DELMARVA POWER & LIGHT COMPANY /
APPLICATION FOR AN INCREASE
IN NATURAL GAS BASE RATES
/' TESTIMONY AND SCHEDULES (BOOK 2 OF 3)
BEFORE THE
DEL A WARE PUBLIC SERVICE COMMISSION
I August 3172006 1 DELMARV A POWER & LIGHT COMPANY 2 TESTIMONY OF MARK BROWNING
3 BEFORE THE DELAWARE PUBLIC SERVICE COMMISSION 4 CONCERNING AN INCREASE IN GAS BASE RATES 5 DOCKET NO. 06-
6
7 1. Q: Please state your name and position. and business address.
8 A: My name is Mark Browning. I am Director of Rates and Technical
9 Services, Regulatory Affairs, for Pepco Holdings Inc. ("PHI"). My business
10 address is 401 Eagle Run Road, Newark, DE 19714. I am testifying on behalf of
11 Delmarva Power & Light Company ("Delmarva" or "the Company"). A
12 statement of my occupational and educational history and qualifications is
13 appended to this testimony as Schedule MEB-1.
14 2. Q: What are your responsibilties in your role as Director of Rates and
15 Technical Services. Rel!ulatorv Affairs?
16 A: I am responsible for overseeing the Company's cost of service, rate design
17 and revenue requirements functions relating to PHI's three regulated utility
18 subsidiaries, including Delmara Power & Light Company ("Delmarva" or "the
19 Company").
20 3. Q: Have yOU recentlv testifed before the Delaware Public Service Commission?
21 A: Yes, most recently, I fied testimony before the Delaware Public Service
22 Commission in the Company's SOS proceeding in Docket No. 04-391. I have
23 also presented testimony before the Maryland Public Service Commission, the
24 District of Columbia Public Service Commission, the Federal Energy Regulatory
1 1 Commission, and the Surface Transportation Board of the United States
2 Department of Transportation.
3 4. Q: What is the purpose ofvour testimony? 4 A: I am the overall regulatory policy witness and I provide support for the
5 Company's Application for an increase in Gas Base Rates. The costs of providing
6 safe and reliable service to the Company's gas customers has increased
7 considerably, and this requested rate increase is necessary in order to provide
8 Delmara with full and timely recovery of these costs. I also present the
9 Company's proposal for a revenue stabilization mechanism, which has benefits
10 for the Company and for customers. As part of my testimony I wil provide an
11 overview of the filing by Delmarva and I wil briefly summarize the testimony of
12 the Company's other witnesses.
13 5. Q: Please provide an overview of what the Company is reQuestinl!.
14 A: The Company is requesting approval of a proposed Increase of
15 $14,967,412 in its gas delivery base rates or 6.62% of total revenue. As stated in 16 this Application, the Company is requesting a Return on Equity (ROE) of
17 11.00%, which results in an overall rate of return of 8.08%. As explained by Dr.
18 Morin, the Company's requested ROE is based on the Commission approving a
19 Bill Stabilization Adjustment (BSA) mechanism, which has the effect of lowering
20 somewhat the Company's risk profie. Without the approval of the BSA, the
21 Company's proposed ROE increases to 11.25%, and the Company's revenue
22 requirement would increase approximately $500,000.
2 1 The Company, coincident with this filing, also filed its annual Gas Cost
2 Rate (GCR) adjustment and Environmental Surcharge Rider (ESR). The
3 combined effect of the three filings, if approved by the Commission and fully
4 implemented, will be a very modest overall reduction to rate levels. However,
5 since the GCR and ESR charges will go into effect on November 1,2006, while
6 the full impact of the base rate request wil not occur until the spring of 2007, on
7 November 1, 2006 a typical residential space heating customer using 120 ccf
8 during the heating season will experience an overall rate decrease of 6.2% or a
9 reduction of$l1.73.
10 6. Q: Please summarize the Company's earninl!s condition in the test period for
11 the l!as business.
12 A: The Company developed a fully historic test year and test period of the
13 twelve months ended March 2006. It is the most recent historical period available
14 and incorporates the most recent winter period. This test period, with the
15 adjustments proposed, represents a reasonable basis for establishing the
16 Company's revenue requirements. As shown in the Company's fiing, for the test
17 period as adjusted, the Company is earning a Rate of Return (ROR) of only
18 4.35%. The information is summarized in Company Witness VonSteuben's
19 testimony, as Schedule WMV-23.
20 7. Q: When did the Company last fie for a l!as base rate increase?
21 A: The Company last requested an increase in gas base rates in 2003 in
22 Docket No. 03-127. The Commission approved Order No. 6327 in Docket No.
23 03-127 which approved a Settlement Agreement reached by the paries involved
3 1 in the case which provided for an anual gas base rate increase of $7.75 milion.
2 Rates went into effect December 10, 2003. The Settlement Agreement specified
3 an ROE of 10.5%. It was quickly apparent to the Company, however, that the
4 increase was insufficient, as the first historical test year after rates became
5 effective showed that the Company was only able to achieve a 7.77% ROE, based
6 on the Company's Rate of Return submittal with the Commission for 2004.
7 8. Q: Please explain the structure of this tilinl!.
8 A: Book 1 consists of the Application, the Minimum Filing Requirements,
9 and Tariff Modifications. Book 2 is comprised of the testimony of several
10 witnesses that support the Company's request for an increase in gas base rates.
11 Book 3 is comprised of work-papers to support the Company's adjustments and 12 Rate Design.
13 9. Q: Please describe the testimony that wil be presented in support of this 14 Application. 15 A: There are eight other witnesses presenting testimony in support of the
16 Company's Application. They are as follows:
17 . Mr. Charles L. Driggs, Manager of Gas Operations and Planning, 18 discusses the overall Gas business, and in particular the cost increases that 19 result from the need to provide safe and reliable service.
20 · Ms. Kathleen A. White is Assistant Controller for PHI and its operating
21 companies. Ms. White sponsors the books and record of the Company.
22 . Mr. W. Michael V onSteuben, Manager of Revenue Requirements, 23 discusses the development of the proposed revenue requirement.
4 1 . Mr. Joseph F. Janocha, Regulatory Affairs Manager, discusses the
2 Company's rate design initiatives, and the proposed rate increase that is
3 applicable to the various customer classes. He also sponsors the
4 Company's tariff rates and certain miscellaneous proposed tariff changes.
5 · Dr. Kemm C. Farney, Regulatory Affairs Lead, discusses the details of the
6 Company's weather normalization, the effects of rising prices on gas sales
7 volumes, and calculations of the design day requirements for certain 8 customer classes.
