application, direct testimony and exhibits ofvirginia ... · application, direct testimony and...

Application, DirectTestimony and Exhibitsof Virginia Electricand Power Company

Before the State CorporationCommission of Virginia

Application of Virginia Electricand Power Company to revise itsfuel factor pursuant to Va. Code§ 56-249.6

Case No. PUE-2015-00022

Filed: February 27, 2015

PUBLIC VERSION

DIRECT TESTIMONY AND EXHIBITS

OF

STEVEN A. ROGERS

ROBERT G. THOMAS

GLENN A. KELLY

GREGORY A. WORKMAN

TOM A. BROOKMIRE

ALAN L. MEEKINS

JOHN C. INGRAM

EDWARD J. ANDERSON

COMMONWEALTH OF VIRGINIA

STATE CORPORATION COMMISSION

APPLICATION OF ))

VIRGINIA ELECTRIC AND POWER COMPANY ))

To revise its fuel factor pursuant to Va. Code )§ 56-249.6 )

Case No. PUE-2015-00022

APPLICATION AND REQUEST FOR PARTIAL WAIVER

Pursuant to § 56-249.6 of the Code of Virginia ("Va. Code"), Virginia Electric and Power

Company ("Dominion Virginia Power" or the "Company"), by counsel, files this Application to

revise its fuel factor effective April 1, 2015 ("Application"). In support of its Application,

Dominion Virginia Power respectfully states the following;

1. Dominion Virginia Power is a public service corporation organized under the

laws of the Commonwealth of Virginia furnishing electric service to the public within its

certificated service territory. The Company also supplies electric service to nonjurisdictional

customers in Virginia and to the public in portions of North Carolina. Dominion Virginia

Power's electric system, consisting of facilities for generation, transmission and distribution of

electric energy, as well as associated facilities, is interconnected with the electric systems of

neighboring utilities and is part of the interconnected network of electric systems serving the

continental United States. By reason of its operations in Virginia and North Carolina and its

interconnections with other electric utilities, the Company engages in interstate commerce. The

post office address of Dominion Virginia Power is P.O. Box 26666, Richmond, Virginia 23261.

2. The facts supporting this Application are set forth in the accompanying testimony

and exhibits of Steven A. Rogers, Robert G. Thomas, Glenn A. Kelly, Gregory A. Workman,

Tom A. Brookmire, Alan L. Meekins, John C. Ingram, and Edward J. Anderson.

3. The testimony and exhibits demonstrate that a revision to Dominion Virginia

Power's existing fuel factor rate is necessary to provide the Company with the appropriate level

of fuel cost recovery pursuant to Va. Code § 56-249.6 over the period beginning April 1, 2015

through June 30, 2016.

4. Dominion Virginia Power is requesting in this Application a total fuel factor of

2.406 cents per kilowatt-hour ("¢/kWh"), which represents a 0.612¢/kWh decrease from the total

fuel factor currently in effect of3.018¢/kWh, and results in a fuel revenue decrease of

approximately $512.3 million when applied to the projected current period kWh sales over the

period April 1,2015 - June 30, 2016.

5. The Company is requesting that the Commission implement the proposed fuel

rate reduction effective for usage on and after April 1, 2015, on an interim basis, with such

further proceedings in this docket after that time as the Commission deems appropriate,

consistent with the directives of Senate Bill 1349, which was recently enacted by the General

Assembly of Virginia during its 2015 Regular Session and signed into law by Governor

McAuliffe on February 24, 2015 ("Senate Bill 1349" or the "Legislation").' Under the

Legislation, the Company is required to forgo recovery of 50% of the Company's prior period

deferred fuel expense recovery balance on its books and records as of December 31, 2014 - or

approximately $85 million - from customers. In addition, the Legislation directs the

Commission to implement reductions in the Company's fuel factor rate "as soon as practicable"

to reflect this non-recovery, as well as any reduction in the fuel factor associated with the

Company's current period forecasted fuel expense over-recovery for the 2014-2015 fuel year,

and the projected fuel expense for the 2015-2016 fuel year. To facilitate the accelerated

implementation of a fuel rate reduction, the Company is filing its Application, testimony and

12015 Virginia Acts of Assembly, Ch. 6, Enactment Clause 2 (approved February 24, 2015; effective July 1,2015).

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schedules supporting a revision to the fuel factor approximately two months ahead of the typical

early May filing date, and requests that the Commission implement the lower fuel rate, on an

interim basis, for the fifteen-month period commencing April 1, 2015 and ending June 30, 2016.

6. The Company's total fuel factor, reflected in Fuel Charge Rider A, consists of

both a current and prior period factor. As discussed by Company Witness Anderson, for the July

1,2015 through June 30, 2016 fuel year (the "current period"), the Company projects Virginia

jurisdictional fuel expenses, including purchased power expenses, of approximately $1.6 billion,

resulting in a current period fuel factor rate of2.374¢/kWh. Fuel Charge Rider A's prior period

fuel factor rate of 0.032¢/kWh is designed to recover approximately $21.9 million, which

represents the net of two projected June 30, 2015 fuel deferral balances. The first balance is the

projected June 30, 2015 over-recovery balance of approximately $24.0 million associated with

recovery of the July 2014 through June 2015 period expense. The second balance is the

projected June 30, 2015 under-recovery balance of approximately $45.9 million associated with

recovery of the remaining portion of the January 31, 2015 prior period expense to be recovered

through June 30, 2015. This prior period factor also reflects the 50% reduction to the deferral

balance as of December 31, 2014 of approximately $85 million, as discussed by Company

Witness Ingram.t

7. In connection with this Application, the Company is also proposing a

modification to the Commission's Definitional Framework of Fuel Expenses for Virginia

Electric and Power Company, as described in the accompanying testimony and exhibits of

Company Witnesses Rogers and Ingram.

8. Rule 80.A of the Commission's Rules Governing Utility Rate Applications and

2 As Company Witness Anderson explains, this is a savings to customers of $0.00 102/kWh per month, or$1.02/MWh, based on projected sales for the period April 2015 - June 2016.

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Annual Informational Filings ("Rate Case Rules"), 20 VAC 50-201-80.A, requires that "[i]n the

event that an electric utility files an application to change the fuel factor, fuel factor projections

shall be filed at least six weeks prior to the proposed effective date."

9. As noted, the Company's annual application to revise its fuel factor is typically

filed with the Commission around May 1 of each year, with a requested implementation date of

July 1. Given the directive of Senate Bill 1349 to implement a fuel rate reduction "as soon as

practicable," the Company is filing its Application to change its fuel factor approximately two

months ahead of the typical filing date and is requesting the lower fuel rate be implemented for

usage on and after April 1,2015, on an interim basis, with such further proceedings in this

docket following that time which the Commission deems appropriate. Under this accelerated

schedule, the Company's fuel factor projections are being filed approximately four weeks prior

to the proposed effective date, rather than six weeks prior as prescribed by Rule 80.A.

10. Rule 10.E of the Rate Case Rules, 20 VAC 5-201-10.E, provides the Commission

with the discretion to "waive any or all parts of this chapter for good cause shown." For these

reasons and for good cause shown, the Company requests that the Commission grant a partial

waiver of the requirements of Rule 80.A and permit a shortened period between the filing of the

fuel factor projections and the proposed effective date of the fuel factor change.

WHEREFORE, Dominion Virginia Power respectfully files the proposed fuel factor of

2.406¢/kWh, as set out herein, on an interim basis, effective for usage on and after April 1,2015,

and requests the Commission grant the Company a partial waiver of Rule 80.A.

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Respectfully submitted,

VIRGINIA ELECTRIC AND POWER COMPANY

By:_.:::::::.:::::::=====-=-~+::::::::===-__Counsel

William H. Baxter IIDominion Resources Services, Inc.120 Tredegar Street, Riverside 2Richmond, Virginia 23219(804) 819-2458 (telephone)(804) 819-2183 (facsimile)william. [email protected]

Joseph K. Reid, IIIElaine S. RyanMcGuireWoods LLPOne James Center901 E. Cary StreetRichmond, Virginia 23219(804) 775-1198 (JKR telephone)(804) 775-1090 (ESR telephone)(804) 698-2146 (facsimile)[email protected]@mcguirewoods.com

Counselfor Virginia Electric and Power Company

February 27, 2015

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DIRECT TESTIMONYOF

STEVEN A. ROGERSON BEHALF OF

VIRGINIA ELECTRIC AND POWER COMPANYBEFORE THE

STATE CORPORATION COMMISSION OF VIRGINIACASE NO. PUE-2015-00022

Please state your name, business address, and position of employment.

My name is Steven A. Rogers and my business address is 120 Tredegar Street,

Richmond, Virginia 23219. I am Senior Vice President - Financial Management for

Dominion Generation. A statement of my background and qualifications is attached as

Appendix A.

What are your management responsibilities with respect to Virginia Electric and

Power Company ("Dominion Virginia Power" or the "Company")?

I am responsible for the financial management of Dominion's generating business. This

includes responsibility for financial analysis, forecasting and budgeting functions, fuel

procurement, and generation system planning.

What is the purpose of your testimony in this proceeding?

I will describe the calculation of fuel costs that are recoverable by the Company over the

period beginning April 1, 2015 through June 30, 2016 and briefly discuss the elements

that are responsible for the significant decrease in the Company's fuel factor rate. In

addition, I will address the Company's request to implement the proposed fuel rate

reduction on April 1, 2015, on an interim basis, consistent with the directives of Senate

Bill 1349, which was recently enacted by the General Assembly of Virginia during its

2015 Regular Session and signed into law by Governor McAuliffe on February 24, 2015

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("Senate Bill 1349" or "the legislation"). I My testimony also discusses certain

operational performance metrics and our ongoing initiatives to reduce fuel costs on behalf

of our customers.

You mentioned Senate Bill 1349. How does this legislation impact the Company's

2015 fuel factor proceeding?

Two key elements of the legislation are relevant to this proceeding. First, the legislation

requires that 50% of the Company's prior period deferred fuel expense recovery balance

on its books and records as of December 31, 2014 - representing approximately $85

million - not be recovered from customers. In addition, the legislation directs the State

Corporation Commission of Virginia ("Commission") to implement reductions in the

Company's fuel factor rate "as soon as practicable" to reflect this non-recovery, as well

as any reduction in the fuel factor associated with the Company's current period

forecasted fuel expense over-recovery for the 2014-2015 fuel year, and the projected fuel

expense for the 2015-2016 fuel year. These three components contribute to a significant

fuel rate reduction for the benefit of our customers.

To facilitate the accelerated implementation of a fuel rate reduction, the Company is

filing its application, testimony and schedules supporting a revision to the fuel factor

approximately two months ahead of the typical early May filing date, and requests that

the Commission implement the lower fuel rate, on an interim basis, effective for usage on

and after April 1, 2015. Given the General Assembly's directive, the Company has

calculated a fuel factor rate which combines the effect of the three components described

above and which would remain in effect, with Commission approval, for the fifteen-

12015 Virginia Acts of Assembly, Ch. 6, Enactment Clause 2 (approved February 24,2015; effective July 1,2015).

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month period commencing April 1, 2015 and ending June 30, 2016, thereby accelerating

the rate reduction and avoiding any volatility in the fuel rate which might be associated

with a second change on the typical implementation date of July 1.

What fuel factor does the Company propose in this case?

The Company is proposing a fuel rate reduction of approximately 20% from the 3.018

¢/kWh rate previously approved by this Commission in Case No. PUE-2014-00033 (the

"2014 Fuel Factor").

The proposed Virginia jurisdictional fuel rate is comprised of two elements. First, for the

July 1,2015 through June 30, 2016 fuel year (the "current period"), the Company

projects Virginia jurisdictional fuel expenses, including purchased power expenses, of

approximately $1.6 billion, translating into a current period fuel factor rate of

2.374¢/kWh, as Company Witness Edward J. Anderson discusses. Second, the

Company's projected June 30, 2015 fuel deferral balance (the "prior period") is

approximately $21.9 million, representing the net of the projected June 30, 2015 over

recovery of expenses during the July 1,2014 - June 30, 2015 fuel period, and the

projected June 30, 2015 under-recovery of expenses associated with the remaining

January 31, 2015 prior period expense, resulting in a prior period factor of 0.032¢/kWho

This prior period factor also reflects a 50% reduction to the deferral balance as of

December 31, 2014 of approximately $85 million as discussed by Company Witness John

C. Ingram. Together, these components translate into a total proposed fuel factor rate of

2.406¢/kWh for the period April 1,2015 - June 30, 2016, as Company Witness Anderson

explains.

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As Company Witness Anderson also details in his testimony, this fuel rate reduction will

result in a decrease to the typical residential customer's monthly electric bill of

approximately $6.12. For our higher volume energy consumers in the commercial and

industrial classes, the savings will be significantly higher.

What are the major factors underlying the Company's ability to reduce the fuel

factor rate in this proceeding?

The over-recovery during the 2014-2015 fuel year was driven principally by lower than

expected commodity and power prices, particularly those for natural gas, as well as

milder than normal weather in the summer and fall. In addition, our investment in

highly-efficient generation resources like the Bear Garden Power Station and the new

Warren County Power Station ("Warren") have strengthened our fuel diversity and

allowed us to leverage these low gas prices for the benefit of customers. These trends

helped to reduce our fuel costs in the 2014-2015 fuel year, and are projected to continue

during the 2015-2016 fuel year.

The significant decline in natural gas prices compared to forecast is addressed on page 10

of Company Witness Kelly's testimony. Natural gas prices have dropped as much as

38% since last year's filing, from a forecasted $5.03 per one million British thermal units

("MMBtu") for the July 2014 - June 2015 fuel year to $3. 12/MMBtu through January

2015, as Mr. Kelly's testimony demonstrates.

Company Witness Kelly's testimony also illustrates the significant decline in power

prices, which correlate to low gas costs when gas units drive the marginal pricing in the

PJM Interconnection, L.L.C. ("PJM") marketplace. He shows that on-peak power prices

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for the PJM Western Hub have fallen by 20% since last year's filing.

Are there any changes in generation capacity during this upcoming fuel year?

Yes, the Brunswick County Power Station ("Brunswick"), a 1,358 MW (nominal)

natural-gas fired combined-cycle generation facility, is expected to become operational in

May 2016. Employing state-of-the-art 3xl gas combined-cycle technology, Brunswick

will further strengthen the mix of fuels and generation resources now available to the

Company and enhance our existing operational efficiencies to the benefit of our

customers. Like Warren, the facility's heat rate will be among the best in the nation when

it enters service, resulting in reduced fuel costs and lower emissions. Possum Point Unit

6, a combined-cycle 559 MW unit, will be uprated by 27 MW in May 2015.

While not directly at issue in this proceeding, how is the Company's generation fuel

mix expected to change over the next several years?

As discussed in the Company's Fuel Procurement Strategy Report ("Report") filed on

January 30, 2015 in the 2014 Fuel Factor, the Company's natural gas-fired units now

provide baseload, intermediate, and peaking services, and in 2014 met approximately

15% of the Company's annual energy requirements. By 2019, the natural gas percentage

of energy production is expected to increase to as much as 40%, with corresponding

decreases in the percentage of system energy derived from coal and purchased power, as

new, efficient gas-fired generation resources like Brunswick come on-line.

How does this increase in natural gas as a percentage of system energy impact the

Company's gas procurement strategy?

The Company's approach to natural gas procurement continues to involve two primary

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goals: (1) ensuring adequate supply to provide reliable and cost-effective service, and (2)

reasonably mitigating price volatility for customers. As discussed in the Report, in order

to support the growing need for physical supplies of natural gas, the Company believes

that it is prudent to modify its existing gas procurement practices to include more firm

transportation agreements sourced from diverse locations and longer-term (terms greater

than day ahead or intra-day) gas supply contracts as compared to our current approach

(day ahead or intra-day). Using a greater percentage of longer-term natural gas supply

arrangements sourced directly from diverse locations will promote greater certainty of

supply. This longer-term gas procurement approach is also consistent with the

Company's multiyear contracting approach for procuring coal supplies. Additionally, the

Company will continue to use financial hedging instruments to mitigate price volatility

for this historically volatile commodity.

Does the Company intend to make any changes to its price hedging practices?

Yes. Given the projected increase in the volume of natural gas purchases over the next

several years, the Company plans to expand its forward price hedging activity from one

year to three years. In addition, the Company intends to increase price hedging levels to a

target range of 20% to 50% of forecasted volumes to be purchased in the first year of a

three-year period. These new natural gas price hedging targets are expected to be

achieved via the pricing associated with the gas supply and transportation procurement

activities described above, as well as the continued use of derivative instruments to

financially hedge a portion of these volumes.

The Company's forecasted energy requirements and fuel expense for the 2015-2016 fuel

year presented by Company Witness Kelly reflect a movement toward these new targets,

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which are addressed in more detail in the Report. The Company also anticipates that

purchased power volumes will gradually decrease, but we will continue to use derivative

instruments to financially hedge a portion of these volumes when such instruments are

available and beneficial for our customers.

Is the Company proposing any changes in this proceeding to its Definitional

Framework of Fuel Expenses (the "Definitional Framework") in connection with

these plans?

