Application, Direct Testimony and Exhibits of Virginia Electric and Power Company Before the State Corporation Commission of Virginia Application of Virginia Electric and Power Company to revise its fuel factor pursuant to Va. Code § 56-249.6 Case No. PUE-2015-00022 Filed: February 27, 2015 PUBLIC VERSION
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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.
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
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 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.
What is the purpose of your testimony in this proceeding?
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
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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
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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.
Does this conclude your pre-filed direct testimony?
Yes, it does.
5
APPENDIX A
BACKGROUND AND QUALIFICATIONSOF
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
'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
Company Exhibit No. __Witness: RGTSchedule 2Page 2 of3
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
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Company Exhibit No. __Witness: RGTSchedule 3Page 6 of7
Historical Commodity Prices
502 Allowances
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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
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.
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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.
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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.
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9 Q.
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11 A.
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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
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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
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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).
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11 Q.
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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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8 Q.
9
10 A.
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20 Q.
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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
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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.
Does this conclude your pre-filed direct testimony?
Yes, it does.
11
APPENDIX A
BACKGROUND AND QUALIFICATIONSOF
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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311,
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541,
203,
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130,
243,
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201,
722,
665
(9,1
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Nov
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192,
528,
498
(10,
283,
846)
Dec
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182,
244,
652
(11,
471,
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Janu
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170,
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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
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 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
background and qualifications is attached as Appendix A.
What is the purpose of your testimony in this proceeding?
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.
During the course of your testimony, will you introduce an exhibit?
Yes. Company Exhibit No. __, EJA, consisting of Schedules 1 through 9, was
prepared under my supervision and direction, and is accurate and complete to the best of
my knowledge and belief.
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
BACKGROUND AND QUALIFICATIONSOF
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"
Company Exhibit No._Witness: EJA
Schedule 2Page 1 of 1
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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.
Company Exhibit No._Witness: EJA
Schedule 4Page 1 of 1
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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.
Company Exhibit No._Witness: EJA
Schedule 6Page 1 of 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)
Company Exhibit No._Witness: EJA
Schedule 7Page 1 of 1
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
# 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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Company Exhibit No. _Witness: EJA
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
KWH RATE # RIDERS## FUEL' BILL RATE # RIDERS## FUEL" BILL DIFFERENCE DIFFERENCE
# 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
Company Exhibit No. _Witness: EJA
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