9 . Dr. Roger A. Morin is a principal at Utility Research International as well 10 as a Professor of Finance at the College of Business at Georgia State 11 University and Professor of Finance for Regulated Industry at the Center 12 for the Study of Regulated Industry at Georgia State University. Dr. 13 Morin provides testimony on capital structure as well as the appropriate
14 fair rate of return including the cost of equity that the Commission should 15 allow the Company an opportunity to earn.
16 · Dr. John H. Chamberlin of Quantec, LLC., discusses the Company's 17 proposed Bil Stabilization Adjustment.
18 . Mr. Paul M. Normand, a Principal with Management Applications
19 Consulting, Inc., supports the Company's Cost of Service study. 20 10. Q: What are the reasons that the Company is reQuestinl! this increase? 21 A: The costs of providing safe and reliable service have increased sharply
22 over the last few years. Operating expenses have increased from $37.2 million to
23 $44.1 milion, or 19%, since the Company's last base rate filing. Mr. Driggs
5 1 discusses the increased costs, including additional safety requirements, which are
2 causing this increase. In addition, the gas rate base has increased from $216.3
3 millon to $237.7 millon, or 10%. Adjusting for the rate increase of $7.75
4 millon allowed in the last case, revenues have been essentially flat, so that these
5 cost increases are not mitigated by any increase in revenues.
6 The current level of rates must be increased to reflect the current level of
7 costs that the Company is incurrng to provide service to its gas customers. The
8 Company intends to continue to meet its obligation to provide safe and reliable
9 service to its customers, and it needs to fully recover the costs required to do so in
10 a timely maner.
11 11. Q:Whv is the Company reQuestinl! a chanl!e in ROE from the last authorized
12 ROE of 10.5% to 11.00%?
13 A: The ROE that the Company requests in this Application is discussed in
14 detail in Dr. Morin's testimony. The last authorized ROE of 10.5%, which was
15 determined as par of an overall settlement, is not an accurate reflection of the true
16 cost of equity capital to the Company. As supported by Dr. Morin, a fair rate of
17 return of 11.00% is needed to attract capital and support reasonable credit quality.
18 Since Docket No. 03-127, financial conditions have changed so that an 11.00%
19 ROE is now representative of the current capital markets, as demonstrated by Dr.
20 Morin under the assumption that the Commission approves the Company's
21 proposal for a BSA.
22 12. Q: Please discuss the recent downl!rade of the Company's debt ratinl!s bv the 23 major ratinl! al!encIes.
6 1 A: A key indicator that the Company's risk profile for investors has increased
2 is the recent actions of the rating agencies. For instance, following its review for
3 possible downgrade initiated in March 2006, Moody's downgraded the ratings of
4 DP&L's senior unsecured debt from Baal to Baa2 on July 11,2006. Among the
5 factors causing the downgrade, Moody's cited the following:
6 "The signifcant decline in the supportiveness of the regulatory
7 environments for electric utilities in Maryland and Delaware... "
8 "Expectations that rate relief wil be less constructive in the currently
9 contentious environment ...
10 "Legislative and regulatory developments in both Maryland and
11 Delaware that wil defer regulatory recovery of some of the substantially
12 higher costs that resulted from power supply auctions held in those states
13 earlier this year. "
14 "Signs of a tougher regulatory response in Delaware... "
15 In addition, on August 7, 2006 S&P downgraded DP&L's credit ratings
16 from BBB+ to BBB citing "an increasingly challenging regulatory environment"
17 as a driving factor
18 As discussed in detail by Dr. Morin, these downgrades affect the
19 Company's ability to raise capital at reasonable rates, and the rating agencies and
20 the overall investment community wil be following the Commission's actions. It
21 is important for the Company and its customers that the investment community
22 view the environment in Delaware in a more positive maner, consistent with the
23 view that prevailed previously.
7 1 13. Q: Please describe the Company's proposed Bil Stabilzation Adjustment 2 mechanism. 3 A: The Company is proposing a bill stabilization mechanism, the Bill
4 Stabilization Adjustment (BSA), which provides a better opportunity that the
5 Company will recover the Commission approved test year revenue requirement in
6 the rate effective period. In essence, the BSA provides for decreases in delivery
7 rates if actual revenues per customer are above the Commission approved level,
8 and it provides for an increase in delivery rates if actual revenues per customer are
9 below the Commission approved leveL. The BSA provides benefits to both the
10 Company and the customer. Mr. J anocha provides the details of the mechanism 11 in his testimony.
12 14. Q: Please discuss why this mechanism is beneficial. 13 A: In colder than normal winters in which customers face sharply higher bills,
14 the BSA will reduce the payments that would otherwise be due. Conversely
15 under the BSA, customers wil pay more for delivery in a mild winter than they
16 would otherwise, but their overall bills will stil be down compared to what they
17 would be with normal winter weather. In short, customers' bil variability is
18 somewhat decreased. In addition, since the BSA reduces somewhat the
19 Company's financial risk, the Company requires a lower return on equity, which
20 allows rates to be lower by approximately $500,000.
21 The BSA provides the Company with a stream of revenues consistent with
22 the costs of providing safe and reliable service. The Company's costs for
23 providing service are generally fixed regardless of the volume of sales that the
8 1 Company delivers to its customers. This proposal provides for a matching of
2 revenues in the rate effective period with the amounts that the Commission has
3 approved as adequate compensation for providing service. The majority of the
4 sales in the gas business are weather driven. This has the implication that if a
5 heating season has colder than normal weather, the Company collects more than
6 the test year revenues that are set based on a definition of normal weather.
7 Conversely, if a particular heating season has warmer than normal weather, the
8 opposite is true. The BSA as proposed by the Company creates an adjustment to
9 customers' bils that is designed to reflect differences between Commission-
10 approved delivery revenue levels and actual delivery revenues. This is good for
11 the customer because the Company's customers wil pay only the amount
12 determined by the Commission as required to provide safe and reliable service.
13 This is a benefit to the Company because the Company can maintain a stable
14 revenue stream year to year.
15 Thus, both customers and the Company are better off under the
16 mechanism. The mechanism also protects the Company from ongoing attrition
17 due to the reduced usage of customers. This wil help avoid frequent rate cases
18 and the attendant costs.