Yes. As Company Witness Ingram notes, in order to support the expansion of its

financial hedging activities, the Company is proposing to add a new Paragraph (d) to the

existing Definitional Framework to explicitly reaffirm that gains and losses, including

option premiums, arising from the use of derivative instruments to financially hedge fuel

and purchased power are recoverable through the Company's fuel factor. The proposed

change is shown in Company Exhibit No. _, lCI, Schedule 4.

As Company Witness Ingram explains, it is possible that derivatives employed in future

financial hedging transactions for natural gas and purchased power may not meet or

maintain the strict requirements for "hedge accounting treatment." These types of

transactions, referred to as "economic hedges," are undertaken with the objective of

promoting rate stability and mitigating price volatility for customers under the

Company's hedging program. To accommodate these circumstances, the Company

believes that a modification to the text of the Definitional Framework to explicitly

reaffirm that gains and losses, including option premiums, arising from the use of

derivative instruments are recoverable through the fuel factor, regardless of whether they

qualify for "hedge accounting treatment," is necessary and appropriate. These

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transactions provide an important tool and this change would allow for these activities to

continue to provide benefits for our customers in the future, particularly as the Company

moves toward the new price hedging targets for gas. Importantly though, as Company

Witness Ingram explains, the Company will not seek to recover through the fuel factor

any costs arising from the use of derivative instruments that are currently recovered

through base rates.

As measured by Equivalent Forced Outage Rate on demand ("EFORd"), how did

the Company's generation fleet perform in 2014 compared to that of other units

within PJM?

For the period January through September 2014, the Company had a fleet EFORd of

3.24%, which compares very favorably to the PJM pool-wide average of9.7% over the

same period.

In closing, can you summarize the key aspects of the Company's generation, fuel

procurement, and purchased power acquisition practices?

Yes. The Company employs a comprehensive strategy to meet our customers' needs and

demands for power at the lowest reasonable cost utilizing its diverse mix of reliable,

efficient self-generation and non-utility generation resources as well as economy

purchases from the wholesale power markets. The Company will continue to act

prudently in its fuel procurement practices to minimize costs for the coal, oil, natural gas,

wood and nuclear fuel that we must purchase to run our power plants. We will also

continue to buy in the PJM spot energy market when doing so is cost-advantageous

relative to the costs of self-generation. Company Witness Alan L. Meekins discusses the

savings that access to these markets provided for our customers in 2014.

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Fuel costs are a significant component of overall rates for all classes of our customers,

and they are influenced in many respects by conditions that are external to the Company

and beyond its control - including extreme weather and market price fluctuations. The

availability of a diverse fleet of generation assets, using a variety of fuels and

technologies, is a primary tool in protecting our customers from the effects of commodity

price volatility, commodity delivery disruptions, and other external factors. The addition

of new, efficient resources such as Warren and Brunswick will enhance these efforts for

the benefit of customers.

Ensuring reliable and sufficient access to fuel supply and transport is another significant

component of the Company's fuel procurement strategy. To achieve this objective with

respect to natural gas, the Company follows a disciplined protocol of purchasing both

supply and transport from a diverse portfolio of suppliers and supply regions, with

various contract terms and prices.

As noted, uncertainty in future commodity prices exposes the Company and its customers

to unpredictable changes in fuel costs. To help mitigate this risk, the Company also

transacts physical and financial instruments in the marketplace to hedge against potential

fuel price changes in the future. Together, these three components of the Company's

comprehensive fuel procurement strategy help to ensure that fuel costs remain as

reasonable as possible for our customers, both now and in the future.

What Company witnesses are filing testimony in this case?

The Company is presenting the following additional witnesses, several of whom I have

already mentioned in my testimony:

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III Mr. Robert G. Thomas, Director of Energy Market Analysis and IntegratedResource Planning, discusses the development of the projected commodity pricesfor fossil fuels, emissions allowances, and PJM economy power purchases;

III Mr. Glenn A. Kelly, Director of Generation System Planning, providesinformation on the forecast of the current period fuel costs, as well as themethodology and models used to project total system energy and fuel costs;

III Mr. Gregory A. Workman, Director of Fuels, discusses the Company's fossil fuelprocurement practices;

III Mr. Tom A. Brookmire, Supervisor of Nuclear Fuel Procurement, discusses thecomponents of the Company's nuclear fuel cost and the Company's projectednuclear fuel expense rate;

III Mr. Alan L. Meekins, Director of Electric Market Operations, explains theCompany's interface with PJM, as well as customer savings realized from PJMeconomy energy purchases;

III Mr. John C. Ingram, Director of Generation Accounting, presents the prior periodaccounting balances for the Company's proposed fuel factor, the proposed changeto the Company's Definitional Framework, an update on the status of theCompany's judgment against the DOE, and other accounting-related matters; and

III Mr. Edward J. Anderson, Regulatory Advisor, presents the calculations of thecurrent period and prior period components for the Company's proposed fuelfactor, along with the impact on typical customer bills.

Does this conclude your pre-filed direct testimony?

Yes, it does.

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APPENDIX A

BACKGROUND AND QUALIFICATIONSOF

STEVEN A. ROGERS

Steven A. Rogers graduated from the College of the Holy Cross with a degree in

Economics/Accounting and started his career with the accounting firm Deloitte. He is currently

Senior Vice President - Financial Management, Dominion Generation. In this role, he is

responsible for financial analysis, forecasting, budgeting functions, fuel procurement, and

generation system planning.

Mr. Rogers joined Dominion in 1996 as manager-Internal Audit and has held controller

positions with several Dominion companies. He was named vice president and controller of

Dominion Resources Inc. in June 2000 and promoted to senior vice president and controller in

April 2006. He became senior vice president and chief accounting officer in January 2007.

In October, 2007, Mr. Rogers was named president and chief administrative officer of

Dominion Resources Services Inc. He became senior vice president and chief information

Officer in January 2013, and assumed his current post in January 2014.

From 2006 to 2009, Mr. Rogers was a member of the Financial Accounting Standards

Advisory Council - an advisory body to the Financial Accounting Standards Board. He has

served with several industry groups while in his accounting and Information Technology roles.

In the Richmond community, he serves on the board of directors of CenterStage Foundation,

serves as Treasurer of the Library of Virginia Foundation Board, and as Treasurer of MSR2020.

Mr. Rogers has previously testified before the State Corporation Commission of

Virginia.

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DIRECT TESTIMONYOF

ROBERT G. THOMASON BEHALF OF




My name is Robert G. Thomas and my business address is 120 Tredegar Street,

Richmond, Virginia 23219. I am the Director of Energy Market Analysis and Integrated

Resource Planning in the Budgeting, Business Planning & Market Analysis Department.

In my current position, I am responsible for various analytic activities, including the

development of commodity price projections used by Virginia Electric and Power

Company ("Dominion Virginia Power" or the "Company"). A statement of my

background and qualifications is attached as Appendix A.


My testimony will explain the sources and development of the commodity price

projections used to support the Company's fuel expense projections.

During the course of your testimony, will you introduce an exhibit?

Yes. Company Exhibit No. _, RGT, consisting of Schedules 1 through 3, was prepared

under my supervision and direction, and is accurate and complete to the best of my

knowledge and belief.

Please describe the Company's overall process for projecting commodity prices.

Commodity price projections are compiled from market data sources for the Company's

planning horizon. The availability and transparency of forward commodity markets over

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the last several years have eliminated the need to produce forecasts for short-term time

horizons. Each month, a comprehensive set of market-based projected commodity prices

for natural gas, gas basis, crude oil, No.6 fuel oil, No.2 fuel oil, Central and Northern

Appalachian coal, emissions allowance costs, and power is compiled. Schedule 1 shows

prices as of January 31, 2015 for the fuel factor period beginning April 1, 2015 through

June 30, 2016.

Please describe the source data and method for developing the natural gas price

projections.

Natural gas price projections are based on New York Mercantile Exchange Clearport

("NYMEX") Henry Hub futures prices. Henry Hub, located in Louisiana, is a pooling

point of several pipelines from various supply regions in the Gulf of Mexico. Henry Hub

is widely used throughout the industry as a benchmark for natural gas prices.

Please describe the source data and method for developing the natural gas basis

price projections.

Natural gas basis price projections are based on Intercontinental Exchange ("ICE")

futures prices and Platts postings. Natural gas for the Company's fleet is primarily

purchased at several different market points: Transco Zone 5 and Zone 6 Non-New York

("NNY"), TCO Pool (Columbia Gas Transmission), and Dominion South Point. Gas

basis at Transco Zone 6NNY, Dominion South Point, and TCO Pool are all traded on

ICE. Gas basis at Transco Zone 5 is based on Platts postings.

Please describe the source data and method for developing oil price projections.

Projections for crude oil and No.2 fuel oil are based on NYMEX Clearport futures

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products. West Texas Intermediate ("WTI") crude oil is a light sweet product delivered

to Cushing, Oklahoma that is priced in terms of $/barrel. This forward contract is a

widely used benchmark throughout the industry. For No.2 fuel oil, futures contracts

with a delivery point at New York Harbor are used. Prices are stated in $/gallon, and

converted to $/MMBtu using a conversion factor of 7.2 gallons/MMBtu. Because there

is no No.6 fuel oil product traded on NYMEX, a commonly used broker source, A.E.

Bruggemann & Co. Energy Brokers, is employed. The product is defined as 1% sulfur

residual oil (quoted in $/bbl), and then converted to $/MMBtu by dividing the quote by a

6.3 MMBtu/bbl conversion factor.

Please describe the source data and method for developing coal price projections.

For projection purposes, three distinct product prices based on market quotes are

compiled. Specifically, coal price data are obtained from United Power, a division of

ICAP United, Inc., which is the primary source for coal pricing in the industry. The first

product quote is a Central Appalachian coal with a 12,500 Btu/lb heating value and 1.6

Ib/MMBtu sulfur dioxide (S02) content obtained using the CSX Corporation railway

system. The second product quote has the same specifications, but is delivered using the

Norfolk Southern Corporation railway system. The final product quote is a Northern

Appalachian coal with a 13,000 Btu/lb heating value and 3.8-4.2Ib/MMBtu S02 content.

All three of these coals have the potential to be burned in the Company's generating units

depending upon commodity and transportation pricing, and specific unit characteristics.

Please describe the source data and method for developing emissions price

projections.

On October 23,2014, the U.S. Court of Appeals for the D.C. Circuit lifted the stay on the

3

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17 Q.

18

19

20 A.

21

22

Cross State Air Pollution Rule ("CSAPR"), allowing implementation of Phase 1 on

January 1,2015. CSAPR replaces the Clean Air Interstate Rule ("CAIR"). CSAPR

requires states to improve air quality by limiting power plant emissions that cross state

lines. The rule covers 23 states, requiring reductions in both nitrogen oxide ("NOx") and

sulfur dioxide ("S02") emissions. States in Group 1 (including Virginia) will be required

to make additional reductions to S02 emissions when Phase 2 is implemented in 2017.

CSAPR is an emissions allowance-based "cap-and-trade" program. The allowances

originally issued in 2011 for 2012 and 2013 have been re-vintaged for 2015 and 2016.

Under CSAPR, environmental S02 and NOx allowance pricing is obtained from

Evolution Markets, Inc., a commonly used industry source for environmental pricing

data. The price quotes contained in my Schedules are given in dollars per short ton of

S02 or NOx allowances available in the market.

There are two "cap-and-trade" markets for NOx. The first applies throughout the entire

year, and includes the 23 states mandated by CSAPR to reduce emissions, including

Virginia. The second is a seasonal ozone program and applies to 25 states, also including

Virginia. This program creates a five-month ozone season (May-September).

Describe the source data and method for developing power price ($/MWh)

projections, including an explanation and determination of locational power price

differences.

Price projections for the PJM Interconnection, L.L.C. ("PJM") Dominion Zone ("Dom

Zone") region are developed using forward price quotes for the PJM Western Hub

("PJM- W"), along with a locational adjustment to reflect delivery to Dom Zone. This is

4

1

2

3

4

5

6

7 Q.

8

9 A.

10

11

12 Q.

13

14 A.

15

16 Q.

17 A.

necessary because forward PJM Dom Zone quotes are not readily available. The PJM-W

forward price projections are based on ICE-reported forward over-the-counter settlement

prices. The locational difference is based on historical average differentials for both

congestion and losses dating back to February 1,2013 between the PJM-W Hub region

and the PJM Dom Zone delivery point. This locational differential is then applied to the

PJM-W forward market price to develop a proxy for the Dom Zone price.

Please provide a summary of the commodity price sources that are used and

indicate where additional information can be obtained.

This information is shown on Schedule 2. In addition, Schedule 3 provides historical

price information for certain commodity price sources relative to the prior period fuel

factor (July 1,2014 to June 30, 2015) through January 31, 2015.

Please describe any changes in market assumptions between the Company's 2014

Fuel Factor and this year's filing.

The only change is the transition discussed above from the CAIR emissions program to

CSAPR.


Yes, it does.

5

APPENDIX A


ROBERT G. THOMAS

Robert G. Thomas received a Bachelor of Science degree in Mining Engineering from the

University of Pittsburgh in 1981, and holds a Master of Materials Science degree from the

University of Virginia in 1988 and a Master of Business Administration from the University of

Richmond in 2000.

Mr. Thomas started his career with the Company in 1981 as an Engineer in the

Procurement Services Department and has held various positions in the Fuel Procurement

Department, the Capacity Acquisition Department, and the Dominion Energy Clearinghouse. He

has also held management positions in the Dominion Energy Clearinghouse and Business

Planning and Market Analysis Department.

Currently, Mr. Thomas is the Director, Energy Market Analysis & Integrated Resource

Planning within the Budgeting, Business Planning and Market Analysis Department. His

responsibilities include energy commodity price forecasting, Dominion Virginia Power load and

sales forecasting, and demand-side and integrated resource planning. He is also a certified Six

Sigma Green Belt.

Mr. Thomas has previously presented testimony before the State Corporation

Commission of Virginia.

Company Exhibit No. __Witness: RGTSchedule 1

Commodity Price Projections

January Outlook CaseCommodity Fuel and Market Price AssumptionsMarket as of 1/31/2015

$/MMBtu $/MMBtu $/MMBtu $/MMBtu $/MMBtu $/bbl $/MMBtu $/bbl $/ton $/ton $/tonZone 6 Transco Coal- Coal- Coal-

NYMEX NNY Zone 5 Dominion TCO Pool #GOil Crude CAPP CAPP NS NAPPYear Month NG Basis' Basis* SP Basis' Basis' (1%S) #2 Oil (WTI) 1.6# 1.6# 3.2#2015 April 2.69 -0.17 0.01 -0.78 -0.11 44.65 12.10 48.99 45.50 48.00 51.752015 May 2.71 -0.31 -0.02 -0.87 -0.12 44.70 12.11 50.07 45.50 48.00 51.752015 June 2.76 -0.58 -0.04 -1.01 -0.16 45.00 12.19 51.22 45.50 48.00 51.752015 July 2.81 -0.38 -0.04 -0.78 -0.19 45.40 12.33 52.37 46.05 48.00 52.002015 August 2.82 -0.49 -0.04 -0.99 -0.23 45.85 12.49 53.44 46.05 48.00 52.002015 September 2.81 -0.73 -0.04 -1.23 -0.27 46.35 12.65 54.40 46.05 48.00 52.002015 October 2.85 -0.69 -0.03 -1.15 -0.25 46.85 12.81 55.25 46.45 48.00 52.252015 Novsmber 2.96 -0.35 0.08 -1.03 -0.27 47.35 12.94 56.03 46.45 48.00 52.252015 December 3.15 0.47 0.81 -1.05 -0.28 47.85 13.07 56.79 46.45 48.00 52.252016 January 3.29 3.72 3.28 -1.09 -0.28 49.00 13.19 57.41 46.85 48.50 53.002016 February 3.29 2.72 2.20 -1.07 -0.25 49.00 13.25 58.00 46.85 48.50 53.002016 March 3.25 -0.53 0.12 -1.04 -0.29 49.00 13.27 58.56 46.85 48.50 53.002016 April 3.14 -0.53 -0.06 -0.99 -0.18 52.02 13.24 59.09 47.40 48.60 53.402016 May 3.15 -0.83 -0.08 -1.14 -0.24 52.02 13.28 59.59 47.40 48.60 53.402016 June 3.19 -0.91 -0.11 -1.24 -0.26 52.02 13.40 60.10 47.40 48.60 53.40

January Outlook CaseCommodity Fuel and Market Price AssumptionsMarket as of 1/31/2015

PJM Western Hub (PJM-W) PJM-W Basis to DOM Zone PJM DOM Zone Emmissions$/MWh $/MWh $/MWh $/MWh $/MWh $/MWh $/MWh $/MWh $/MWh $/ton $/ton

NOx(SIP Call

Year Month 5x16 5x8,2x24 7x24 5x16 5x8,2x24 7x24 5x16 5x8,2x24 7x24 S02 + Annual)

2015 April 37.95 27.15 32.43 1.06 0.65 0.85 39.01 27.80 33.28 175.00 250.002015 May 38.95 25.95 31.54 2.26 0.90 1.49 41.21 26.85 33.03 175.00 425.002015 June 41.50 25.90 33.53 0.86 0.39 0.62 42.36 26.29 34.15 175.00 425.002015 July 55.45 29.45 42.31 0.13 0.62 0.38 55.58 30.07 42.69 175.00 425.002015 August 47.40 27.90 36.71 1.09 1.37 1.24 48.49 29.27 37.95 175.00 425.002015 September 38.10 26.35 31.83 3.17 2.24 2.67 41.27 28.59 34.51 175.00 425.002015 October 36.00 26.20 30.84 1.63 1.37 1.49 37.63 27.57 32.33 175.00 250.002015 Novarnber 36.70 26.85 31.23 0.33 1.21 0.82 37.03 28.06 32.05 175.00 250.002015 December 40.15 30.20 34.91 -0.07 0.81 0.39 40.08 31.01 35.30 175.00 250.002016 January 56.15 44.55 49.54 3.71 7.32 5.76 59.86 51.87 55.30 175.34 250.482016 February 51.85 40.75 46.11 0.83 1.41 1.13 52.68 42.16 47.24 175.67 250.962016 March 41.45 32.40 36.88 4.61 3.07 3.83 46.06 35.47 40.71 176.01 251.452016 April 38.10 30.60 34.10 1.07 0.68 0.86 39.17 31.28 34.96 176.35 251.932016 May 39.35 26.95 32.55 2.27 0.90 1.52 41.62 27.85 34.07 176.69 429.112016 June 41.65 26.30 33.80 0.86 0.39 0.62 42.51 26.69 34.42 177.03 429.93

'Basis is the price differential between Henry Hub and the specific trading point noted. The purchase price for gas at Zone 6 NNY, for example. is equal toHenry Hub NG + Zone 6NNY Basis.

