified by Company. When the average monthly power factor of the power supplied by Customer to Company is other than 100%, the Low Power Factor Adjustment stated in Company’s Service Regulations may be applicable. Company reserves the right to install facilities necessary for the measurement of power factor. Company will not install such equipment, nor charge a Low Power Factor Adjustment if the renewable generation system is less than 20 kW AC and uses an inverter.

CONTRACT PERIOD

Customer shall enter into a contract for service under this Rider for a minimum original term of one (1) year, and shall automatically renew thereafter, except that either party may terminate the contract after one year by giving at least sixty (60) days prior notice of such termination in writing.

Company reserves the right to terminate Customer’s contract under this Rider at any time upon written notice to Customer in the event that Customer violates any of the terms or conditions of this Rider, or operates the renewable generation system and equipment in a manner which is detrimental to Company or any of its customers. In the event of early termination of a contract under this Rider, Customer will be required to pay Company for the costs due to such early termination, in accordance with Company's South Carolina Service Regulations.

Supersedes Rider RNM-1 Effective for service rendered on and after August 12, 2015July 1, 2016 SCPSC Docket No. 2015-204-E2016-001-E, Order No. 2015-5922016-_______

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