19 As previously stated, Dr. Morin has incorporated the benefits to the
20 Company of the BSA in his determination of the Company's required Return on
21 Equity. Without this mechanism, the required ROE would be increased.
9 1 15. Q: Have other utilties implemented this type of revenue stabilization
2 mechanism?
3 A: Yes. In our region, both Baltimore Gas & Electric and Washington Gas
4 Light Company in Maryland have implemented a mechanism similar to the
5 proposed BSA. Dr. Chamberlin discusses in more detail how widespread this
6 type of mechanism has become throughout the country.
7 16. Q. Are there other reasons to implement the BSA?
8 Yes. The BSA removes the incentive for the Company to maximize its
9 sales in order to benefit shareholders. Without the BSA, the Company's
10 shareholders benefit with each additional mcf delivered. With the BSA, the link
11 between increased sales and profits is broken. The Company's interest in helping
12 its customers use energy wisely and effciently is no longer at seeming odds with
13 the interests of shareholders. If the Commission or the State were to institute
14 conservation programs to help customers meet the challenges of the current high
15 costs of energy, the Company's support of those efforts would not conflict with
16 the interests of shareholders.
17 17. Q: How did the Company distribute the proposed increase amonl! the rate
18 classes?
19 A: The Company distributed the proposed increase to the customer classes in
20 a way that wil move the class rates of return toward unity. It is appropriate to
21 strive to equalize rates of return across customer classes to remove any class
22 cross-subsidies. As a result, customer classes with lower rates of return have been 23 apportioned a relatively higher increase, and customer classes with higher rates of
10 1 return have been apportioned a relatively lower increase. The appropriate rate
2 making policy is for each customer class to pay of its full cost of service. Mr.
3 Normand discusses the determination of the current class rates of return, and Mr.
4 Janocha describes the Company's rate design proposals based on these findings.
5 18. Q: Does the Company plan to place an interim increase. of $2.5 Milion into
6 effect as permitted under 26 DeL. C. § 306 (c).
7 A: Yes, it does. If the Commission chooses to suspend this proceeding for
8 the full suspension period, the Company plans to place in effect, subject to refund,
9 an interim annual increase of approximately $2.5 Million. On November 1, as
10 permitted by state law, the Company will place $2.5 million of the proposed
11 delivery base rate increase in effect on an interim basis while the Commission
12 reviews the proposed rates. If the Commission approves an overall increase of
13 less than $2.5 milion, the Company would refund, with interest, the difference
14 between the interim and the Commission-approved rates. Modified Tariff Leafs
15 reflecting the interim increase are included in this Application.
16 The typical bil for space-heating customers using 120 ccf per month
17 during the heating season will increase $1.84 or by 1.0% from $189.62 to $191.46
18 due to the interim rate increase which reflects changes to the base rates only.
19 Coincident with the interim base rate increase, the Company has proposed to put
20 into effect a Gas Cost Rate (GCR) decrease and an increase in the Gas
21 Environmental Surcharge Rider. On November 1, 2006, a typical residential
22 space-heating customer using 120 ccf per month during the heating season will
11 1 see a net total decrease resulting from all three filings of $11.73 from $189.62 to
2 $177.89, or 6.2%.
3 19. Q: Please address the customer impact of the full proposed increase.
4 A: The typical bil for a space-heating customer using 120 ccf per month
5 during the heating season wil increase $10.49 by 5.5% from $189.62 to $200.11
6 which reflects proposed changes to base rates only. On an anual basis the total
7 revenue increase for the residential class is 7.2%. Mr. Janocha wil address in
8 detail in his testimony the impact of the proposed increase on all customer classes. 9 The bill impact resulting from all three filings on a typical residential space-
10 heating customer using 120 ccf during the heating season is a net total decrease of
11 $3.08 from $189.62 to $186.54. On an annual basis, taking the impact of all three 12 filings into consideration, residential customer bills should remain approximately 13 the same as current levels. 14 If full proposed rates are adopted and netted against the GCR decrease and 15 ESR increase to take place on November 1, 2006, a typical residential space-
16 heating customer will see a modest reduction. The effect of all three fiings,
17 including the full proposed base rates, on a typical bil for a space-heating
18 customer using 120 ccf per month would be a net total decrease of $3.08 from 19 $189.62 to $186.54, or 1.6%.
20 20. Q: Are yOU sponsorinl! any Filnl! Requirements? 21 A: Yes, I am sponsoring Schedule A - Period Definitions of the following 22 portions of the Minimum Filing Requirements.
12 1 21. Q: Are there any specitic items where the Company is proposinl! rate makinl!
2 treatment that differs from recent Commission approval?
3 A: The Company has not removed any of the employee incentive payments
4 that were made in the test period, which is different than what the Commission
5 approved for recovery in Docket No 05-304. Incentives paid to employees are
6 legitimate business expenses that the Company should be allowed to recover from
7 customers. As the Company has stated in previous proceedings, the incentives
8 that are paid to our employees are an integral part of the employee compensation
9 package. Base salary and incentive compensation together are a comprehensive
10 package designed to attract and retain highly motivated employees. The
11 Company chooses to put a portion of employee compensation at risk in the form
12 of incentives so that employees will have a strong motivation and financial link to
13 the established goals of the Company. The goals that are established are goals
14 that are deemed as being important to the operations of the Company, and
15 therefore also benefit customers as welL. In the Company's plan reflected in the
16 test year, the goals included employee related goals for employee safety and
17 diversity; customer related goals of customer satisfaction and reliability; and
18 financial related goals of operations and maintenance spending, capital spending,
19 and utility earnings. The employee and customer goals are clearly beneficial and
20 should be recoverable in rates; they include meeting all quarterly certification
21 deadlines and passing all external Department of Transportation compliance
22 audits, as well as meeting customer satisfaction levels. The financial goals also
23 benefit customers, as controlling spending reduces the need for rate increases, and
13 1 clearly if utility earnings are increased, this also reduces the need for rate
2 increases. All the goals are combined in a "Balanced Scorecard" so that the
3 financial goals will not be achieved by reducing customer service and reliability.
4 The Company must attract and retain skiled employees in a competitive labor
5 market. It does this by offering an overall competitive compensation package. If
6 the Company were to eliminate the incentive pay component from its
7 compensation package, to remain competitive, it would have to replace it with
8 additional base pay. The additional base pay would be a legitimate expense and
9 would be required to be recovered in rates. However, without the incentive
10 component, it will be more difficult or more expensive to reach the goals in the
11 "Balanced Scorecard," and customers would be worse off.