Company Exhibit No. __Witness: RGTSchedule 2Page 1 of3

Commodity Price Data Sources

a. Natural GasSource: New York Mercantile Exchange (NYMEX) ClearportProduct: Natural Gas .Trade Symbol: NGDelivery Point: Henry Hub, LouisianaContract Size: 10,000 MMBtu (million British thermal units)Additional Information: ~~.&!]1.Si;[Ql@.,~n

b. Natural Gas BasisSource: Intercontinental ExchangeProducts: Transco Zone 6NNY, Dominion South Point, TCO Pool BasisTrade Symbol:Delivery Point: Financial onlyContract Size:Additional Information: www.theice.com

Source: PlattsProduct: Transco Zone 5Trade Symbol: NIADelivery Point: Transco Zone 5Contract Size: NIAAdditional Information: www.platts.com/products/m2ms-gas

b. Crude Oil (WTI)Source: New York Mercantile Exchange (NYMEX) ClearportProduct: Light Sweet Crude OilTrade Symbol: CLDelivery Point: Cushing, OklahomaContract Size: 1,000 barrels (42,000 gallons)Additional Information: www.cmegroup.com

c. #2 Fuel OilSource: New York Mercantile Exchange (NYMEX) ClearportProduct: Ultra-Low Sulfur DieselTrade Symbol: LHDelivery Point: New York HarborContract Size: 1,000 barrels (42,000 gallons)Additional Information: www.cmegroup.com

1


d. #6 Fuel OilSource: A.E. Bruggemann & Co. Energy BrokersProduct: Residual Fuel Oil, 1% SulfurTrade Symbol: N/ADelivery Point: New York HarborContract Size: 1,000 barrels (42,000 gallons)Additional Information: ~"!.YY..~Qn~&rr@!~Qm

e. Coal- CSX (CSX Corp.), Central AppalachiaSource: United Power (division of ICAP United, Inc.)Product: Coal- 12,500 Btu/lb, 1.6 lb/MMBtu S02Trade Symbol: N/ADelivery Point: Central Appalachia via CSX (Big Sandy River or Kanawha River)Contract Size: 10,000 short tons (approximate size of one train)Additional Information: www.icapenergy.com/US/markets/coal.aspx

f. Coal- NS (Norfolk Southern), Central AppalachiaSource: United Power (division ofICAP United, Inc.)Product: Coal- 12,500 Btu/lb, 1.6lb/MMBtu S02Trade Symbol: N/ADelivery Point: Central Appalachia via NS (Thacker or Kenova)Contract Size: 10,000 short tons (approximate size of one train)Additional Information: www.icapenergy.com/US/markets/coal.aspx

g. Coal- MGA (Monongahela Railway), Northern AppalachiaSource: United Power (division ofICAP United, Inc.)Product: Coal- 13,000 Btu/lb, 3.8-4.2lb/MMBtu S02Trade Symbol: N/ADelivery Point: Northern Appalachia via MGAContract Size: 10,000 short tons (approximate size of one train)Additional Information: www.icapenergy.com/US/markets/coal.aspx

h. SOz AllowancesSource: Evolution Markets, Inc.Trade Symbol: N/ADelivery Point: United States (nationwide)Quoted Units: $/ton of S02 emittedAdditional Information: http://new.evomarkets.com/index.php?page=Emissions_Markets

2

Company Exhibit No.Witness: RGTSchedule 2Page 3 of3

Commodity Price Data Sources

i. NO x Allowances (SIP Call Period and Annual)Source: Evolution Markets, Inc.Trade Symbol: N/ADelivery Point: United States (SIP Call region)Quoted Units: $/ton ofNOx emittedAdditional Information: http://new.evomarkets.com/index.php?page=Emissions_Markets

j. PJM-W Power PricesSource: Intercontinental ExchangeProduct: On-peak, Off-peak PowerTrade Symbol: N/ADelivery Point: PJM Western HubContract Size: 50 MWAdditional Information: www.theice.com/homepage.jhtml

3

Company Exhibit No. _ _Witness: RGTSchedule 3Page 1 of7

Historical Commodity Prices

HenryHub

$5.00

$4.50

$4.00

$3.50

$3.00

$2.50

$2.00

$1.50

$1.00

$0.50

$0.00

,,,I , I I

-----------+------ -------l------------t-- ----------'-------

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2014 -- ICE Indices - Avg Cas h

50.00

45.00

40.00

35.00

~ 30.00-IlJ:E 25.00~~ 20.00

15.00

10.00

5.00

Transco Zone 6NNY Delivered

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--- -- - -- - - -L------- - -~- - --- - -- - -- -~- - -- -- --- --L---L-- i : 01 i - - - - - - - - - - --L---- - - - -~-- - - - ----- -~--- - - - --- --'-J ,

0.00"l' "l' "l' "l' "l' "l' It) It) It) It) It) It).... .... 0 .... .... .... .... .... .... .... 0 ...0 0 0 0 0 0 0 0 0 0~ ~ ~ s ~ ~ ~ !:! ~ !:! !:! !:!.... .... .... .... .... :!: .... :!: .... .... :!:;:: co (j; 0 - N N ~ in.... .... M co.... ....

201 4 -- Platts GO - Avg Cas h

1

$45.00

$40.00

$35.00

$30.00

~

$25.00iii::i:~ $20.00~

$15.00

$10.00

$5.00

$0.00

$4.50

$4.00

$3.50

$3.00

~

$2.50-m::i:

~ $2.00

$1.50

$1.00

$0.50

Company Exhibit No. __Witness: RGTSchedule 3Page 2 of 7

Transco Zone 5 Delivered

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2014 --Platts GD - Avg Cas h

Dominion SP Delivered

,,,I I I r I I I I I I I------------r-----------"1------------t-------------t-------------t------------t-------------t-----------T-----------"1------------t-------------,.-----------I : : : : I : :: I! i ! l ' I ! i !

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2014 --Platts GD - Avg Cas h

2

$5.00

$4.50

$4.00

$3.50

~ $3.00m

$2.50;:i;

~ $2.00

$1.50

$1.00

$0.50

Company Exhibit No. _ _Witness: RGTSchedule 3Page 3 of 7

Teo Pool Delivered

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2014 --Platts GO - Avg Cash

No.6 Oil (1 %5)

$18.00

$16.00

$14.00

~ $12.00m;:i;;:i;

$10.00V.

$8.00

$6.00

$4.00

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2014 --AE Brugg Prompt - Avg Cas h

3



No.2 Oil

$25.00

$20.00 ........

$15.00 'l~ r-em -"!-~ r

~ $10.00

$5.00

$0.00~ ~ ~ ~ ~ ~ III III III III III III.... .... 0 .... .... .... .... .... 0 0 0 ....0 0 0 0 0 0 0 0~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~.... .... a; ~ :!:: .... :!:: ~

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20 14 -- NYMEX Heating Oil Prompt - Avg Cash

Crude Oil (WTI)

$110.00

$100.00

$90.00

$80.00

:c $70.00.aiit $60.00

$50.00

$40.00

$30.00

,A I "' ! I I I I I I I I

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$20.00~ ~ ~ ~ ~ ~ III III III III III III

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201 4 - - NYMEX WTI Prompt - Av g Cas h

4



CAPP Coal (12500 Btu/lb, 1.6 Ib/MMBtu S02)

$65.00

$60.00 --$55.00 -,

.....

$50.00\.J ~c

~ LJ,",.!11... $45.00

$40.00

$35.00

$30.00~ ~ ~ ~ ~ ~ II) II) II) II) II) II)

0 0 ... 0 0 0 0 ... ... ... ... ...0 0 0 0 0 0

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2014 --United Brokersheet Prompt - Avg Cas h

NAPP Coal (13,000 Btu/lb, 3.8/4.2Ib/MMBtu S02)

$65.00

$60.00 -----------

$55.00

c $50.00

~.!11

$45.00...$40.00

$35.00

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201 4 --United Brokersheet Prompt - Avg Cash

5



502 Allowances

I I I I I I I I I I

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50.00

250.00

200.00

300.00 -r----r----,----.,..---.,.--......---,..---...---,..---...---.......----r---...,

100.00

c~ 150.00~

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201 4 -- Evoluti on Brokers heet Prompt - Avg Cash

NOx SIP Call Allowances

$350

$300

$250

c $200

~.!!!

$150~

$100

$50

$0

! : : ! ! : ! ! ! ! :I I I I I I I I I I I

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7

1 Q.

2 A.

3

4

5

6

7

8 Q.

9 A.

10

11

12

13

14

15

16

17 Q.

18 A.

DIRECT TESTIMONYOF

GLENN A. KELLYON BEHALF OF




My name is Glenn A. Kelly, and my business address is 5000 Dominion Boulevard, Glen

Allen, Virginia 23060. I am the Director of Generation System Planning for Virginia

Electric and Power Company ("Dominion Virginia Power" or the "Company"). I am

responsible for forecasting total system fuel and purchased power expenses, and for

conducting the Company's long-term generation supply planning. A statement of my



I will review the methodology and models that the Company used to project total system

energy requirements and fuel expenses from July 1,2015 through June 30, 2016 (the

"current period"). In doing so, I will also describe the load forecast, unit operating

parameters, and electric market interface assumptions used to develop these projections.

Finally, I will discuss the Company's actual energy requirements and fuel expenses for

the 12-month historical period of February 1, 2014 through January 31, 2015, as required

by Rule 80 ofthe Commission's Rules Governing Utility Rate Applications and Annual

Informational Filings, 20 VAC 5-201-80.


Yes. Company Exhibit No. _, GAK, consisting of Schedules 1 through 15, was

1

2

3 Q.

4

5 A.

6

7

8

9

10

11

12

13

14

15

16

17

18 Q.

19 A.

20

21 Q.

22 A.

prepared under my supervision and direction, and is accurate and complete to the best of

my knowledge and belief.

Please describe the Company's process for projecting total system energy

requirements and fuel expenses for the current period.

Projected system energy and fuel expenses are developed through a four-phase planning

process that simulates the expected economic dispatch of the Company's system. First,

the Company develops a load forecast (retail and wholesale) for its entire service

territory. Second, the Nuclear and Power Generation business units provide projections

of the generating unit operational parameters, including unit capacities, heat rates,

planned outages, and forced outage rates. The Power Contracts Department also provides

the contract parameters for non-utility generators ("NUGs") under contract with the

Company. Third, the Budgeting, Business Planning & Market Analysis Department

provides the commodity and power price forecasts, while the Fuels Department provides

the fuel contracts and associated transportation arrangements. Finally, the data is

compiled into models that provide a simulation of the Company's system dispatch. The

result of this simulation is a projection of the system fuel expense, which the Rates

Department then uses to develop the Company's Virginia jurisdictional fuel factor rate.

What models were used to develop the energy and fuel expense projections?

The Company utilizes the FuelPlan and PROMOD models to calculate expected fuel

expense.

What is the FuelPlan model?

The FuelPlan model is a PC-based model that consists of two different modules - the

2

1

2

3

4

5

6

7 Q.

8 A.

9

10

11

12

13

14

15

16

17 Q.

18 A.

19

20

21

22

23

dispatch module and the expense module. The dispatch module develops the unit

dispatch rates (in ¢/MBtu) that are used by PRO MOD to simulate the economic dispatch

of the Company's generating units. The expense module develops the unit expense rates

that are used in PROMOD to calculate the cost of the units' projected generation based

on the weighted average value of the fuel inventory at each unit (which changes over

time due to the monthly fuel deliveries and consumption at the Company's stations).

How are unit dispatch rates developed?

The dispatch module of FuelPlan utilizes the forward commodity price forecast, which is

described by Company Witness Robert G. Thomas, along with a transportation adder for

each unit to develop a unit dispatch rate. This dispatch rate reflects the marginal or

replacement delivered fuel cost of the incremental generation from a particular unit. The

unit dispatch rates (in ¢/MBtu) are passed to the PROMOD model as inputs for the

Company's system to simulate the economic dispatch to meet the Company's projected

load requirements. The PROMOD model is run using the unit dispatch rates, and the

resulting unit Btu requirements are then passed back from PRO MOD to FuelPlan to

develop the unit expense rates.

How are unit expense rates developed?

The expense module of FuelPlan develops a projection of the monthly average inventory

cost for each generating unit. The model downloads the beginning inventory cost for

each unit from the Company's accounting system, and calculates a forecasted monthly

average inventory cost based on beginning inventory cost and the cost of the projected

fuel deliveries. For example, for the Company's coal units, the model incorporates both

contract and spot market purchases based on the projected Btu requirements, which

3

2 Q.

3 A.

4

5

6

7

8

9

10

11

12

13

14 Q.

15 A.

16

17

18

19

20

21

22

results in an average of spot and contract delivered prices weighted by tons.

What is the PROMOD model?

PROMOD is a production costing model leased from Ventyx LLC that the Company has

used for many years to forecast its system operations and fuel costs. The model utilizes

the dispatch rates developed in FuelPlan along with the forward power price curve to

simulate the dispatch of the Company's system to meet projected load requirements. The

model logic dispatches resources in least-cost order (from either the Company's

generating units or purchases through PJM Interconnection, L.L.C. ("PJM")) to meet the

Company's total demand requirements. If during any given hour the load requirement is

met, and the Company's marginal generating unit dispatch cost is below the market price

of energy, PROMOD will simulate an interchange sales transaction. The PROMOD

dispatch logic takes into account the operational parameters of the generating units and

the Company's NUG contracts when determining the least cost solution.

How are the respective units' dispatch costs determined in PROMOD?

Unit dispatch cost is based on the marginal or replacement energy cost specific to the

unit. The energy cost components include the marginal fuel expense (the unit dispatch

rate from the FuelPlan model), the marginal allowance expense for both sulfur dioxide

("S02") and nitrogen oxide ("NOx") emissions, and the variable operations and

maintenance ("O&M") expense. The marginal allowance expense is based on a unit's

S02 and NOx emission rates (lbs/MBtu) and the market value or replacement cost of

allowances ($/ton). The variable O&M expense component includes both consumables

(water, limestone, ammonia, etc.) and the variable portion of maintenance expense.

4

2

3

4

5

6

7 Q.

8 A.

9

10

11

12 Q.

13

14 A.

15

The $/MWh dispatch cost of the unit is developed by multiplying the delivered fuel cost

(in $/MBtu) times the unit heat rate (in MBtulMWh), and then adding the $/MWh costs

of emissions adders and variable O&M. These unit dispatch costs are calculated by the

model to determine the total variable cost of dispatching the unit ($/MWh) at various

levels of output, including the impact of start-up costs and environmental regulations.

I. CURRENT PERIOD DISCUSSION

What kWh sales forecast is used to develop the projected load requirements?

Schedule 1 shows the Company's total energy requirement at the generator output level,

and the sales forecast for both total system and Virginia jurisdictional customers for the

current period. The effects of energy efficiency and demand-side management programs

are included in the system sales forecast.

How have forward commodity prices changed since the Company's fuel factor filing

last year in Case No. PUE-2014-00033 (the '"2014 Fuel Factor")?

As the table below demonstrates, natural gas, coal, oil and power prices have decreased

since last year's fuel filing.

FORWARD PRICES

16

COMMODITY

Coal (CAPP-FOB) ($/ton)

Oil (Crude-WTI) ($/bbl)

Gas (Henry Hub) ($/mmbtu)

Gas (Zone 5) ($/mmbtu)

Gas (Z6NNY) ($/mmbtu)

Power (7 x 24 PJM West Hub) ($/MWh)

Nuclear (expense basis) ($/MWh)

3/31/2014

JULY 14-JUNE 15

62.13

95.04

4.40

5.05

4.92

43.43

6.80

5

1/30/2015

JULY 15-JUNE 16

46.69

56.75

3.06

3.78

3.54

36.73

6.87

-25%

-40%

-30%

-25%

-28%

-15%

1%

1 Q.

2

3 A.

4

5

6

7

8

9 Q.

10

11 A.

12

13

14 Q.

15 A.

16

17

18

19 Q.

20 A.

21

22

What is the Company's projection of system fuel and purchased power expenses for

the current period?

