new duke energy. - transmissionhub.com · 2019. 4. 29. · duke energy corporation 550 soulh tryon...

( .., DUKE 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.

Jocelyn G. Boyd April 28, 2016 Pagc2

By copy of this letter, I am serving all parties of record via electronic mail. Please contact me if you have any questions concerning this liling.

Charles A. Castle

Enclosures cc: 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

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