12 In addition, in Docket No. 05-304, the Commission expressed concern that
13 the achievement of payouts had financial triggers. The Company's 2006 plan for
14 management employees no longer has financial triggers. If the Company meets
15 its goals concerning safety and customer service and reliability, there will be a
16 payout even if the financial triggers are not achieved.
17 22. Q: Please address the issue of Construction Work in Prol!ress and how this was 18 treated in the Company's fiinl!?
19 A: The Company's calculation of rate base includes an adjustment to account
20 for the balance of Construction Work in Progress (CWIP) during the test period. 21 As a general ratemaking matter, the Company believes that it is appropriate to
22 recognize CWIP in rate base. In addition, as Mr. Driggs and Mr. Yon Steuben
23 show, virtually all of the projects that were included in rate base during the test
14 1 year are now in plant in service and are serving customers. Thus there is no
2 legitimate reason to exclude these amounts from rate base in this case.
3 23. Q: Would you please summarize the key points of your testimony?
4 A: The Company's gas business is not recovering the costs of providing safe
5 and reliable service in its current rates. The Company needs to increase base
6 revenues by $14,967,412 to bring the amount of revenue collected to the
7 appropriate level to continue to provide safe and reliable service to customers.
8 The Company continues to invest in the system and recovery of those costs is
9 essential to the financial health of the gas business. The Company's proposal to
10 establish a revenue stabilization mechanism is an appropriate step that will result
11 in more stable bills for customers, provide a consistent stream of revenues to the
12 Company, and align the interests of the Company with those of its customers.
13 24. Q: Does this conclude your testimony? 14 A: Yes, it does.
15 Schedule MEB-1 Statement of Occupational and Educational History and Qualifications
MARK E. BROWNING
Dr. Browning received a Bachelor of Science Degree in
Economics from the Massachusetts Institute of Technology in
1974 and a Doctor of Philosophy in Economics in 1982 from
the University of Michigan. From 1978-1982, he was a Lecturer/Assistant Professor at the University of Illinois.
In July i 982, Dr. Browning joined the Potomac Electric Power Company as a Senior Analyst in the Load Forecast
Department. In this position, he worked on the Company IS analyses of the local economy. In March 1983, he was promoted to Load Forecast Supervisor and was responsible for
developing the Company i s long term sales and peak demand
forecasts, as well as the Company i s long term economic forecasts. In September 1984, Dr. Browning was promoted to Manager of the Load Forecast Department. In this position he supervised the development of the Company's forecasts of sales, peak demand, and the local economy.
In May of 1995, Dr. Browning was promoted to Manager,
Rates and Regulatory Practices. In this position, he is responsible for the Company's Load Forecast Department, Cost
Allocation Department, Rate Design Department and Revenue
Analysis Department. In January 1999, Dr. Browning was promoted to General Manager Rates and Regulatory Practices. In January, 2004 Dr. Browning was named Director
- Rates and Technical Services. Dr. Browning was a member of the PJM Load Analysis
Subcommittee from 1984 through 1995 and was chairman of the committee from 1985 through 1987. He was also a member of the North American Electric Reliability Council i s Load Forecasting Working Group from 1985-1987. In the fall of 1992, Dr. Browning served as a member of the Maryland Governor i s Revenue Advisory Council. Dr. Browning is a member of the Edison Electric Institute i s Economic Regulation and Competition Committee. Dr. Browning has previously testified before the District of Columbia Public Service Commission and the
Maryland Public Service Commission concerning the Company IS load forecasts, cost of service studies and rate proposals.
2 1 DELMARVA POWER & LIGHT COMPANY 2 TESTIMONY OF CHARLES L. DRIGGS
3 BEFORE THE DELAWARE PUBLIC SERVICE COMMISSION 4 CONCERNING AN INCREASE IN GAS BASE RATES
5 PSC DOCKET NO. 06- 6 1. Q: Please state your name. position and address.
7 A: Charles L. Driggs, Manager, Gas Operations & Planning with Delmarva
8 Power & Light's (Delmarva or the Company) Gas Delivery business area. My
9 business address is 630 Martin Luther King Boulevard, PO Box 231, Mail Stop
10 88MK62, Wilmington Delaware 19899-0231.
11 2. Q: What are your responsibilties in your role as Manal!er of Gas Operations &
12 Planninl!?
13 A: Managerial responsibilities in the Gas Delivery business line are shared
14 between the Manager oÎ Engineering, the Manager oÎ Construction and
15 Maintenance and my position, Manager of Gas Operations & Planning. My area
16 of responsibility includes day-to-day delivery of gas to customers for the
17 regulated utility business of Delmarva. This is performed with the support of a
18 group of engineers, analysts and technicians who are operating and maintaining
19 both the distribution system and a liquefied natural gas plant, planing capacity
20 needs for gas facilities, tracking and balancing usage for customers served under
21 our transportation gas tariffs, preparing the annual sales and revenue forecasts and
22 budgets, and tracking monthly sales and revenue against the budget. My role also
23 includes oversight of portions of the revenue process on behalf of the Gas
24 Delivery management team, security and emergency planning for gas operations
25 facilities, and gas business planning.
1 1 3. Q: What is your educational and professional backl!round and experience?
2 A. My education includes a B.S. in Mechanical Engineering from Rochester
3 Institute of Technology, an MBA with a Finance concentration from Loyola
4 College of Baltimore, and some course work for a PhD program in Economics
5 and Finance at the University of Delaware, along with a variety of professional
6 seminars.
7 My professional background involves:
8 · thirteen years in consulting work for utility, industrial and governent /
9 defense clients primarily relating to energy use, electric energy generation &
10 storage with an emphasis on alternative energy, large scale underground gas or
11 oil storage, and energy resource planning;
12 · over three years in the Delmarva corporate plannng department, evaluating
13 what is today called distributed generation, as well as designing and evaluating
14 demand-side management programs and overall resource strategy for the
15 electric utility business and managing the corporate research and development
16 program;
17 · four years as renewable energy project development manager in the former
18 Delmara Capital Investments subsidiary; and
19 · over thirteen years spent in several positions within the present Gas Delivery
20 business of Delmarva; I assumed my present position as Manager of Gas
21 Operations & Planning on December 1, 1996.
22 I am also a registered professional engineer in Delaware and Maryland, and hold
23 an inactive registration in New York State.