The Company's projected system fuel expense for the current period is $2,026 million.

Schedule 2 shows supply volumes (MWh), supply costs ($000), and average cost

($/MWh), by supply type, for the current period. The total monthly system energy and

fuel expense on my Schedule 2 is included in Company Exhibit No. _, EJA, Schedule

1, sponsored by Company Witness Edward J. Anderson, to determine the Company's

Virginia jurisdictional fuel expense.

The Company's projected system fuel expense is lower than in its 2014 Fuel Factor.

What are the drivers for this decrease?

As I will discuss later in my testimony, the primary drivers to the decrease in the system

fuel expense are the decreases in the commodity prices for natural gas, coal, oil and

power.

What unit operating assumptions and results are included in this filing?

Confidential Schedule 3 provides the projected equivalent availability rates, confidential

planned outage dates, and capacity factors by generating unit (for non-peaking units) for

the current period. Confidential Schedule 4 shows the assumed monthly unit equivalent

forced outage rates.

How does PROMOD account for the Company's participation in PJM?

PROMOD dispatches the Company's generating units against an hourly market price that

is reflective of the PJM Dominion Zone ("Dom Zone") price. Company Witness Thomas

discusses this forecast in greater detail. In the model, the Company's system is

6

1

2

3

4

5

6

7

8 Q.

9 A.

10

11

12

13

14

15

16 Q.

17

18 A.

19

20

interconnected with the PJM energy market. For economy energy purchases, if the

market price of energy is lower than our cost to generate, then imports will occur until the

marginal cost of the last unit dispatched equals the market price of energy (with the

imports not allowed to exceed the transmission tie limit). For off-system sales, if the

market price of energy is higher than our cost to generate, then exports will occur until

the marginal cost of the last unit dispatched equals the market price of energy (with the

exports not allowed to exceed the transmission tie limit).

Are there any off-system sales included in this filing for the current period?

The Company is projecting that it will sell 479,390 MWh, with an associated sales

margin of $9.0 million, for the current period. Therefore, $6.8 million for energy sales

margins is reflected as a reduction to the system fuel expense pursuant to the statutory

75%-25% sharing mechanism of such margins under Va. Code § 56-249.6 D 1. Schedule

5 shows the expected off-system sales margins by month. The total reduction to the

system fuel expense is $27.7 million. These values are also included in the system total

fuel expense shown on Schedule 2.

Does the Company's system fuel expense include the impacts of financial

transmission rights ("FTRs")?

Yes. Schedule 2, page 2 of 3 shows a reduction of $6.7 million, which reflects a 100%

credit of excess FTRs as previously agreed by the Company in prior Virginia fuel factor

cases.

7

1 Q.

2 A.

3

4 Q.

5

6 A.

7

8

9 Q.

10

11 A.

12

13

14

15

16

17

18

19

20

21 Q.

22 A.

Are interim nuclear spent fuel storage costs reflected in total system fuel expense?

Yes. System nuclear fuel expense includes interim spent fuel storage costs of$13.2

million.

Are natural gas storage and pipeline firm transportation expenses reflected in total

system fuel expense?

Yes. System gas fuel expense includes natural gas storage and pipeline transportation

expenses and contract costs. For the current period, these projected fixed gas expenses

are $85.1 million.

What is the status of the Company's recovery from the U.S. Department of Energy

("DOE") for spent nuclear fuel storage mentioned in the 2014 Fuel Factor?

In the 2014 Fuel Factor, the Company included approximately $21 million on a Virginia

jurisdictional basis of expected settlement payments as a reduction to projected system

fuel expense. Through January 2015, the Company has received approximately $16

million of the $21 million noted above, and expects to receive the remaining $5 million

during the 2015 2016 fuel year. For the upcoming current period, the Company is

including projected settlement payments totaling approximately $11 million on a Virginia

jurisdictional basis by June 2016, as Company Witness John C. Ingram discusses. These

additional fuel-related payments from the DOE during the current period are for

additional claims related to storage of spent nuclear fuel at the Company's North Anna

and Surry Power Stations.

Do you have any other schedules relating to the current period?

Yes. Confidential Schedule 6 shows the forecasted fuel consumption (in MBtu), by

8

1

2

3

4

5 Q.

6

7 A.

8

9

10

11

12

13

14 Q.

15

16 A.

17

18 Q.

19 A.

20

21

month and by unit. Confidential Schedule 7 shows the forecasted heat rates for the

thermal generating units, also by month and by unit. Finally, Schedule 8 shows the

projected fuel cost information for February to June 2015 - i.e., the remainder of the prior

period (July 1,2014 to June 30, 2015) - for which there are not yet actual results.

Is there any new capacity that will become available during the remainder of the

prior period or during the current period?

Yes. The 1,329 MW Warren County combined-cycle unit was brought online in

December 2014 as scheduled. The 1,358 MW Brunswick County gas-fired combined

cycle station is expected to be operational in May 2016. This plant will employ state-of

the-art technology and will further strengthen the fuel diversity of the Company's

generation fleet. In addition, the Possum Point Unit 6 gas-fired combined-cycle will be

uprated by 27 MW in May 2015.

U. HISTORICAL PERIOD DISCUSSION

What were the Company's monthly energy requirements and sales volumes for the

most recent 12-month historical period?

System energy requirements and sales volumes for that period are shown on Schedule 9,

which provides data for the period February 2014 January 2015.

Please explain the Company's fuel expense for the historical period.

Schedule 10 shows a system level monthly summary of the actual supply volumes

(MWh), supply costs ($000), and average cost ($/MWh), by supply type, for the period

February 2014 - January 2015.

9

1 Q.

2 A.

3

4

5

6 Q.

7

8 A.

9

10

11

12

Please explain the Company's fuel recovery position for the prior period.

As shown by Company Witness Anderson, the year-end fuel recovery through June 30,

2015 is expected to be an under-recovery of approximately $21.9 million. This value

includes a write-off of $85.4 million which is one-half of the deferral balance as of

December 31,2014.

What are the main factors that contributed to the fuel expense recovery position

during the prior period?

After March 2014, the weather was milder and commodity prices were lower than

expected. This resulted in an over-recovery of$84 million through January, 2015 which

includes the impact of the $85 million fuel deferral write-off as described by Company

Witness Ingram. The actual change in these commodity prices are shown in the table

below.

13

COMMODITY

Coal (CAPP-FOB) ($/ton)

Oil (Crude-WTI) ($/bbl)

Gas (Zone 5) ($/mmbtu)

Gas (Z6NNY) ($/mmbtu)

Gas (Henry Hub) ($/mmbtu)

Power (7 x 24 PJM West Hub) ($/MWh)

3/31/2014 forecast

JULY 14 - JAN 15

61.50

97.11

5.14

5.03

4.50

45.27

Actual

JULY 14 - JAN 15

53.50

79.72

4.07

3.12

3.72

36.36

-13%

-18%

-21%

-38%

-17%

-20%

14

15

16

17

However, during February 2015, the weather became abnormally cold, driving both gas

and power prices higher as demand increased in the Mid-Atlantic region. Thus, when

taking into account current weather and the accelerated implementation of the proposed

reduced fuel rate, the June 30, 2015 deferral balance is forecasted to be an under-recovery

10

2

3 Q.

4 A.

5

6

7

8

9

10 Q.

11 A.

of$21.9 million. This includes an estimated $83.5 million fuel impact for the cold

weather in February 2015.

Do you have any other schedules relating to the historical period?

Yes. Confidential Schedule 11 shows unit availability information, planned outage dates,

and capacity factors of the thermal generating units over the historical period. Confidential

Schedule 12 shows the actual fuel (in MBtu) consumed by month and by unit, and

Confidential Schedule 13 shows monthly unit equivalent forced outage rates. Confidential

Schedule 14 shows monthly unit heat rates, while Confidential Schedule 15 contains

information about abnormal operating events that occurred during the historical period.


Yes, it does.

11

APPENDIX A


GLENN A. KELLY

Glenn A. Kelly joined Dominion Virginia Power in 1986 as an engineer after graduating

from Virginia Tech with a Bachelor of Science degree in Mechanical Engineering. He received

a Master of Business Administration degree from Averett University in 1998.

After working eleven years as a performance and project engineer at the Chesapeake

Energy Center and the Yorktown Power Station, Mr. Kelly transferred to the Company's Power

Generation Technical Services Department in Richmond as a Generation Performance Specialist.

Following a series of positions supporting Power Generation operations, he earned his Six Sigma

Master Black Belt and became Manager of Planning and Analysis in 2004. His responsibilities

included Energy Supply PJM support, fuel expense and variance reporting, generation

forecasting, and project financial analysis.

In September 2007, Mr. Kelly was promoted to Director - Generation System Planning

for Dominion Virginia Power, where he is currently responsible for developing generation

portfolio plans to serve customers' future energy and capacity requirements. His group also

monitors fuel expenses and provides forecasted operational data to various groups within the

Company.

Mr. Kelly has previously submitted testimony before the State Corporation Commission

of Virginia and the North Carolina Utilities Commission.

VIRGINIA ELECTRIC AND POWER COMPANYJULY 2015 - JUNE 2016

LOAD AND SALES FORECAST (MWH)

Company Exhibit No,_Witness: GAKSchedule 1Page 1 of 1

Jul-15Aug-15Sep-15Oct-15Nov-15Dec-15Jan-16Feb-16Mar-16Apr-16May-16Jun-16

Total

SystemEnergy

Requirement

8,802,7808,594,9277,277,0696,579,2746,584,4448,255,0028,732,5397,550,0257,287,8076,524,4797,197,7728,109,093

91,495,212

TotalSystemSales

8,267,9308,047,5236,762,8856,060,3436,016,1657,762,2808,261,6107,148,3686,793,6586,105,5696,598,9537,614,203

85,439,487

VirginiaJurisdictional

Sales

6,633,7626,436,7515,292,4594,697,3254,719,6386,271,4746,716,6055,784,1815,393,2064,787,8145,179,0676,060,468

67,972,749

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Confidential Information Redacted

VIRGINIA ELECTRIC AND POWER COMPANYJULY 2015 - JUNE 2016

Fossil & Hydro and Nuclear Unit Performance Forecast

Company Exhibit No._Witness: GAKSchedule 3Page 1 of 1

EquivalentAvailability Capacity

Unit Rate Factor(%) (%)

North Anna 1 98.0 99.8North Anna 2 90.8 92.2

Surry 1 98.0 100.2Surry 2 84.6 86.2

Altavista-Biomass 87.7 87.7

Bear Garden 90.2 78.8

Bellemeade 87.0 36.2

Bremo 3 - Gas 82.7 1.5

Bremo 4 - Gas 88.5 3004

Brunswick 87.7 81.7

Chesterfeld 3 90.8 17.8





Chesterfeld 8 81.5 8504

Clover 1 93.8 84.3

Clover 2 93.8 86.3

Gordonsville 1 90.7 56.1


Hopewell-Biomass 87.7 87.7

Mecklenburg 1 9504 25.8

Mecklenburg 2 9504 23.6

MtStorm 1 83.3 59.6

Mt Storm 2 87.2 65.9

Mt Storm 3 67.2 41.9

Pittsylvania/Multi 93.3 19.8

Possum Point 3 90.5 3.7


Possum Point 5 7804 2.7


Rosemary 88.8 6.7

Southampton-Biomass 87.7 87.7

VCHEC 76.7 49.7

Warren 89.2 77.0

Yorktown 1 80.7 204

Yorktown 2 83.7 4.1

Yorktown 3 65.3 2.7

Planned Outage Period ;,O,-,u!-"ta"lg",e,-D~e",sc"lr.!!ip<!.tl!-,,·o~n _

Refueling

Refueling

RefuelingRefueling

BoHer maintenanceBoilermaintenance, turbine valve maintenance

Borescope inspection, balanceof plantmaintenance, turbine valvemaintenanceBorescope inspection, balanceof plantmaintenance

Borescope inspection, balanceof plantmaintenance

Generatorinspection, balanceof plantmaintenanceBalanceofplantmaintenance

Catalystreplacement

BoHer maintenance, catalyst replacement

Boilermaintenance, balanceof plantmaintenance,catalystreplacement

Hotgas pathinspectionHotgas path inspection, turbine valve maintenance

BoHer maintenanceBoiler maintenance

Turbinevalve maintenance, catalyst replacement

Hot gas path inspection

BoilermaintenanceBoilermaintenance

Boilermaintenance, turbine valve maintenance

Boilermaintenance, catalystreplacement

BoHer maintenance, turbine valve maintenance

Boilermaintenance

Boilermaintenance, turbine valve maintenance

Borescope inspectionBorescope inspection, catalystreplacement

Borescope inspection



Borescope inspection

Borescope inspection, balanceof plantmaintenance,turbinevalve maintenance(seriesof derates)

Boiler maintenanceBoilermaintenanceBoilermaintenance, turbine valve maintenance

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Company Exhibit No,_Witness: GAK

VIRGINIA ELECTRIC AND POWER COMPANY Schedule 9FEB 2014 - JAN 2015 Page 1 of 1

LOAD AND SALES (MWH)

ACTUALS

System Total VirginiaEnergy System Jurisdictional

Requirement Sales SalesFeb-14 7,191,157 6,906,552 5,572,556Mar-14 7,338,494 7,107,876 5,664,511Apr-14 5,767,342 5,640,566 4,387,043May-14 6,343,762 6,234,799 4,857,503Jun-14 7,302,618 7,074,620 5,625,752Jul-14 7,800,658 7,655,579 6,112,948Aug-14 7,337,155 7,239,650 5,751,231Sep-14 6,578,998 6,506,842 5,099,123Oct-14 5,851,413 5,904,444 4,620,184Nov-14 6,452,389 6,449,725 5,167,762Dec-14 7,292,343 7,118,281 5,764,327Jan-15 8,126,235 7,815,019 6,351,820

Total 83,382,563 81,653,952 64,974,761

FORECASTED


Requirement Sales SalesFeb-14 7,202,360 7,055,159 5,706,830Mar-14 7,227,282 6,959,859 5,608,759Apr-14 6,537,085 6,097,431 4,826,369May-14 6,971,141 6,623,088 5,253,980Jun-14 8,085,379 7,626,296 6,136,744Jul-14 8,513,885 8,175,268 6,500,827Aug-14 8,285,203 7,940,791 6,293,166Sep-14 7,027,000 6,717,159 5,208,752Oct-14 6,484,937 6,149,802 4,748,672Nov-14 6,516,652 6,213,734 4,857,730Dec-14 8,080,343 7,728,934 6,164,861Jan-15 8,579,302 8,193,087 6,594,163

Total 89,510,569 85,480,607 67,900,853

VARIANCE


Requirement Sales SalesFeb-14 (11,203) (148,607) (134,274)Mar-14 111,212 148,017 55,752Apr-14 (769,742) (456,865) (439,326)May-14 (627,379) (388,290) (396,476)Jun-14 (782,761) (551,676) (510,992)Jul-14 (713,227) (519,689) (387,879)Aug-14 (948,048) (701,141) (541,935)Sep-14 (448,002) (210,317) (109,629)Oct-14 (633,524) (245,358) (128,488)Nov-14 (64,262) 235,991 310,032Dec-14 (788,001) (610,653) (400,534)Jan-15 (453,067) (378,068) (242,343)

Total (6,128,006) (3,826,655) (2,926,092)


VIRGINIA ELECTRIC ANO POWER COMPANYFEB 2014 - JAN 2015

SYSTEM ENERGY (MWH)

Combined Combustion Hydro & PowerNuclear Coal Biomass Heavy Oil Steam Gas ~ Turbine Bath Co. Solar NUG Purchases Sales FTRs Total

Feb-14 2,297,732 2,683,504 69,276 870,892 30,678 63,447 1,052,757 196,717 (73,846) 7,191,157Mar-14 2,514,971 1,913,849 101,601 16,766 782,933 87,340 57,921 898,608 1,038,813 (74,309) 7,338,494

Apr-14 2,263,789 1,075,089 57,460 31,510 533,352 16,991 116,652 483,578 1,206,618 (17,695) 5,767,342May-14 2,109,033 1,644,799 48,162 27,829 950,551 132,351 83,195 604,021 823,977 (80,156) 6,343,762Jun-14 2,440,051 2,393,763 111,161 53,519 984,832 183,228 (17,573) 721,018 540,740 (108,121) 7,302,618Jul-14 2,509,619 2,359,258 105,756 71,302 72,356 1,003,221 267,412 (33,375) 41 669,404 865,056 (89,392) 7,800,658Aug-14 2,517,150 2,501,811 125,938 42,427 51,698 987,192 231,858 (44,553) 83 611,015 499,191 (186,654) 7,337,155

Sep-14 1,957,945 1,765,630 94,469 35,283 890,609 122,272 (7,204) 69 610,977 1,157,439 (48,490) 6,578,998

Oct-14 2,272,012 1,701,514 106,188 56,005 550,815 23,986 4,417 71 498,478 689,893 (51,966) 5,851,413Nov-14 2,504,469 2,184,020 101,203 27,744 1,296,647 13,037 (25,855) 47 587,584 (201,586) (34,921) 6,452,389Oec-14 2,398,356 2,317,608 112,368 206 33,571 1,635,684 32,154 53,865 37 726,517 63,814 (81,838) 7,292,343Jan-15 2,542,760 2,480,552 116,628 45,756 63,509 1,759,442 35,511 55,491 39 868,362 202,047 (43,863) 8,126,235

Total 28,327,887 25,021,398 1,150,209 159,691 469,790 12,246,171 1,176,818 306,428 386 8,332,319 7,082,719 (891,251) 83,382,563

SYSTEM FUEL EXPENSE ($000)

Combined Combustion Hydro & PowerNuclear Coal Biomass Heavy Oil SteamGas ~ Turbine Bath Co. Solar NUG Purchases Sales FTRs Total

Feb-14 16,998 90,770 4,337 16 (887) 56,099 4,550 47,868 4,338 (4,990) (59) 219,039Mar-14 18,705 66,215 5,868 13 856 40,132 9,417 38,306 96,444 (3,805) (6,044) 266,107Apr-14 16,639 34,988 3,893 418 20,991 930 27,170 46,992 (550) (957) 150,512May-14 14,967 49,930 2,832 762 35,717 3,704 29,292 46,313 (8,075) (24) 175,417Jun-14 17,104 80,266 5,747 2,327 37,534 8,177 28,821 24,002 (3,906) 8,270 208,343Jul-14 16,856 75,485 5,262 11,420 3,489 36,027 13,655 25,978 33,247 (2,689) (11) 218,720Aug-14 16,951 78,728 5,805 5,206 2,488 31,582 8,563 24,059 14,750 (6,079) (905) 181,148Sep-14 12,895 57,558 4,344 1,658 27,785 3,782 24,092 44,417 (1,419) (2,787) 172,325Oct-14 16,899 53,995 4,979 (752) 2,563 12,534 2,249 19,795 32,516 (1,441) (1,255) 142,083Nov-14 17,259 69,540 4,761 1,646 29,217 1,934 25,968 9,478 (1,278) (543) 157,982Oec-14 15,497 74,592 5,700 262 2,422 45,999 2,547 27,287 14,454 (2,986) 16 185,790Jan-15 16,809 77,663 6,281 9,088 3,301 79,159 3,880 34,490 15,876 (1,589) (32) 244,926

Total 197,579 809,729 59,807 25,252 21,043 452,775 63,388 353,127 382,828 (38,806) (4,331) 2,322,393

AVERAGE COST ($ PER MWH)

Combined Combustion Hydro & PowerNuclear Coal Biomass Heavy Oil Steam Gas ~ Turbine Bath Co. Solar NUG Purchases Sales FTRs Total

Feb-14 7.40 33.83 62.60 N/A N/A 64.42 148.33 45.47 22.05 67.57 30.46Mar-14 7.44 34.60 57.75 N/A 51.03 51.26 107.82 42.63 92.84 51.21 36.26Apr-14 7.35 32.54 67.75 N/A 13.28 39.36 54.72 56.18 38.95 31.09 26.10May-14 7.10 30.36 58.79 N/A 27.38 37.57 27.99 48.49 56.21 100.74 27.65Jun-14 7.01 33.53 51.70 N/A 43.48 38.11 44.63 39.97 44.39 36.13 28.53Jul-14 6.72 32.00 49.76 160.16 48.22 35.91 51.06 38.81 38.43 30.08 28.04Aug-14 6.73 31.47 46.09 122.70 48.13 31.99 36.93 39.38 29.55 32.57 24.69Sep-14 6.59 32.60 45.98 N/A 46.99 31.20 30.93 39.43 38.38 29.25 26.19Oct-14 7.44 31.73 46.88 N/A 45.77 22.76 93.78 39.71 47.13 27.72 24.28Nov-14 6.89 31.84 47.05 N/A 59.33 22.53 148.33 44.19 -47.02 36.60 24.48Oec-14 6.46 32.19 50.73 N/A 72.14 28.12 79.20 37.56 226.51 36.49 25.48Jan-15 6.61 31.31 53.85 198.63 51.98 44.99 109.26 39.72 78.57 36.24 30.14

Total 6.97 32.36 52.00 158.13 44.79 36.97 53.86 42.38 54.05 43.54 27.85

NOTES:Hydro& BathCo. MWh are net of pumpingenergy'CombinedCycle'Expenseincludes gas pipelinefixedexpenses'Combustion Turbine'actualexpensesincludegas pipeline fixedexpenses'PowerSales' Expenseincludes 75% marginsfor applicable Off-system salesData includes the impactof Warren testing (fuelexpensewenttocapitalproject)

Confidential Information Redacted

VIRGINIA ELECTRIC AND POWER COMPANYFEB 2014 - JAN 2015

Fossil & Hydro and Nuclear Unit Performance

EquivalentAvailability Capacity

Unit Rate Factor(%) (%)

NorthAnna 1 97.2 99.6North Anna 2 90.3 91.9Surry 1 100.0 103.1Surry 2 89.0 91.8

Altavista-Biomass 57.0 52.5

Bear Garden 80.5 63.0

Bellemeade 70.4 9.6

Bremo 3 - CoalBremo4 - Coal

Bremo 3- Gas 72.8 32.9Bremo4 - Gas 61.3 16.3

Chesapeake 1 90.6 18.7Chesapeake 2 83.6 17.6Chesapeake 3 81.3 34.5Chesapeake 4 89.3 25.7

Chesterfield 3 80.9 11.5






Clover 1 92.7 80.3Clover2 80.1 67.6



Hopewell 70.6 59.1Hopewell-Biomass

Mecklenburg 1 94.6 38.1Mecklenburg 2 91.3 33.9

MtStorm 1 91.4 77.2

MtStorm 2 74.2 61.1

MtStorm 3 83.2 71.6

PiUsylvania 91.7 44.9

PossumPoint3 75.3 0.7




Rosemary 76.3 2.5

Southampton 71.4 56.4

VCHEC 74.1 66.0

Yorktown 1 67.2 27.5

Yorktown 2 72.6 30.8

Yorktown 3 28.4 1.1

Company Exhibit No._

Witness: GAKSchedule 11Page 1 of 1

Refueling Outage

Refueling Outage

BollermaintenanceBoilermaintenance, turbine overhaul

HotgaspathinspectionBorescope inspection

Borescope inspectionGeneratorrewind, borescopeInspection,HRSG maintenance, turbinevalve maintenance

Gas ConversionGas Conversion

BoilermaintenanceTurbinevalve maintenance

Boilermaintenance

BoilermaintenanceBoilermaintenanceBoilermaintenance

Hotgas path inspection, borescopeinspection,steamturbine valve maintenance, balanceof plantmaintenance

BoilermaintenanceTurbinevalve maintenanceBoilermaintenance

Hot gas pathinspectionGeneratorrewind

Electric transmission workHot gas pathinspection

Turbinevalve maintenanceBalanceof plantmaintenance, warranty workBoilermaintenance

Generatorinspection

Boilermaintenance

Boilermaintenance

Boilermaintenance


BoilermaintenanceBoilermaintenance, ductwork replacementBoilermaintenanceTurbinevalve maintenanceBalanceof plantmaintenanceDuctwork replacementBorescope inspectionBorescope inspection

Turbinevalve maintenanceHRSG maintenance

Turbinevalve maintenanceBoilermaintenance


BoilermaintenanceBoilermaintenanceBalanceof plantmaintenanceBalanceof plantmaintenanceGeneratorinspectionBoilermaintenance, controls upgrade

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North Anna Unit 1

Chesterfield 3

Chesterfield 7

Chesterfield 8

VIRGINIA ELECTRIC AND POWER COMPANYFEB 2014 -JAN 2015

Fossil & Hydro and Nuclear Unit Performance

ABNORMAL OPERATING EVENTSConfidential Information Redacted

Start Date End Date Duration (Days)


Description

Manual Shutdown to repair RC leakage in containment sump level.

Offline due to a grounding issue in generator rotor

Offline due to a failure in the combustion zone centering around combustion lid #7. Thegas line as well as the lid's as flange failed.

Offline due to failure of atomizing air flexible metal hose, causing damage to thecombustion lids.

~o;;0

"s:»z

1 Q.

2 A.

3

4

5

6

7

8

9 Q.

10 A.

11

12

13

14

15

16

17

18

DIRECT TESTIMONYOF

GREGORY A. WORKMANON BEHALF OF




My name is Gregory A. Workman, and my business address is 120 Tredegar Street,

Richmond, Virginia 23219. I am the Director-Fuels and have the responsibility of fuel

procurement for Virginia Electric and Power Company ("Dominion Virginia Power" or

the "Company"). The Dominion Fuels group handles the procurement, scheduling,

transportation, and inventory management for coal, natural gas, oil, and biomass

consumed at the Company's power stations. A statement of my background and

qualifications is attached as Appendix A.


I will discuss the Company's fossil fuel procurement practices, as well as any recent

changes to those practices for delivery of fuels to the Company's fossil generation fleet.

Such procurement practices impact the forward calculation of the Company's system fuel

expenses, which Company Witness Glenn A. Kelly has incorporated in his fuel expense

projections for both the prior (July 1,2014 to June 30, 2015) and current (July 1,2015 to

June 30, 2016) fuel factor periods.

My testimony is divided into five sections. The first section will discuss the overall fuel

markets, and Section II will cover coal procurement and coal contracts. Section III will

address natural gas procurement and transportation, while Section IV will discuss the

2

34

5

6

Q.

Company's oil procurement methods. Finally, Section V will discuss the procurement of

biomass (i.e., wood chips) as fuel for consumption at the Company's power stations.

SECTION IFUEL MARKETS

Please discuss the trends that affected commodity markets during the period of July

2014 through January 2015.

7 A.

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

Coal prices continue to decline, despite power plant coal inventories being less than the

historical five-year average. Historically, lower inventories would tend to push coal

prices higher. However, coal markets have been fundamentally changed due to the

unprecedented productivity witnessed in the shale gas production regions. The abundant

availability of competitively priced shale gas provides economic incentive for utilities to

switch fuels from coal to natural gas. This phenomenon results in lower coal demand for

power generation. In addition, a weak export market for both thermal and metallurgical

coal has increased coal supplies for domestic power generation. The combination of

coal-to-gas fuel switching and weak export markets have driven coal supplies higher,

thereby reducing prices.

Natural gas prices have declined significantly. This is attributed to a continued increase

in gas production, particularly from the Marcellus shale region. Lower natural gas prices

will favor gas-fired power generation, putting downward pressure on coal prices.

The significant decline in No.2 and No.6 oil prices is the direct result of falling crude oil

prices in global markets. Increased production from domestic shale oil production as

well as OPEC's recent decisions not to reduce production have led to a worldwide

2

2

3456 Q.

7 A.

8

9

10

11

12

13

14

15

16 Q.

17 A.

18

19

20

21

22

oversupply of oil and petroleum products. As a result, West Texas Intermediate crude

prices have dropped to well below $50/bbl, a pricing level not seen since 2009.

SECTIONHCOAL PROCUREMENT

Please discuss the Company's coal procurement practices.

The Company employs a multi-year coal physical hedge procurement plan to ensure a

reliable supply of coal at competitive prices. This is accomplished by procuring the

Company's long-term coal requirements primarily under periodic solicitations and

secondarily on the open market for its short-term or spot needs. In addition to the

contracts executed as a result of normal solicitations, the Company continually evaluates

prevailing market conditions and may enter into other transactions if conditions are

favorable. The effect of procuring both long- and short-term provides a layering in of

contracts with staggered terms and blended prices. This ensures a reliable supply of fuel

with limited exposure to dramatic market price swings.

How is coal delivered to the Company's generating facilities?

The Company utilizes a combination of train and truck transportation to supply fuel to its

coal fired generating stations. The Clover Power Station, Mecklenburg Power Station,

Mt. Storm Power Station, Chesterfield Power Station, and Yorktown Power Station

receive coal via rail delivery. Mt. Storm also receives a portion of its coal deliveries via

truck, while truck coal comprises 100% of coal deliveries to the Virginia City Hybrid

Energy Center ("VCHEC").

3

12

3 Q.

4 A.

5

6

7

8

9

10

11

12

13

14

15

16

17 Q.

18 A.

19

20

21

22

23

SECTION IIIGAS PROCUREMENT

Please discuss the Company's gas procurement practices.

With the addition of Warren County Power Station and Bremo Power Station to the gas-

fired generation fleet in 2014, the Company transitioned from a predominantly day-ahead

procurement approach to a program that includes day-ahead, monthly, and seasonal

purchases. Similar to our coal procurement practices, the Company utilizes periodic

solicitations and the open market to procure physical gas to meet station requirements.

The Company also entertains and evaluates opportunities as market conditions change.

The Company evaluates its diverse portfolio of pipeline and storage contracts to

determine the most reliable and economical delivered fuel options available for each

power station. This portfolio of gas transportation contracts provides access to multiple

natural gas supply points from the Gulf region to the Marcellus shale region. In addition,

the Company actively participates in the interstate pipeline capacity release and physical

supply markets as well as longer-term, pipeline expansion projects that will augment the

transportation portfolio and enhance reliability at a reasonable cost.

Does the Company currently have a price hedging program?

Yes, the Company has historically followed its Marginal Fuel Hedging Program for

natural gas and purchased power. Under this program, the Company has hedged natural

gas using 25% of the forecasted volumes during the summer and winter months in the

low load case. In addition, the Company has hedged on-peak power using the forecasted

volumes for all 12 months in the low load case. As discussed by Company Witness

Steven A. Rogers, the Company intends to increase natural gas price hedging levels to

4

1

2

3

45

6 Q.

7 A.

8

9

10

11

12

1314

15 Q.

16 A.

17

18

19

20

21

22 Q.

23 A.

20% to 50% of forecasted volumes in the first year of a three-year period. Purchased

power volumes are expected to gradually decrease, but the Company will continue to

financially hedge a portion of these volumes when beneficial for customers.

SECTION IVOIL PROCUREMENT

Please discuss the Company's oil procurement practices.

The Company purchases its No.2 fuel oil and No.6 oil requirements on the spot market,

and optimizes its inventory, storage, and transportation to ensure reliable supply to its

power generating facilities. Trucks, vessels, barges, and pipelines are employed to

transport oil to the Company's stations and third-party storage locations. The Company

utilizes its own storage and third-party storage to ensure a reliable supply of oil, and to

mitigate the price risk associated with these potentially volatile products.

SECTION VBIOMASS PROCUREMENT

Please discuss the Company's biomass procurement practices.

The Company currently procures the majority of its wood chips and other woody material

for four biomass-fired plants (the Altavista and Pittsylvania Power Stations in the Central

Region, and the Hopewell and Southampton Power Stations in the Eastern Region) via

long-term contracts with two suppliers. Procurement for the Company's VCHEC facility

in the Western Region is conducted via short-term contracts with various suppliers. All

five biomass consuming plants receive wood deliveries via truck.


Yes, it does.

5

APPENDIX A


GREGORYA.WORKMAN

Gregory A. Workman graduated from Fairmont State College in 1987 with a Bachelor of

Science degree in Business Administration and received a Master of Business Administration

degree from West Virginia University in 1988. He became an employee of Dominion in 2001

and has held various positions within the following departments: Business Development and

Acquisitions, Fossil and Hydro Merchant Operations, and Technical Services. In October 2007,

Mr. Workman assumed his current role as Director-Fuels. He currently serves on the National

Coal Council, a federal advisory committee to the U.S. Secretary of Energy.

Prior to joining Dominion, Mr. Workman worked for Norfolk Southern Corporation from

1990-2001. He served in various capacities at Norfolk Southern Corporation including:

Finance, Operations, Coal Marketing, and Strategic Planning. Prior to Norfolk Southern, he

worked as a Financial Consultant for American Express.

Mr. Workman has previously presented testimony before the State Corporation

Commission of Virginia, the North Carolina Utilities Commission, and the Federal Energy

Regulatory Commission.

1 Q.

2 A.

3

4

5

6

7

8

9 Q.

10 A.

11

12

13

14

15 Q.

16 A.

17

18

DIRECT TESTIMONYOF

TOM A. BROOKMIREON BEHALF OF




My name is Tom A. Brookmire and I am the Supervisor of Nuclear Fuel Procurement.

My business address is 5000 Dominion Boulevard, Glen Allen, Virginia 23060. I am

responsible for activities pertaining to nuclear fuel procurement, nuclear fuel-related

project management, long-term nuclear spent fuel disposal, and nuclear fuel price

forecasting and budgeting used by Virginia Electric and Power Company ("Dominion

Virginia Power" or the "Company"). A statement of my background and qualifications is

attached as Appendix A.


The purpose of my testimony is to review the Company's actual and projected nuclear

fuel costs for the prior period fuel factor of July 1,2014 through June 30, 2015, and to

provide projections for the current period of July 1,2015 through June 30, 2016. Section

I of my testimony will discuss the components of the Company's nuclear fuel costs, and

Section II will discuss the Company's nuclear fuel expense rates.

What is your responsibility in the development of the Company's fuel factor?