2 1 4. Q: Have you previously testifed before the Delaware Public Service
2 Commission?
3 A: Yes, I provided written and verbal testimony before the Delaware Public
4 Service Commission in cases dealing with the
5 · Challenge 2000 integrated (electric) resource planning effort and the
6 development of electric Rate X (Dockets 87-4 and 87-6)
7 · Gas retail choice pilot program (Dockets 98-524 and 00-315)
8 · Gas Cost Recovery Dockets in 2000 (00-463F), 2004 (04-301F), and 2005
9 (05-312F), and
10 . Gas Base Rate case in 2003 (Docket No. 03-127).
11 5. Q: What is the purpose of your testimony?
12 A: The purpose of my testimony is to support the Company's Application for
13 an increase in Gas Base Rates. I am the business witness and wil provide a brief
14 overview of the Company's Gas Delivery business line. I wil discuss a varety of
15 issues facing our business, the sales forecast used in developing proposed rates,
16 and certain adjustments and Minimum Filing Requirements ("MFR").
17 6. Q: How is your testimony structured?
18 A: My testimony is structured in four parts:
19 i. Overview
20 II. Minimum Filing Requirements and Adjustments
21 III. Other Issues
22 IV. Conclusion
23
3 1 I. Overview
2 7. Q: Please provide a brief overview of the Company's Gas Business and its 3 system.
4 A: As of the end of the April 2005 - March 2006 test period, Delmarva
5 Power served about 120,000 natural gas customers, of which approximately
6 111,000 were served under residential rates. Our delivery system incorporated
7 some 1866 miles of gas mains fed by three primary gate stations and five minor
8 stations or pipeline taps. Over ninety percent of the Company's natural customers
9 rely upon our distribution system to heat their homes and businesses.
10 8. Q: Please outlne the sil!nificant chanl!es in the Company's Gas Delivery 11 business since the last base rate fiinl!. 12 A: Since the last base rate case was filed before the Commission in 2003, the
13 Delmarva Gas delivery business has been managing a mix of new or expanded
14 challenges potentially impacting the cost of providing service, service reliability,
15 and the ability of the Company to recover its costs. The issues are as follows: 16 Changing Customer Mix 17 Changing Regional Economy 18 Changing Usage Per Customer
19 Compliance with the Pipeline Safety Improvement Act of 2002
20 Compliance with Changing Environmental Regulations
21 Renewal of an Aging Workforce
22 Redevelopment of Delaware Infrastructure 23 Ensurng System Reliability and Security
4 1 I will address each of these issues in turn.
2 9. Q: Please explain the impact of chanl!es in the rel!ional econom,:.
3 A: The Delmarva service area is the northern two-thirds of New Castle
4 County, including the segment of the county between Boyd's Corner Road and
5 the C&D CanaL. The gas service area was adequately served for many years from
6 two primary gate stations at the north end of the county. The pattern of growth in
7 population and commercial activity during the 1990's generally involved some
8 infill in the established communities in the northern reaches of the county,
9 combined with a continuous march of residential, commercial and light industrial
10 development southwards towards the C&D CanaL. Passage of a significantly
11 revised New Castle County code resulted in a significant slowdown of
12 development in most of New Castle County, except for the Middletown - Odessa
13 - Townsend (MOT) area. Since Delmarva does not serve natural gas to the MOT
14 area, much of that growth is outside the Company's service terrtory, falling
15 within the service terrtory of Chesapeake Utilities.
16 Growth was very strong in the Gas Delivery business line during the early
17 1990's, but that trend had already subsided when the Company filed the last base
18 rate case in 2003. Sales growth rates since 2003 have continued to be much lower
19 than rates experienced in the 1990's, reflecting a market that has matured within
20 the franchise terrtory. Long term sales growth expectations in the Delmarva gas
21 service area were on the order of one to two percent per year at the time of the last
22 base rate fiing in 2003, and that long term expectation remains the same today.
23 A portion of sales growth is expected to come from increased usage by existing
5 1 commercial customers, and the remainder wil likely come from net new
2 residential and commercial customer additions. The slowing of sales growth in
3 recent years was shown in the 2003 base rate filing, and Schedule CLD-1 shows
4 more recent experience.
5 Changes in energy costs in recent years and competitive pressures have
6 particularly affected large customers, particularly those running energy-intensive
7 manufacturing or process operations selling into world commodity markets.
8 Many of these customers do qualify for transportation service. These customers
9 are candid that they are searching for savings, sometimes via more frequent
10 movement between bundled service and transportation tariff rates. Unbundling
11 and deregulation initiatives that began in the late 1980's resulted in many of
12 Delmarva's large customers switching to transportation service in the 1990's.
13 Some large customers now have their energy managed by third-parties in ongoing
14 efforts to stay competitive within their segments of the economy. However,
15 despite these efforts, a significant number of the Company's large customers have
16 disappeared or significantly cut back their operations in recent years.
17 10. Q: What is the result of these trends with larl!e customers?
18 A: The customers served under the larger usage tariff rates are transforming
19 into a mix that is less dominated by heavy industry and more represented by
20 service company offce complexes and light manufacturing. This brings a change
21 in the hourly patterns of gas delivery across the system. Service companies and
22 light manufacturing are less likely to be 24 hour per day, 7 day per week
23 operations than are heavy industrial companies, and commercial and light-
6 1 industrial operations tend to be less energy-intensive. These changes are visible,
2 as evidenced by declining load factor.
3 System load factor (the ratio of average daily load to annual peak daily
4 load) in 2001 was a relatively typical 39%. System load factor fell significantly
5 in subsequent years and held steady for calendar years 2004 and 2005 at 31 %
6 (see Schedule CLD-2). While these figures are unadjusted for weather, 2004 and
7 2005 were only 3% and 1 % warmer than 30 year average weather, respectively;
8 incorporation of a weather adjustment would have no material effect on the result
9 of the comparison. Such significant changes in load factor imply a significant
10 change in the demands placed upon the distribution system, and in its operation.
11 Load factor changes could be driven by either a rise in peak load or a reduction in
12 sales, or both. The change, in this instance, is driven primarily by loss of sales to
13 process-oriented industrial customers, as well as by partial replacement of those
14 lost sales by more weather sensitive customers.
15 Changing patterns of commercial and industrial customer locations on the
16 system and customer usage, combined with continued growth in residential
17 customer count and declining residential customer usage, wil continue to
18 . alter the dynamics of the delivery system
19 . impact where gas supply is brought into the system to maintain reliability
20 of service to all customers
21 . require investment in the delivery system to ensure reliability of service to
22 all customers.
7 1 The ongoing change in the mix of customers and the variety of their usage
2 patterns has to be accommodated in daily operations. Further, the physical
3 facilities of the system must be capable of serving the full range of customer
4 loads, or else some customers may experience loss of service. If the physical
5 facilities cannot currently accommodate future customer loads patterns, they must
6 be revised to maintain service reliability to all customers.
7 11. Q: Please explain how chanl!inl! customer mix impacts the operatinl! system and 8 service reliabilty.
9 A: The mix between industrial, commercial and residential customers loads is
10 changing, and wil continue to change. These customers are differentiated into
11 different tariff rates due to relative scale of annual sales. Usage patterns tend to
12 be heavily weather sensitive in the residential class, a mix of moderately-to-
13 severely weather sensitive in the general gas rate class, and become more diverse
14 among customers in the medium volume and large volume classes. Customers
15 engaged in energy intensive manufacturing tend to exhibit usage patterns that are 16 little affected by seasonal weather or day of the week when compared to
17 residential customer patterns. As energy intensive users with relatively steady
18 loads disappear from the mix, the rate of change of customer loads becomes more
19 rapid in cold weather, and the absolute range of the swing between peak winter
20 loads and loads on a warm summer night becomes larger. This wider range of
21 loads has to be accommodated in the sizing of metering and pressure and flow
22 control equipment at gate stations, the sizing of hundreds of existing pressure
23 regulating stations in the system, and possibly even replacement of sections of
8 1 pipe with a larger size, to accommodate the likely range of flow rates needed to
2 maintain the minimum delivery pressures that support reliable service. The
3 project requirements are reviewed annually, and when changes are needed, they
4 can be costly. Failure to recognize changing customer usage patterns in an area of
5 the delivery system before those changes push a regulator beyond its limits can
6 result in an outage for customers that might last days, or worse.
7 In addition, the mix of bundled service customers (for whom the Company
8 buys gas supplies) and transportation customers (who buy their own supplies) is
9 also changing, which impacts the procurement of gas and the associated costs of
10 procurement and interstate pipeline shipment that are separately addressed in Gas
11 Cost Rate proceedings.
12 The share of annual delivered volumes brought through the local
13 distribution system to Transportation rate customers peaked at nearly forty-three
14 percent of Gas Delivery's anual throughput in 2000, as shown in Schedule CLD-
15 1. Transportation volumes have been declining since, primarily due to:
16 . shrnkage in the number of industrial customers
17 . cutbacks in industrial customer operations or process energy usage
18 · decisions by large customers to switch back to bundled service
19 The decline in transportation volume, as shown in Schedule CLD-1,
20 exceeds the overall decline in combined sales volume since 2000. Transportation
21 volumes are predominantly delivered to heavy industrial operations with large
22 loads. Sales to bundled service customers also have been declining over the last
23 three years of rising commodity costs, indicating that all segments of the New
9 1 Castle County economy are altering their needs for natural gas such that sales
2 growth rates are negative, whereas customer growth rates remain small but
3 positive.
4 Delmara's gas delivery business saw more than five milion MCF in
5 anual sales to individual large customers disappear in the 2001-2005 period.
6 These lost sales were to customers served under bundled firm service, firm
7 transportation, and interrptible transportation rates. The customers either went
8 out of business, or significantly cut back their operations for the foreseeable
9 future. Such losses of business activity have a ripple-effect through any local
10 economy by affecting other companies and organizations providing goods and
11 services to those closed or reduced-scale businesses. In some instances, this is
12 known with certainty to have resulted in changes in sales to other customers. The
13 rate of loss of large customer sales appears to have stabilized over the past two
14 years, with only one loss during 2006 (an interrptible transportation customer
15 lost just before this filing, and too late to be included in the Schedules) among this
16 size class of customer.
17 Continued additions of new residential and commercial customers and
18 growth in sales to small and medium size commercial customers have partially
19 offset the industrial sales losses.
20 Peak loads on the system are also reduced compared to historical
21 experience, but the replacement of lost industrial sales by more characteristically
22 weather sensitive residential and commercial sales wil tend to cause peak loads to
23 grow somewhat more rapidly than the overall rate of recovery in sales. The
10 1 combined effect of the changing sales mix and loss of large customers is to make
2 prediction of design day peak loads somewhat more diffcult.
3 These changes in customer mix could also be expected to change the
4 relative allocation of the costs of providing service to customer classes, as
5 demonstrated elsewhere in this rate fiing by Mr. Normand.
6 The combined effect of shrnkage of the industrial base in the county
7 (specifically among large users of natural gas), expansion of service and light
8 industrial customer segment sales, and continued modest residential growth, is
9 two-fold:
10 . scattered investments or adjustments that reconfigure the distribution
11 system to ensure reliability of service to all customers are needed;
12 . inequities tend to arise in the coverage of operating costs by rate class
13 members, to the extent that rates no longer reflect ratable share of costs of
14 service.
15
16 12. Q: SO far. YOU have focused upon chanl!es in commercial and industrial 17 customer classes. Have there been any impacts seen in the residential
18 customer classes as a result of chanl!inl! economic conditions? 19 A: Yes, residential customers have been affected as welL. A significant
20 influence on customer sales has been the relatively rapid growth in commodity 21 energy prices over the last three years. Overall, Delaware's residents and 22 businesses, some of them gas customers of the Company, have all seen their
23 energy costs rise significantly for motor fuels, process energy, home heating fuels,
11 1 and electricity. These cost increases have impacted household budgets and
2 residential customers are rationally responding by reducing their energy
3 consumption.
4 Delmarva has seen significant reductions in average gas usage per
5 residential customer, net of weather effects, during the most recent three year
6 period of escalating energy prices. This impact significantly accelerates a long
7 term downward trend in usage per residential customer. The long term trend was
8 attributable to general energy efficiency improvements in new building
9 construction, building renovations, and more adoption of more energy efficient
10 gas appliances. The long term impact seen over the period 1990-2003 was, for
11 example, a net compound decline rate on the order of one-half percent per year.
12 Usage per residential space heat customer, net of weather, has shown much
13 greater declines during the last two winters. Over this same period, the Gas
14 Commodity Rate for these customers rose 71 %, in concert with significant
15 increases in gasoline and other energy prices. Dr. Farney discusses these findings
16 in greater detail in his testimony.
17 Delmarva has not seen such significant price-driven effects among
18 residential customer usage in many years. Price elasticity effects were not
19 considered particularly significant in projecting future sales to residential and
20 small commercial customers in the past, but that is no longer the case with the
21 volatility of natural gas commodity prices and the exceptional level of commodity
22 market prices.