I am responsible for projecting the Company's nuclear fuel prices, which become the

basis for its projected nuclear fuel expense rates. These rates, along with projected costs

for interim spent fuel storage, are transmitted to the Generation System Planning group

1

2 Q.

3 A.

4

5

67

8 Q.

9 A.

10

11

12

13

14

15 Q.

16 A.

17

18

19

20

21

22

23

for use in calculating the Company's fuel factor and system fuel expenses.


Yes. Company Exhibit No. __, TAB, consisting of Schedules 1 through 3, was



SECTION ICHANGES IN NUCLEAR FUEL COST

What are the major components of nuclear fuel expense?

Nuclear fuel expenses include the amortized value of the cost for uranium, along with

required conversion, enrichment, and fabrication services (collectively called "front-end

components"). In addition, there are expenses for interim spent fuel dry storage.

Historically, there has also been the federal government's one mill/kWh charge for the

disposal of spent nuclear fuel. I will discuss the current status of this one mill/kWh

charge in Section II of my testimony.

What are the current market conditions for the front-end components?

The nuclear fuel market has softened considerably in the past five years. This is largely

due to the devastating Japanese earthquake and tsunami of March 2011. But there have

been other factors influencing this trend as well, such as clear reductions in demand (e.g.,

Germany's decision to permanently shut down eight reactors and the closing of several

U.S. reactors). There have also been some reductions in supply (e.g., postponement and

deferral of new mines and mine capacity expansions along with delays in planned

increases in uranium enrichment capacity) which have, in part, offset some of the

downward trend in demand. China continues to aggressively build new reactors, with

2

2

approximately 30 plants currently under construction and six to eleven that may come on

line in 2015.

3

4

5

6

7

8

9

10

11

The price for conversion services has also dropped significantly on the spot market due to

reduced near-term demand, while long-term prices have remained high due to concern

over the lack of investment in new conversion production facilities, and the possibility for

shortfalls in capacity longer-term. The cost for enrichment services appears to have

stabilized after a steady decline due to reduced demand and the addition of new centrifuge

capacity in Europe and the U.S. Domestic trends in fabrication prices continue to be

difficult to measure because there is no active spot market, but the general consensus is

that costs will continue to increase due to regulatory requirements, reduced competition,

and new reactor demand both in the U.S. and abroad.

12

13

14

Several reactors in Japan are likely to restart in 2015, which is likely to have some short

term price lift on front-end components. The timing and extent of other reactor restarts in

Japan remains uncertain.

Have these changes in market costs impacted the Company's projected near-term

costs?

Yes, but not significantly. The Company's current mix of longer-term front-end

component contracts has reduced its exposure to the market price escalation and volatility

that has occurred over the past several years. In addition, because the Company's nuclear

plants replace about one-third of their fuel on an 18-month schedule, there is a delay

before the full effect of any significant changes in a component price is seen in the plant

operating costs. However, in addition to some higher-priced legacy contracts, the

Q.15

16

17 A.

18

19

20

21

22

3

1

2

34

5 Q.

6 A.

7

8

9

10

11

12

13

14 Q.

15

16

17 A.

18

19

20

21

22

23

Company has been active in the market and has some market-based contracts allowing it

to take advantage of current lower prices.

SECTION IINUCLEAR FUEL

Please describe how you develop the Company's nuclear fuel expense rates.

The calculation of nuclear fuel expense rates, expressed in mills per kilowatt-hour

("mills/kWh"), is based on expected plant operating cycles and the overall cost of nuclear

fuel. As previously noted, front-end component costs include those for uranium, along

with those for the conversion, enrichment, and fabrication services. These costs are

amortized over the estimated energy production life of the nuclear fuel as provided by the

Company's Generation System Planning group. Rear-end costs include, in prior periods,

the federal government's charge of one mill/kWh on net nuclear generation sold, which is

intended to cover the eventual disposal cost of spent nuclear fuel in a federal repository.

You stated earlier in your testimony that you would discuss the status of the one

mill/kWh fee charged by the federal government for spent nuclear fuel disposal.

Please provide an update regarding the status of this fee.

On November 19,2013, the U.S. Court of Appeals for the District of Columbia Circuit

issued a decision on the legal challenge brought by the Nuclear Energy Institute and the

National Association of Regulatory Utility Commissioners ("NARUC") to the one

mill/kWh waste fee that operating nuclear plants pay quarterly into the Nuclear Waste

Fund. The court ordered the U.S. Department of Energy ("DOE") to submit to Congress

a proposal (as is required under the Nuclear Waste Policy Act) that the fee be changed to

zero, unless and until there is a viable disposal program. The DOE petitioned the court to

4

1

2

3

4

5

6

7

8 Q.

9 A.

10

11

12

13

14

15

16

17 Q.

18 A.

19

20

21

rehear this decision, but the court denied this request.

Notwithstanding, the DOE submitted a proposal to Congress in January 2014 to change

this one mill/kWh fee to zero. This relief is industry-wide and applies to all operating

reactors, including the Company's operating reactors at Surry and North Anna. The

processes specified in the Nuclear Waste Policy Act for adjustment of the fee have now

been completed, and as of May 16, 2014, the Company is no longer required to pay the

waste fee.

Can the waste fee collected by the federal government be reinstated?

Yes, it can. The Nuclear Waste Policy Act allows the Secretary of Energy to review fee

adequacy on an annual basis. It is likely that at some point in the future when a viable

waste disposal program is established by DOE, the Secretary will develop an adjustment

to the waste fee that ensures full cost recovery for the life cycle of such a program. Any

proposed adjustment to the fee will again need to be submitted to Congress for review for

a period of 90 consecutive session days. If and when a fee adjustment becomes effective,

the Company will again become obligated to make the fee payment, and will again seek

to recover payments for the assessed fee in its fuel factor.

What other items are included in the Company's nuclear fuel cost?

One other item included is the cost associated with interim spent fuel dry storage. For the

current period, the cost of interim spent fuel storage is included in the Company's

Forecasted System Fuel Expense. See Company Exhibit No. _, OAK, Schedule 2, page

20f3.

5

2

3

4

5

Q.

A.

How does your previous forecast of the Company's nuclear fuel expense rates

compare to the actual rates?

Schedule 1 shows this comparison using actual figures for the period July 1, 2014 through

January 31, 2015, and estimated figures for the period February 1,2015 through June 30,

2015. Actual nuclear fuel expense rates were 1.07% lower than forecasted.

6 Q.

7 A.

8

9

10 Q.

11 A.

What are the projections for the Company's nuclear fuel expense rates?

The Company's monthly nuclear fuel expense rate projections for the combined front-end

components and rear-end costs are shown on my Schedule 2. These projected rates are

2.1% higher than the actual prior period rates shown in Schedule 3.


Yes, it does.

6

APPENDIX A


TOM A. BROOKMIRE

Tom A. Brookmire is a graduate of Virginia Tech with a Bachelor of Science degree in

Nuclear Science (1983), and a Master's degree in Engineering in Nuclear Engineering from the

University of Virginia (1988). He is a registered professional engineer in the Commonwealth of

Virginia.

Mr. Brookmire joined with Virginia Electric and Power Company in 1983, and has

worked since then in staff and management positions involving nuclear fuel. His current

responsibilities include procurement of nuclear fuel and related services, nuclear fuel-related

project management, long-term disposal of spent nuclear fuel, and the projection of nuclear

prices and related capital costs and expense rates.

Mr. Brookmire has previously presented testimony before the State Corporation

Commission of Virginia.

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8

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13 Q.

14 A.

15

16

DIRECT TESTIMONYOF

ALAN L. MEEKINSON BEHALF OF




My name is Alan L. Meekins and I am Director of Electric Market Operations for

Virginia Electric and Power Company ("Dominion Virginia Power" or the "Company").

My business address is 5000 Dominion Boulevard, Glen Allen, Virginia 23060. A

statement of my background and qualifications is attached as Appendix A.

What are your responsibilities as Director of Electric Market Operations?

I am responsible for the Company's electric wholesale operations, including energy

procurement and generation unit commitment and dispatch. In performing these duties,

my staff and I have day-to-day responsibilities for interaction with PJM Interconnection,

L.L.C. ("PJM"), the regional transmission organization or entity ("RTO") of which the

Company is a member, regarding day-ahead ("DA") and real-time ("RT") energy market

operations activities.


I will discuss the Company's economy energy purchases from PJM, which are a

component of our overall system-wide fuel expenses, and I will explain how these

purchases contribute to reducing the Company's fuel costs.

1 Q.

2

3 A.

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19 Q.

20

21 A.

22

23

Please describe the coordination of the Company's operations in the PJM wholesale

markets.

Among the responsibilities of my group is the managing of the Company's interactions

with PJM related to generation unit operations, day-ahead bidding, and real-time

dispatch, as well as load serving entity ("LSE") requirements such as load procurement.

The Market Operations group supplies generating unit availability and cost data to PJM

each morning before noon for the next operating day. Simultaneously, we submit our

hourly load procurement profile based on forecasted need for the same period. PJM's

economic dispatch model determines the least cost means of satisfying demand, operating

reserves and other ancillary services, and the reliability requirements of the RTO. The

result of this model includes the day-ahead energy awards for our generating units and

the hourly prices.

During the operating day, the Market Operations staff further interfaces with PJM's

operations staff indirectly through PJM' s energy management information system, as

well as directly through voice communications. The Market Operations group also

communicates dispatch instructions to the plants through the Company's energy

management system and by verbal instructions. For calendar year 2014, the Company

continued to be a net buyer of economy energy from the PJM market.

Please describe the nature of these net economy energy purchases and how they

arise.

As presented by Company Witness Glenn A. Kelly, for the 12-month historical period of

February 1,2014 through January 31, 2015, the Company purchased approximately 7.1

million MWh of net economy energy from PJM at an overall cost of approximately $383

2

2

3

4

5 Q.

6

7 A.

8

9

10

11

12

13

14

15 Q.

16 A.

million. These net economy energy purchases from PJM result from the Company's

participation in PJM's DA and RT energy markets. The Company's Market Operations

staff works to optimize the commitment of the Company's fleet of generating units with

the PJM market to minimize the Company's cost to serve its load requirements.

Does the Company measure the benefit of the economy energy purchases that it

makes from PJM?

Yes, the Company uses the PJM energy markets to minimize costs, but also studies and

measures outcomes in the PJM markets to ensure that it continues to achieve

economically efficient outcomes for customers. One of the measures that we perform is

an evaluation of the economic benefit of our DA economy purchases. For calendar year

2014, the Company net purchased 5.2 million MWh ofDA energy from PJM at a savings

of approximately $109 million. These savings represent the difference in cost between

buying DA economy energy needs from PJM and generating an equivalent amount of

energy completely from our own fleet of generating resources.


Yes, it does.

3

APPENDIX A


ALAN L. MEEKINS

Alan L. Meekins graduated from Virginia Polytechnic Institute and State University in

1979 with a Bachelor of Science degree in Electrical Engineering (concentration in Power

Systems), and he received a Master's of Business Administration degree from Virginia

Commonwealth University in 1990. Mr. Meekins joined Virginia Electric and Power Company

in July 1979 and has held several positions in Engineering, Operations, and Management. He

assumed his current position as Director - Electric Market Operations on September 1, 2004. In

this capacity, he is responsible for ensuring that the operating characteristics and costs, and daily

forecasted demand obligations, of the Company's regulated generating fleet are appropriately

placed in the PJM Day-Ahead market. Additionally, the Market Operations group, in which he

is a leader, interfaces with PJM's operations staff to effectively manage and dispatch the

Company's generating assets in the PJM Real-Time market.

Mr. Meekins has previously presented testimony before the State Corporation

Commission of Virginia and the North Carolina Utilities Commission.

1 Q.

2 A.

3

4

5

6

7

8

9 Q.

10 A.

11

12

13

14

15

16

17

18

DIRECT TESTIMONYOF

JOHN C. INGRAMON BEHALF OF




My name is John C. Ingram, and my business address is 120 Tredegar Street, Richmond,

Virginia 23219. I am a Director of Accounting for Dominion Generation, which includes

responsibility for Virginia Electric and Power Company ("Dominion Virginia Power" or

the "Company"). My responsibilities include overseeing personnel responsible for

recording the Company's actual fuel and purchased power expenses, as well as any

under-lover-recovery of such expenses through the fuel deferral mechanism. A statement

of my background and qualifications is attached as Appendix A.


I will present the Virginia jurisdictional fuel expenses incurred by the Company during

the period July 1,2014 through January 31, 2015, as well as the status of the Company's

fuel deferral balances as of January 31, 2015. In addition, I will (1) discuss the status of

the deferred fuel balances associated with the 24-month extended recovery period

("mitigation proposal") approved in Case No. PUE-2014-00033 (the "2014 Fuel Factor");

(2) sponsor a proposed modification to the text of the Definitional Framework for Fuel

Expenses ("Definitional Framework") to explicitly re-affirm that derivative gains and

losses, including option premiums, associated with financial hedging activities are

includable in recoverable fuel expenses; and (3) provide updates on the Company's

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8 Q.

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recovery of costs associated with spent nuclear fuel storage from the U.S. Department of

Energy ("DOE").


Yes. Company Exhibit No. _, JCI, consisting of Schedules 1 through 4, was prepared

under my supervision and direction, and is accurate and complete to the best of my

knowledge and belief. Schedule 4 presents the proposed modification to the Definitional

Framework.

What were the Company's actual Virginia jurisdictional fuel expenses incurred

during the seven-month period ending January 31, 2015?

Schedule 1, Column 2 shows $1,010,725,087 of cumulative booked fuel expenses on a

Virginia jurisdictional basis from July 1,2014 through January 31, 2015.

Is 75% of the Company's total annual margins from off-system sales being credited

against fuel factor expenses as required by Va. Code § 56-249.6 D I?

Yes, it is. The Company's profit margin from off-system sales for the period July 1,

2014 through January 31, 2015 was $1,546,842. Based upon this statutory 75% sharing

mechanism, the Virginia jurisdictional allocated share of the margin applied against fuel

factor expenses was $914,686, and is incorporated in Schedule 1, Column 1. Schedule 3

presents more detail regarding the calculation and breakdown of these off-system sales

amounts, as well as shared margins for February 1,2014 through June 30, 2014.

2

1 Q.

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3 A.

4

5 Q.

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7 A.

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16 Q.

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18 A.

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What is the Company's deferred fuel balance as of January 31, 2015 for the 2014

2015 fuel year?

Schedule 1, Column 6 shows the actual Virginia jurisdictional fuel expense over-recovery

balance totaling $84,331,878 as of January 31, 2015.

What was the prior period deferred fuel balance as of the end of the 2013-2014 fuel

year and how much of that balance has now been collected?

The prior period deferred fuel balance as of June 30, 2014 was an under-recovery of

$234,533,019 as shown in Schedule 2, Column 1. During the seven-month period

beginning July 1,2014, $76,937,214 was collected as shown in Schedule 2, Column 2,

and a prior period adjustment of$537,716 was booked as shown in Schedule 2, Column

3, resulting in an under-recovery balance of$158,133,521 as of January 31,2015. Later

in my testimony I will discuss the status of deferred balances associated with the

mitigation proposal and the impact thereon of Senate Bill 1349, which was recently

enacted by the General Assembly of Virginia during its 2015 Regular Session and signed

into law by Governor McAuliffe on February 24,2015 ("Senate Bill 1349,,).1

What was the Company's deferred fuel balance for the period April 1, 2014 through

June 30, 2014?

The table below shows the calculation of the Company's deferred fuel balance (an under

recovery) for the period April 1,2014 through June 30, 2014.

1 2015 Virginia Acts of Assembly, Ch. 6, Enactment Clause 2 (approved February 24, 2015; effective July 1,2015).

3

Virginia Electric and Power ComVirginia 2013-2014 Fuel Year Recovery Experience

Three Months Ended June 2014

AllocatedFuel Current Balance in

Jurisdiction Revenue Month DeferralDeferral Account

March-14 Ending Balance 41

April-14 115,626,744 111,737,978 3,888,766 234,345,907

May-14 134,966,770 123,720,625 11,246,145 245,592,052

June-14 163,869,241 143,287,899 20,581,342 266,173,394

1

2

3

Q. What is the status of the deferred fuel balance associated with the Company's

mitigation proposal approved in the 2014 Fuel Factor, and how is it impacted by the

directives of Senate Bill 1349?

4 A.

5

6

7

8

9

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11

12

13

14

Under the mitigation proposal, the Company proposed to recover its projected June 30,

2014 deferred fuel balance of$267.8 million over two years - 50% during the 2014-2015

fuel year and 50% during the 2015-2016 fuel year. The Commission approved this

proposal.

Senate Bill 1349 requires the Company to forgo recovery of 50% of the prior period June

30,2014 deferral balance that has not already been recovered as of December 31, 2014.

As presented in Schedule 2, Column 4, that unrecovered balance was $170,773,642,

resulting in a write-off of $85,386,821. As a result, the Company's projected June 30,

2015 deferred fuel over-recovery balance and accompanying rate calculations, described

by Company Witnesses Glenn A. Kelly and Edward J. Anderson, will exclude any

recovery of this written-off amount.

4

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Also, as I described in my testimony in the Company's 2014 Fuel Factor, amounts

relating to the mitigation proposal do not include any financing costs and no financing

costs are included for recovery in this fuel factor proceeding. Furthermore, base rates

will not increase as a result of the mitigation proposal, as any incremental financing costs

related to the mitigation proposal will be excluded from base rate cost of service in future

earnings review proceedings and borne by the Company.