12 1 It is reasonable to expect, absent any clear evidence of sustained falling
2 energy prices, that customers will continue to cut back their energy use to match
3 their income as long as prices remain significantly higher than historical
4 expenence. Replacement of appliances and investment in improved
5 weatherization of building structures will tend to make those sales reductions
6 permanent.
7 The implications of such cutbacks on the Company are straightforward:
8 . Costs expended by the Company to operate and maintain the distribution
9 system, and the need for recovery of past investment in the system, are
10 little affected by actual sales volume because most of those expenses are
11 fixed annual costs.
12 . The revenue generated to cover those costs is determined by volumes of
13 gas sold.
14 . As residential customers further reduce their usage in response to high
15 commodity prices, it becomes increasingly less likely that the Company
16 can recover the costs of both maintaining reliable service and compliance
17 with all regulations
18 . Absent rate increases, returns on investment eventually will not justify
19 any further capital investment.
20 . Residential or commercial class contributions to peak loads that are either
21 declining or growing more rapidly than in other classes will also tend to
22 shift the burden of costs of service between classes.
13 1 Absent rate increases or another solution that resolves the issue of fixed cost
2 recovery, declining usage per customer places the interests of the Company at
3 odds with the interests of residential customers acting to reduce their bils to more
4 manageable levels in a period of rising prices.
5 13. Q: Please explain why the Gas Delivery business line has a hil!h proportion of
6 tixed costs.
7 A: Gas distribution utilities are heavily regulated. More so than electric
8 utilities. The difference is primarily attributable to Federal regulations created by
9 implementation of the Pipeline Safety Act of 1978, and its subsequent
10 amendments. Many of the activities of the Gas Delivery business are required to
11 be carred out on a continuous basis regardless of the level of sales to customers.
12 Strict interpretation of the Federal Pipeline Safety regulations in conjunction with
13 Company operating standards could require the Company to continue to maintain
14 all pipelines, swap out and test meters, maintain corrosion protection, perform
15 leak survey work, mark out gas lines for excavators, repair leaks, maintain
16 perpetual records of all present and past pipe in the system, staff a call center to
17 take gas odor calls, and man the control room - even if only one active customer
18 remained on the system. The Federal regulations require maintaining the same
19 standard of operations, maintenance and recordkeeping as long as a pipeline is in
20 service (has natural gas within it), and require a focus upon improving operating
21 safety regardless of the number of active customers on the system or the volume
22 of gas supplied to any customers.
23 14. Q: Is there any prospect of these requirements becominl! more flexible?
14 1 A: Not in the foreseeable future. Passage of the Federal Pipeline Safety
2 Improvement Act of 2002 (PSIA '02) significantly expanded the monitoring,
3 investigation, maintenance, operating and reporting requirements for gas pipeline
4 operators. Furthermore, reauthorization of the Pipeline Safety Act is pending this
5 year in Congress. Additional changes in regulatory requirements are likely to be
6 incorporated in the reauthorization legislation. Upward pressure on operating
7 costs exists, and it is expected to increase.
8 At the time of the last base rate case fiing, the direction of regulatory
9 implementation efforts for PSIA '02 was unclear for many of the initiatives
10 required by that Act. Ultimate regulatory direction remains to be finalized on
11 some issues, and is obscured somewhat by the debate over reauthorization.
12 However, a variety of activities are now mandated, expectations have been clearly
13 laid out, and the remaining unresolved initiatives continue to evolve towards their
14 final form according to prescribed timetables. Compliance actions are either in
15 development or in place within Delmarva's gas delivery operating areas.
16 Compliance programs have been implemented or are under development
17 for the Transmission (pipeline) Integrty Management, Distribution (system)
18 Integrty Management, Operator Qualification (worker competency certification),
19 (control room) Controller Certification, Damage Prevention, and Public Education
20 to comply with final or developing regulations issued by the US DOT / Pipeline
21 and Hazardous Material Safety Administration (PHMSA) in implementing
22 programs required by PSIA '02. Ongoing development of some program needs
23 wil require further expenditure of resources to assess the new regulatory
15 1 requirements as they are developed, define any needed changes to existing
2 practices or policies, and implement compliance programs. Expenditures to date
3 have involved both new capital investment and new operating expenses, incurrng
4 permanent additions to anual expenses. The full extent of new investment and
5 annual expenses needed to comply with regulations that are still in development is
6 not fully defined yet, but Schedule CLD-3 shows the Company's current known
7 or estimated costs of compliance. Thus, a portion of the Company's PSIA '02
8 compliance costs are known and measurable. Other compliance costs may need
9 to appear in an additional filing in the near future, when those less defined
10 requirements are measurable.
11 15. Q: Are there other rel!ulatory compliance expenditures that add to fixed costs?
12 A: Yes. Environmental compliance requirements and the associated costs 13 have expanded since the 2003 rate case. These costs involve a mix of fixed 14 expenditures for training, auditing, and periodic reporting, and variable 15 expenditures that are driven by volumes of wastes handled. Increases in 16 environmental compliance expenditures have primarily been driven by a)
17 regulations in New Castle County and the City of Wilmington that have required
18 changes in the handling of mildly contaminated water pumped out of utility
19 facilities, along with b) new state requirements regarding collection, testing,
20 temporary storage, disposal, documentation, and training of employees involved
21 in handling and disposal of a variety of wastes normally generated by a gas utility 22 business. Other environmental compliance costs associated with cleanup of
23 specific manufactured gas plant properties are the subject of the Company's
16 1 annual Environmental Surcharge Rider filing made in parallel with this case, and
2 are not reflected in this filing.
3 Compliance costs are also being incurred to satisfy Commission Order
4 6328 from Docket No. 02-231, and prior Commission orders, dealing with
5 customer metering. Since September 2002, or the end of the test year in the last
6 base rate case, the Company has invested over $8 millon in 54,000 metering
7 installations. Approximately half of these, requiring $2.3 millon in investment,
8 were remote index meter installations to enable readings where routine access is
9 difficult. The remaining $5.7 milion of investment went for over 21,000 periodic
10 meter replacements, and metering for 6,311 new customers.
11 Still more compliance costs are associated with changes in OSHA
12 requirements, changes in SEC reporting requirements, and the requirements of
13 other regulatory agencies, but, with the exception of Sarbanes-Oxley compliance,
14 costs have been comparatively stable in these areas.
15 16. Q: Are there other fixed expenditures tarl!eted at maintaininl! operational safety
16 or service reliabilty?