Now turning to the Company's recently filed Fuel Procurement Strategy Report,

please summarize how an environment of increasing gas consumption and related

gas costs, as described therein, is expected to affect the Company's financial hedging

efforts and how such costs are treated in fuel expense.

On January 30, 2015, the Company filed its first annual Fuel Procurement Strategy

Report ("Report") pursuant to the Commission's Order in the 2014 Fuel Factor. Among

other things, this Report provides a summary of the Company's historical financial

hedging results and a discussion of its current and anticipated fuel procurement and price

hedging plans (the "Fuel Procurement Strategy"). The Fuel Procurement Strategy was

designed with an emphasis on satisfying the rapid rise in natural gas requirements

associated with the new fleet of combined cycle units and accompanying impacts on

other commodities and purchased power. As described in the Report, the Company

intends to meet its increasing fuel requirements using a combination of longer-term

natural gas supply contracts and spot purchases. For those purchase transactions that

continue to involve price risk, such as spot purchases of natural gas and purchased power,

the Company plans to continue using derivative instruments to financially hedge a certain

portion of those volumes.

5

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3

4

5

6

7

8

9 Q.

10

11 A.

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13

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15

16 Q.

17

18 A.

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20

21

22

23

While the Company has financially hedged a portion of its natural gas requirements and

purchased power transactions for several years now, the sheer volume of natural gas

purchases is projected to increase substantially as the new combined-cycle units come on

line. As a result, the aggregate level of dollar exposure to derivative gains and losses is

expected to increase as a direct result of financially hedging a higher notional value of

physical purchases. Furthermore, the Company also intends to continue its practice of

mitigating the price volatility for a portion of projected purchased power costs as well,

though to a lesser degree when compared to prior years.

Are you sponsoring a proposed modification to the Definitional Framework in this

case to address the Company's planned financial hedging activities?

Yes, I am sponsoring a modification to the text of the Definitional Framework to

explicitly reaffirm that derivative gains and losses, including option premiums, incurred

to financially hedge purchased commodities pursuant to the Company's Fuel

Procurement Strategy for the benefit of customers shall be included in costs recoverable

under the fuel factor, as shown on my Schedule 4.

Why does the Definitional Framework need to explicitly provide for the use of

derivative instruments for financial hedging purposes?

For most types of fuel costs, the text of the Definitional Framework does not explicitly

reference particular types of costs to be recovered through the fuel factor. Rather,

includable costs are inferred by reference to specific FERC inventory and fuel expense

accounts. As a result, includable costs are largely defined by the FERC accounting

instructions that describe what charges are allowable in those specific accounts.

Additionally, there are instances where includable costs are not explicitly written into the

6

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22

Definitional Framework nor addressed in the FERC accounts, but have been approved in

prior fuel orders, such as the inclusion in fuel expense of interim nuclear fuel storage

costs and all settlements related to PJM financial transmission rights.

As for derivative gains or losses resulting from financial hedging transactions, the

Definitional Framework does not explicitly list them as includable costs. However,

pursuant to FERC accounting instructions, such derivative gains or losses should be

recorded to those specific FERC accounts referenced in the Definitional Framework to

the extent that the derivatives receive special "hedge accounting treatment" - as a hedge

of the physical fuel purchases recorded in those accounts.

Cash flow hedge accounting is a particular accounting treatment for derivative activity

that matches the derivative's gain or loss with the cost of the physical transaction that it is

intended to hedge based on certain accounting criteria. Generally, for derivatives not

receiving this accounting treatment ("economic hedges"), FERC accounting instructions

require that activity to be recorded in accounts that are not referenced in the Definitional

Framework. That being said, these economic hedges may be presented in the FERC fuel

related accounts if they are evaluated together with the physical transactions by the

Company's regulators for fuel accounting and ratemaking purposes.

While most all of the Company's historical derivative gains and losses have received

cash flow hedge accounting treatment, it is possible that derivatives employed in future

financial hedging transactions may not qualify for cash flow hedge accounting. I discuss

reasons how this is so further in my testimony, As noted by Company Witness Steven A.

Rogers, these financial hedges are entered into for the purpose of providing customer

7

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4

5

6 Q.

7

8 A.

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13

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22

23

benefit in the form ofrate stability, and that objective is met even if the accounting

requirements for cash flow hedge accounting have not been met or maintained.

Therefore, now is the time to explicitly reaffirm in the text of the Definitional Framework

that derivative gains or losses, including option premiums, related to these financial

hedge transactions are considered to be costs recoverable in the fuel factor.

What is cash flow hedge accounting and why is it not the proper determinant of

whether a financial hedge should be included in the fuel factor?

Simply put, designating a derivative or combination of derivatives as a cash flow hedge

for accounting purposes means that the derivatives have been specifically identified, in

writing, as being highly capable of offsetting the price risk of forecasted future

transactions - in this case, the purchase of fuel commodities such as natural gas and

purchased power. Achieving cash flow hedge accounting allows the deferral of

derivative gains and losses to be matched in expense with the future market-based

commodity purchase when it is recorded in expense for financial reporting purposes. The

net result is the hedged price being reflected in expense. Hedge accounting rules include

strict criteria which require that the forecasted commodity purchases remain probable of

occurring during the entire term the derivatives are outstanding, and that the derivatives'

fair values move in a very highly correlated fashion relative to the market price changes

of the forecasted commodity purchases. Compliance with these criteria is evaluated at

the inception of the derivative transaction and during its tenure through settlement. A

cash flow hedge would be "de-designated" from hedge accounting if, at some point, it

fails to meet the strict price correlation requirements, or if the derivative volumes exceed

forecasted or actual purchased volumes (i.e., an over-hedged position).

8

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2

3

4

5

6

7

8

9

10

11 Q.

12

13

14

15 A.

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17

18

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23

As Company Witness Rogers describes, all of the Company's financial hedging activities

with respect to fuel and power purchases represent prudent economic measures

undertaken with the objective of promoting rate stability for the benefit of customers.

Therefore, even in cases where cash flow hedge accounting may not be met or

maintained, such derivative transactions are still executed in the interest of customers and

should be specifically included in fuel expense and referenced in the text of the

Definitional Framework. As noted in the Report and discussed by Company Witness

Rogers, approval of this Definitional Framework modification is an important factor for

the Company in establishing the scope and nature of any financial hedging that it will

undertake in the future.

Beyond derivative gains and losses, including option premiums, are there any other

types of costs associated with financial hedging activities that the Company intends

to seek recovery for in this fuel proceeding, with an accompanying Definitional

Framework modification?

No, the Company is not including references to any other types of costs in its proposed

Definitional Framework modification, nor is the Company seeking fuel recovery of any

such costs in this filing. As I describe further below, there are transaction costs currently

recovered in base rates that, by their nature, should be eligible for fuel recovery.

Transaction costs are those incremental expenses incurred directly as a result of executing

the underlying derivative instruments. To date, these expenses have primarily included

broker, exchange and financing fees. The inclusion of transaction costs in the fuel factor

would be consistent with similar transaction costs that are incurred for the procurement of

the underlying physical commodities and already included in recoverable fuel expense

9

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2

3

4

5

6

7

8 Q.

9

10 A.

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12

13 '

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19

20 Q.

21

22 A.

under the current Definitional Framework.

However, as base rates will not change for the next several years under Senate Bill 1349,

the Company will not seek to recover any of these transaction costs through fuel for years

in which base rates remain frozen. Following the end of the Transitional Rate Period

described in Senate Bill 1349, it is possible that the Company may seek to re-address this

issue. Option premiums, on the other hand, have historically been and should continue to

be recovered in fuel rates.

What types of costs associated with financial hedging activities would not be

included in recoverable fuel expense, by their nature?

The Company may incur directly, or through an affiliate, other types of costs that are

indirect or fixed in nature, such as internal or affiliated labor, general and administrative,

depreciation, and interest expenses. Although these costs are related to the fuel

procurement and financial hedging processes, along with the required infrastructure

established to carryon such activities, they do not arise as a direct result of the execution

of transactions and therefore are more appropriately recovered in base rates. This is

consistent with similar expenses that are incurred for the procurement of the underlying

physical commodities, but excluded from recoverable fuel expense under the current

Definitional Framework. The Company is currently recovering all infrastructure costs

arising from fuel procurement and financial hedging activities in base rates.

Please provide an update on the status of the Company's recovery of costs

associated with spent nuclear fuel storage from the DOE.

In November 2012, the Company and the DOE entered into a settlement agreement for

10

2

3

4

5

6

7

8

9

10

11

12

13 Q.

14 A.

resolution of the Company's claim for costs incurred during the period July 1, 2006

through December 31, 2010, and periodic payments for claims after that date through

2013. In January 2014, the settlement agreement was extended to provide for periodic

payments for damages incurred through December 31, 2016. A settlement payment of

approximately $27 million for costs incurred for the period January 1,2011 through

December 31, 2012 was received in July 2014. The portion of this payment allocable to

Virginia jurisdictional customers' fuel expense was approximately $16 million and was

credited to fuel expense at that time. As described by Mr. Kelly, during the 2015-2016

fuel year, the Company has included in its forecast the projected receipt of approximately

$11 million from the DOE, on a Virginia jurisdictional basis, related to further claims

regarding spent nuclear fuel storage for the periods January 1, 2013 through December

31,2013 and January 1,2014 through December 31, 2014.


Yes, it does.

11

APPENDIX A


JOHN C. INGRAM, CPA

John C. Ingram graduated from the College of William and Mary in 1992 with a Bachelor

of Business Administration degree (concentration in Accounting) and received his Certified

Public Accountant license in 1994. He performed audit services for a national public accounting

firm for seven years prior to joining Dominion in 1999. Mr. Ingram has held various positions

within Dominion's accounting organization, including SEC reporting, accounting research, and

business unit support. He was promoted to Manager within the Dominion Generation accounting

organization in 2006, and to Director in 2010. His current responsibilities include overseeing

personnel responsible for the Company's generation accounting activities, including fuel

accounting and the Company's deferred fuel mechanism.

Mr. Ingram has previously presented testimony before the State Corporation Commission

of Virginia and the North Carolina Utilities Commission.

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Company Exhibit No. _Witness: lCISchedule 4Page 1 of 1

VIRGINIA STATE CORPORATION COMMISSION 'SDEFINITIONAL FRAMEWORK OF FUEL EXPENSESFOR VIRGINIA ELECTRIC AND POWER COMPANY

a. The cost of fossil fuels shall be those items initially charged to account 151 and cleared toaccounts 501, 518 and 547 on the basis of fuel used. In those instances where a fuelstock account (151) is not maintained, e.g., gas for combustion turbines , the amount shallbe based on the cost of fuel consumed and entered in account 547.

b. The cost of nuclear fuel shall be the amount contained in account 518, excluding leasefinance charges, except that if account 518 also contains any expense for fossil fuelwhich has already been included in the cost of fossil fuel, it shall be deducted from thisaccount.

c. Total energy costs associated with purchased power and charged to account 555 shall berecoverable as fuel costs.

d. The commodity costs referenced in items a., b., and c. above shall include gains orlosses, including option premiums, arising from the use of derivative instruments associatedwith such commodities.

~tl . Energy revenues associated with off-system sales and recorded in account 447 shall becredited against fuel factor expenses in an amount equal to the total incremental fuelfactor costs incurred in the production and delivery of such sales. In addition , seventyfive percent (75%) of the total accumulated energy margins from off-system sales shall becredited against fuel factor expenses annually. In the event such accumulated energymargins result in a net loss, no charges shall be made to fuel factor expenses. Energymargin is defined as the total energy revenue received from an off-system salestransaction less the total incremental costs incurred in supplying that sale.

fe. The Company shall be permitted to credit energy revenues associated with DisplacedRetail Access Sales against fuel factor expenses in an amount equal to the average fuelfactor. No energy margin associated with the sale of the Displaced Retail AccessSales should be credited against fuel factor expenses.

gf. All refunds of fuel costs resulting from overcharges, late delivery, or any other reasonand all recoveries and adjustments of whatever nature affecting the price of fuel shall bepassed on through these proceedings.

hg. Company shall be permitted to adjust for system losses through development of a fuelfactor based upon fuel costs divided by sales through the application of a separatelyderived loss factor applied to a fuel factor based on net energy requirements.

»zom:;0enoz

1 Q.

2 A.

3

4

5

6 Q.

7 A.

8

9

10

11

12

13

14

15

16

17

DIRECT TESTIMONYOF

EDWARD J. ANDERSONON BEHALF OF




My name is Edward J. Anderson. My business address is 701 East Cary Street,

Richmond, Virginia 23219. My title is Regulatory Advisor for Virginia Electric and

Power Company ("Dominion Virginia Power" or the "Company"). A statement of my



My testimony presents the calculation of the proposed total fuel factor to be effective

April 1, 2015, on an interim basis, to comply with the directives of Senate Bill 1349,

which was recently enacted by the General Assembly of Virginia during its 2015 Regular

Session and signed into law by Governor McAuliffe on February 24, 2015 ("Senate Bill

1349").1 The Company is requesting a total fuel factor of $0.02406/kWh to become

effective for usage on and after April 1,2015 through June 30, 2016, on an interim basis.

The impact of Senate Bill 1349 and the request to implement the fuel factor reduction on

an accelerated basis is addressed more fully in the Application and the testimony of

Company Witness Steven A. Rogers. Implementation of the proposed total fuel factor

will result in a fuel revenue decrease over the period April 1, 2015-June 30, 2016 of

approximately $512.3 million.

12015 Virginia Acts of Assembly, Ch. 6, Enactment Clause 2 (approved February 24, 2015; effective July 1,2015).

1 Q.

2 A.

3

4

5 Q.

6

7

8 A.

9

10

11

12

13

14

15

16

17

18

19

20 Q.

21

22 A.


Yes. Company Exhibit No. __, EJA, consisting of Schedules 1 through 9, was



Please explain the various components that make up the Company's proposed total

fuel factor rate to be effective April 1, 2015 through June 30, 2016, on an interim

basis.

The proposed total fuel factor, Fuel Charge Rider A, consists of both a current period and

a prior period factor. Fuel Charge Rider A's current period factor of $0.02374/kWh is

designed to recover the Company's estimated Virginia jurisdictional fuel expenses of

approximately $1.6 billion for the period July 1,2015 through June 30, 2016.

Fuel Charge Rider A's prior period factor of$0.00032/kWh is designed to recover

approximately $21.9 million, which is the net of two projected June 30, 2015 balances:

(1) The projected June 30, 2015 over-recovery balance of approximately $24.0

million associated with recovery of the July 1,2014 through June 30, 2015 current period

expense;

(2) The projected June 30, 2015 under-recovery balance of approximately $45.9

million associated with recovery of the remaining January 31, 2015 prior period expense

to be recovered through June 30, 2015.

Do you have a schedule that shows the fuel factor expenses that the Company

expects to incur during the period July 1,2014 through June 30, 2015?

Yes. Schedule 1 shows estimated system fuel factor expenses in Column 1 (as provided

2

1

2

3 Q.

4

5 A.

6

7

8

9 Q.

10

11 A.

12

13

14

15 Q.

16 A.

17

18

19

20

21

in Company Exhibit No. _, GAK Schedule 2, Page 2 of 3), allocated to the Virginia

jurisdiction for the current period shown in Column 3.

Do you have a schedule that shows the calculation of the current period factor of

Fuel Charge Rider A?

Yes. Schedule 2 shows the calculation of the current period factor. The total Virginia

jurisdictional estimated fuel factor expense of approximately $1.6 billion was divided by

the total estimated Virginia jurisdictional kWh sales for July I, 2015 through June 30,

2016. The result is the current period factor of$0.02374/kWh.

Do you have a schedule that shows the estimated recovery of the proposed current

period factor?

This is shown on Schedule 3. Estimated Virginia jurisdictional fuel factor expenses by

month from July 1,2015 through June 30, 2016 are compared to estimated monthly

Virginia jurisdictional fuel revenues by month, and the estimated resulting over- or

under-recoveries of fuel expenses for each month are shown.

Please describe the development of the prior period factor.

In order to develop the proposed prior period factor, we must first estimate the

Company's projected June 30, 2015 deferral balance.

To do so, we must first determine the projected June 30, 2015 balance associated with the

present current period expenses. The estimated system fuel expenses allocated to the

Virginia jurisdiction for the period February 1 through June 30, 2015 are calculated and

shown on my Schedule 4.

3

1

2

3

4

5

6

7

8

9

10

11

12

13 Q.

14

15 A.

16

17 Q.

18

19 A.

20

Schedule 5, Row 1, contains the January 31, 2015 actual current period deferral balance

of approximately ($84.3) million and the actual prior period deferral balance of

approximately $72.7 million (assuming 50% of the December 31, 2014 deferral

balancer), as explained by Company Witness John C. Ingram. Estimated February

through June 2015 Virginia jurisdictional sales were obtained from Company Witness

Glenn A. Kelly.

Column 10 shows the Company's total June 30, 2015 projected net balance of

approximately $21.9 million associated with the current and prior period assuming April

1, 2015 implementation of the proposed current and prior period factors in this case.

Schedule 6 shows the calculation of the proposed prior period factor of$0.00032/kWh by

dividing this $21.9 million under-recovery by the total estimated Virginia jurisdictional

kilowatt-hour sales for the fuel year.

What is the total fuel factor that the Company is requesting to become effective

April 1, 2015 through June 30, 2016, on an interim basis?

Schedule 7 shows the components ofthe proposed total fuel factor rate of $0.02406/kWh

compared to the present Fuel Charge Rider A factor of$0.03018/kWh.

Have you included in your exhibit revisions to Fuel Charge Rider A to reflect the

Company's proposed total fuel factor for April 1, 2015, on an interim basis?

Yes. My Schedule 8 shows the revised Fuel Charge Rider A, which would be applicable

for usage on and after April 1, 2015, on an interim basis.

2 This is a savings to customers of$O.OOl02lkWh per month, or $1.02/MWh, based on projected sales for the periodApril 2015 June 2016.

4

1 Q. Mr. Anderson, would you explain how these proposed changes in the fuel factor

2 would affect customers' bills?

3 A. Schedule 9 provides typical bill comparisons (base and fuel) for Rate Schedules 1, GS-l,

4 GS-2, GS-3, GS-4, and 5C based on the proposed April 1, 2015 fuel factor and rates

5 pending State Corporation Commission of Virginia approval to be effective on April 1,

6 2015. As shown on Schedule 9, Page 1, for a residential customer using 1,000 kWh per

7 month, the typical bill in the summer months (June through September) would decrease

8 $6.12 from $119.47 to $113.35 or by 5.1%. The typical bill for a residential customer

9 using 1,000 kWh in the base months (October through May) would decrease $6.12 from

10 $113.77 to $107.65, or by 5.4%. The average weighted monthly residential bill (4

11 summer months and 8 base months) would decrease $6.12 from $115.67 to $109.55, or

12 by 5.3%. For reference, page 10 of Schedule 9 provides a workpaper showing the billing

13 components of the 1,000 kWh residential bill proposed for April 1,2015.

14 Q. Does this conclude your pre-filed direct testimony?

15 A. Yes, it does.

5

APPENDIX A


EDWARD J. ANDERSON

Edward 1. Anderson graduated from the Virginia Military Institute in 2002 with a

Bachelor of Arts degree in Economics and Business. He was hired by Dominion in 2003. From

2003 to 2007, he worked at the Dominion Energy Clearinghouse in the Electric Accounting

group as a Business Operations Support Associate, and in the Electric Trading group as a Power

Market Analyst. His responsibilities included Power Pool (P1M and NE-ISO) reconciliation,

analysis, and trading support. In 2007, he was promoted to Hourly Trader within the Electric

Trading group. In 2008, Mr. Anderson moved to the State Regulation Department as Regulatory

Analyst III. In April 2014, Mr. Anderson was promoted to his current position as Regulatory

Advisor. His responsibilities include providing support and analysis as it relates to rate design

for the Company's regulatory filings within Virginia and North Carolina.

Mr. Anderson has previously presented testimony before the State Corporation

Commission of Virginia, the North Carolina Utilities Commission, and the Federal Energy

Regulatory Commission.

Company Exhibit No._Witness: EJA

Schedule 1Page 1 of 1

VIRGINIA JURISDICTIONAL ALLOCATED EXPENSESJULY 2015 THROUGH JUNE 2016

(1) (2) (3)TOTAL

TOTAL VIRGINIA JURISDICTION VIRGINIA JURISDICTIONSYSTEM FUEL ALLOCATION ALLOCATED FUEL

EXPENSE FACTOR EXPENSE(A) (1) x (2)

JULY 2015 $ 204,354,304 0.802349 $ 163,963,374

AUGUST $ 192,895,716 0.799842 $ 154,286,186

SEPTEMBER $ 139,832,528 0.782574 $ 109,429,313

OCTOBER $ 123,739,255 0.775092 $ 95,909,338

NOVEMBER $ 145,938,899 0.784493 $ 114,488,005

DECEMBER $ 184,775,324 0.807942 $ 149,287,795

JANUARY 2016 $ 244,813,807 0.812990 $ 199,031,144

FEBRUARY $ 184,433,804 0.809161 $ 149,236,645

MARCH $ 157,701,413 0.793859 $ 125,192,685

APRIL $ 138,381,623 0.784172 $ 108,514,938

MAY $ 137,959,990 0.784832 $ 108,275,367

JUNE $ 171,037,152 0.795942 $ 136,135,736

TOTAL $ 2,025,863,813 $ 1,613,750,526

(A) From Company Exhibit No. __, GAK, Schedule 2, Page 2 of 3.

FUEL CHARGE RIDER A CURRENT PERIOD FACTORJULY 2015 THROUGH JUNE 2016(Rates in Dollars per Kilowatt-hour)

1. ESTIMATED VA JURISDICTIONAL ALLOCATED FUEL EXPENSE (A)JULY 2015 - JUNE 2016

2. ESTIMATED VIRGINIA JURISDICTIONAL KWH SALES (B)JULY 2015 - JUNE 2016

3. ZERO BASE FACTOR ="F"

F = (E) / (8)

E = $1,613,750,526S = 67,972,748,794

F = $0.02374per kWh

(A) From Company Exhibit No. __' EJA, Schedule 1, Column 3.(B) From Company Exhibit No. __, GAK, Schedule 1.

$ 1,613,750,526 ="E"

67,972,748,794 ="S"



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ESTIMATED VIRGINIA JURISDICTIONAL ALLOCATED EXPENSESFEBRUARY 2015 THROUGH JUNE 2015

(1) (2) (3)TOTAL

TOTAL VIRGINIA JURISDICTION ALLOCATEDSYSTEM FUEL ALLOCATION VIRGINIA JURISDICTION

2015 EXPENSE FACTOR FUEL EXPENSE(A) (1) X (2)

FEBRUARY $ 260,673,103 0.808205 $ 210,677,289

MARCH $ 177,976,374 0.792473 $ 141,041,422

APRIL $ 155,764,251 0.782554 $ 121,893,996

MAY $ 159,029,982 0.783341 $ 124,574,660

JUNE $ 182,360,587 0.794660 $ 144,914,614

TOTAL $ 935,804,296 $ 743,101,981

(A) From Company Exhibit No. _, GAK, Schedule 8.



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FUEL CHARGE RIDER A PRIOR PERIOD FACTORJULY 2015 THROUGH JUNE 2016(Rates in Dollars per Kilowatt-hour)

1. ESTIMATED VIRGINIA JURISDICTION ALLOCATED FUEL EXPENSEJULY 2015 - JUNE 2016 (A)

2. ESTIMATED VIRGINIA JURISDICTIONAL KWH SALESJULY 2015 - JUNE 2016 (B)

3. ZERO BASE FACTOR ="F"

F =(E) / (8)

E = $21,892,680S = 67,972,748,794

F = $0.00032per kWh

(A) From Company Exhibit No. __, EJA, Schedule 5, Column 10.(B) From Company Exhibit No. __, GAK, Schedule 1.



$21,892,680 = "E"

67,972,748,794 = "S"

APRIL 1,2015 - JUNE 30, 2016 PROPOSED FUEL FACTORTOTAL FUEL FACTOR COMPARISON

(Rates in Dollars per Kilowatt-hour)



PROPOSED

PRESENT

DIFFERENCE

CURRENT PERIODFACTOR

$0.02374

$0.02819

($0.00445)

PRIOR PERIODFACTOR

$0.00032

$0.00199

($0.00167)

RIDER A TOTAL FUELFACTOR

$0.02406

$0.03018

($0.00612)

Virginia Electric and Power CompanyCompany Exhibit No._Witness: EJASchedule 8

FUEL CHARGE RIDER-A

The charge for service under Virginia Electric and Power Company's Filed Rate

Schedules 1, IP, IS, IT, lW, DP-R, lEV, EV, 5, 5C, 5P, 6, GS-l, DP-l, GS-2, DP-2, GS-2T,

GS-3, GS-4, 6TS, 7, 8, 10,25,27,28 and 29, as well as applicable energy charges specified in

any special rates, contracts or incentives approved by the State Corporation Commission

pursuant to Virginia Code § 56-235.2 shall be increased by 2.406 cents per kilowatthour.

Filed 02-27-15Electric-Virginia

Superseding Filing Effective For UsageOn and After 07-01-14. This Filing EffectiveFor Usage On and After 04-01-15, On anInterim Basis.

Company Exhibit No. _Witness: EJA

Schedule 91 of 10

VIRGINIA ELECTRIC AND POWER COMPANYTYPICAL BILLS - RESIDENTIAL - SCHEDULE 1

SUMMER MONTHS

EFFECTIVE FOR EFFECTIVE FOR

USAGE ON AND AFTER USAGE ON AND AFTER

04-01-2015' 04-01-2015"APPLICABLE APPLICABLE

BASIC NON-FUEL TOTAL BASIC NON-FUEL TOTAL PERCENT

KWH RATE # RIDERS## FUEL' BILL RATE # RIDERS## FUEL" BILL DIFFERENCE DIFFERENCE

500 $42.12 $5.03 $15.09 $62.24 $42.12 $5.03 $12.03 $59.18 ($3.06) -4.9%

750 $59.67 $7.56 $22.64 $89.87 $59.67 $7.56 $18.05 $85.28 ($4.59) -5.1%

1,000 $79.24 $10.05 $30.18 $119.47 $79.24 $10.05 $24.06 $113.35 ($6.12) -5.1%1

1,500 $119.38 $15.08 $45.27 $179.73 $119.38 $15.08 $36.09 $170.55 ($9.18) -5.1%

2,000 $159.52 $20.10 $60.36 $239.98 $159.52 $20.10 $48.12 $227.74 ($12.24) -5.1%

2,500 $199.66 $25.13 $75.45 $300.24 $199.66 $25.13 $60.15 $284.94 ($15.30) -5.1%

3,000 $239.80 $30.15 $90.54 $360.49 $239.80 $30.15 $72.18 $342.13 ($18.36) -5.1%

5,000 $400.36 $50.25 $150.90 $601.51 $400.36 $50.25 $120.30 $570.91 ($30.60) -5.1%

BASE MONTHS

APPLICABLE APPLICABLE



500 $42.12 $5.03 $15.09 $62.24 $42.12 $5.03 $12.03 $59.18 ($3.06) -4.9%

750 $59.67 $7.56 $22.64 $89.87 $59.67 $7.56 $18.05 $85.28 ($4.59) -5.1%

1,000 $73.54 $10.05 $30.18 $113.77 $73.54 $10.05 $24.06 $107.65 ($6.12) -5.4%1

1,500 $99.46 $15.08 $45.27 $159.81 $99.46 $15.08 $36.09 $150.63 ($9.18) -5.7%

2,000 $125.36 $20.10 $60.36 $205.82 $125.36 $20.10 $48.12 $193.58 ($12.24) -5.9%

2,500 $151.28 $25.13 $75.45 $251.86 $151.28 $25.13 $60.15 $236.56 ($15.30) -6.1%

3,000 $177.18 $30.15 $90.54 $297.87 $177.18 $30.15 $72.18 $279.51 ($18.36) -6.2%

5,000 $280.82 $50.25 $150.90 $481.97 $280.82 $50.25 $120.30 $451.37 ($30.60) -6.3%

# BASIC RATE INCLUDES BASE DISTRIBUTION, GENERA TION, AND EMBEDDED TRANSMISSION RATES.## REFLECTS CURRENT APPLICABLE NON-BASE RATE RIDERS AND THOSE PENDING COMMISSION APPROVAL TO BE EFFECTIVE APRIL 1, 2015.

, REFLECTS TOTAL CURRENT FUEL LEVEL OF $0.03018 PER KWH." REFLECTS TOTAL PROPOSED FUEL LEVEL OF $0,02406 PER KWH.

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Schedule 99 of 10

VIRGINIA ELECTRIC AND POWER COMPANYTYPICAL BILLS - CHURCH AND SYNAGOGUE - SCHEDULE 5C

SUMMER MONTHS

EFFECTIVE FOR EFFECTIVE FORUSAGE ON AND AFTER USAGE ON AND AFTER

04-01-2015' 04-01-2015**APPLICABLE APPLICABLE

BASIC NON·FUEL TOTAL BASIC NON·FUEL TOTAL PERCENT


1,500 $118.56 $17.75 $45.27 $181.58 $118.56 $17.75 $36.09 $172.40 ($9.18) -5.1%

3,000 $228.61 $35.49 $90.54 $354.64 $228.61 $35.49 $72.18 $336.28 ($18.36) -5.2%

5,000 $367.57 $59.15 $150.90 $577.62 $367.57 $59.15 $120.30 $547.02 ($30.60) -5.3%

7,500 $541.27 $88.73 $226.35 $856.35 $541.27 $88.73 $180.45 $810.45 ($45.90) -5.4%

10,000 $714.97 $118.30 $301.80 $1,135.07 $714.97 $118.30 $240.60 $1,073.87 ($61.20) -5.4%

15,000 $1,062.37 $177.45 $452.70 $1,692.52 $1,062.37 $177.45 $360.90 $1,600.72 ($91.80) -5.4%

BASE MONTHSAPPLICABLE APPLICABLE



1,500 $11856 $17.75 $45.27 $181.58 $118.56 $17.75 $36.09 $172.40 ($918) -5.1%

3,000 $228.61 $35.49 $90.54 $354.64 $228.61 $35.49 $72.18 $336.28 ($18.36) -5.2%

5,000 $355.73 $59.15 $150.90 $565.78 $355.73 $59.15 $120.30 $535.18 ($30.60) -5.4%

7,500 $514.63 $88.73 $226.35 $829.71 $514.63 $88.73 $180.45 $783.81 ($45.90) -5.5%

10,000 $673.53 $118.30 $301.80 $1,093.63 $673.53 $118.30 $240.60 $1,032.43 ($61 :20) -5.6%

15,000 $991.33 $177.45 $452.70 $1,621.48 $991.33 $177.45 $360.90 $1,529.68 ($91.80) -5.7%

# BASIC RA TE INCLUDES BASE DISTRIBUTION, GENERATION, AND EMBEDDED TRANSMISSION RATES.

## REFLECTS CURRENT APPLICABLE NON-BASE RATE RIDERS AND THOSE PENDING COMMISSION APPROVAL TO BE EFFECTIVE APRIL 1, 2015., REFLECTS TOTAL CURRENT FUEL LEVEL OF $0.03018 PER KWH.

*' REFLECTS TOTAL PROPOSED FUEL LEVEL OF $0.02406 PER KWH.

DOMINION VIRGINIA POWER1,000 KWH SEASONALLY WEIGHTED RESIDENTIAL BILLRATE SCHEDULE 1

BILL COMPONENTS ~

DISTRIBUTION· BASE s 27.63GENERATION· BASE $ 38.11TRANSMISSION $ 9.43FUEL s 24.06GENERATION A6 $ 9.70DSM/EE A5 $ 0.62

TOTAL BILL $ 109.55


Schedule 910 of 10

KWH KWHRATES RATES 1,000 I 1,000 I

BILL COMPONENTS SUMMER NON·SUMMER SUMMER NON·SUMMER WEIGHTED

BASIC CUSTOMER CHARGE $ 7.00 s 7.00 s 7.00 $ 7.00 $ 7.00

DISTRIBUTION 800 KWH $ 0.02258 $ 0.02258 $ 18.06 $ 18.06 $ 18.06

DISTRIBUTION OVER 800 KWH $ 0.01285 $ 0.01285 $ 2.57 $ 2.57 $ 2.57

ELECTRICITY SUPPLY SERVICE 800 KWH $ 0.03795 $ 0.03795 $ 30.36 $ 30.36 $ 30.36

ELECTRICITY SUPPLY SERVICE OVER 800 KWH $ 0.05773 $ 0.02927 $ 11.55 $ 5.85 7.75

TRANSMISSION $ 0.00970 s 0.00970 $ 9.70 $ 9.70 s 9.70

RIDER T1 • TRANSMISSION $ (0.00027) $ (0.00027) s (0.27) $ (0.27) $ (0.27)

FUEL FACTOR RIDER A' $ 0.02406 $ 0.02406 $ 24.06 $ 24.06 $ 24.06

RIDER C1A (A5) $ 0.00002 $ 0.00002 $ 0.02 s 0.02 $ 0.02

RIDER C2A (A5) $ 0.00060 $ 0.00060 $ 0.60 s 0.60 0.60

RIDER B • BIOMASS (A6)' $ 0.00022 $ 0.00022 $ 0.22 $ 0.22 $ 0.22

RIDER R • BEAR GARDEN (A6)' $ 0.00143 $ 0.00143 $ 1.43 $ 1.43 $ 1.43

RIDER S • VCHEC (A6)' $ 0.00418 s 0.00418 $ 4.18 $ 4.18 $ 4.18

RIDER W· WARREN COUNTY (A6) $ 0.00230 $ 0.00230 $ 2.30 $ 2.30 2.30

RIDER BW • BRUNSWICK COUNTY (A6) $ 0.00157 $ 0.00157 $ 1.57 $ 1.57 $ 1.57

BILL AMOUNT $ 113.35 $ 107.65 109.55

BLEND (SUMMER x 4 • NON·SUMMER x 8) $ 453.40 $ 861.20

AVG $ 109.55

'PENDING SCC APPROVAL

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