17 A: Yes. One example is not a significant cost driver in the filing, but wil
18 become a more significant issue over the next few years.
19 The Company faces the same problem of replacing aging Baby Boomer
20 Generation workers as faced by many other companies in various industries
21 throughout the regional and national economy. This is a particularly diffcult
22 problem to work through when tryng to control cost growth. An approach of
23 allowing no increase in operating costs tends to place future reliability of service
17 1 at risk. Protecting service reliability through hiring personnel to be trained by
2 highly knowledgeable senior employees approaching retirement tends to increase
3 customer costs at a time when other customer costs are also rising. Delmarva is
4 attempting to reach a balance between these conflcting needs by incurrng some
5 additional operating costs to promote transfer of knowledge and maintain service
6 reliability as senior personnel leave their positions in the gas delivery operating
7 area. Orderly transfer of knowledge will reduce operating risks affecting service 8 reliability.
9 17. Q: If tixed costs are risinl!. base load sales are fallnl!. and customer usal!e in
10 l!eneral is fallnl!. can the Company promote l!as usal!e to increase sales and 11 spread their tixed costs across more sales volume? 12 A. Gas local distribution companies typically compete with a variety of 13 energy sources for the heating and industrial process markets. In the residential
14 and small commercial markets, competitive fuels may include fuel oil or propane
15 distributed by local dealers, wood available for purchase or cutting on the
16 customer's property, solar installations on the customer's residence or business, or
17 resistance electric, electric heat pump, or geothermal heat pump installations
18 supported by the local electric utility. In some markets, the gas utility is allowed
19 to advertise and is allowed to offer promotional incentives to prospective
20 customers. The general objective in these situations is to maximize sales through 21 the plant investment to spread fixed costs over as large a sales base as can
22 practically be achieved, thus lowering rates to natural gas customers.
18 1 Marketing gas process technology to industrial users has been a focus of
2 some portions of the natural gas industry for some time. The diffculty of
3 identifying opportunities and the expense of development is generally beyond the
4 scope of what the Company is willng to undertake, and any inquiries that may
5 come from customers are generally referred to outside experts in the industr.
6 The Delaware Commission does not encourage promotions by its gas
7 utilities, and has implemented revenue tests to limit investment by the distribution
8 utility when adding a customer. In some situations revenue tests are beneficial to
9 the utility in limiting investment, but the actual intent of the revenue test from the 10 regulatory view is to avoid situations where existing customers subsidize
11 customers joining the system. The imposition of revenue tests certainly assists
12 Delmara's unegulated competition, as they are free to use price and/or appliance
13 promotions and long-term contracts to acquire sales growth. However, when 14 natural gas sales are declining and localized capacity may be available,
15 restrictions on adding any sales which could spread fixed costs and lower rates to 16 all customers may not be in the interests of customers. 17 Since promotion generally is not an option in the residential and small
18 commercial market, and achieving meaningful success at industrial process
19 marketing is diffcult, the Company has little choice but to seek rate increases to 20 achieve cost recovery.
21 18. Q. You listed "Redevelopment of Delaware Infrastructure" as an issue - what is 22 this issue?
19 1 A. Since reaching Settlement in the last base rate case, Docket No. 03-127,
2 there have been a varety of state-sponsored projects to improve the highway
3 system and redevelop underutilized areas to support population and commercial
4 growth, particularly near Wilmington. Delmarva has had to make investments to
5 relocate existing gas mains and services. Examples of significant projects in
6 recent years are the Lancaster Pike / DE 41 reconstruction through Hockessin, the
7 Concord Pike / US 202 & Foulk Road intersection reconstruction, the 1-95 &
8 Churchman's Road bridge replacement, and the Riverfront Development
9 Corporation's efforts in Wilmington. Portions of this work have been performed
10 under reimbursement agreements. Reimbursed costs are not borne directly by
11 Delmarva's gas customers and are excluded from rate base and the request for a
12 rate increase in this filing. Delmarva's unreimbursed investments to
13 accommodate these societal needs and maintain safe, reliable service typically do
14 not produce any new revenue. However, they are important if Delmarva is to
15 continue to provide safe and reliable service to customers in both areas unaffected
16 by construction and the areas where infrastructure is being improved or
17 undergoing redevelopment.
18 Delaware law has provided Delmarva and other utilities the option of
19 using state right-of-ways for location of facilities without charge for many years.
20 In exchange for using public right of way, the Company takes on the obligation of
21 relocating facilities in the event that State reconstruction of a roadway requires
22 relocation. Under most circumstances, the arrangement has reduced the
23 Company's costs and that benefit has passed to customers through lower rates.
20 1 However, the Company has faced multiple relocations of the same facilities
2 between rate cases on occasion in the past, such that the investment in relocation
3 of plant at those sites is both made and retired in the period between cases. The
4 impact is reduced by the mass accounting approach to recording utility plant, but
5 the net effect is that a portion of those short-lived investments is never recovered
6 through rates. That is a risk to stockholders that does not exist in the case where it
7 was necessary to pay for the right to locate Company facilities on private land.
8 Delmarva has worked with DelDOT to moderate this risk, with the result being a
9 change to state law that required DelDOT to reimburse the impacted utility in the
10 event that a second relocation is required within ten years of the initial relocation.
11 19. Q. What efforts and new investment are onl!oinl!. in addition to what you've
12 already described. to ensure system reliabilty and security?
13 A. As discussed by Dr. Browning in his testimony, the Gas Delivery Business
14 has seen a significant increase in plant investment since the last rate case. There 15 have been a significant number of small system improvements, often in
16 conjunction with Company support of DelDoT highway improvement projects,
17 but there have only a few noteworthy improvements for distribution system
18 reliability in this three year time period. One improvement made at the Hockessin
19 Gate Station involved replacement of the pipeline gas heater for the Williams /
20 Transco interconnection that had been installed in the 1990's. Replacement was
21 warranted due to failure of the heater structure and severe internal corrosion of the
22 combustion system.
21 1 The decreases in usage seen among residential and industrial customers
2 have been exhibited by our small commercial customers as well, but expected
3 growth in commercial customer count and sales is greater than with other
4 customer classes. The changing mix of customer loads has implications on a
5 system designed to meet the prior mix of loads.
6 Planing studies examine the change in system loads and load patterns and
7 determine how system loading changes on design day as a result. These studies
8 also factor in any changes to the distribution system as a result of pipe relocation
9 or replacement projects performed to support infrastructure improvements by
10 others or to meet new regulatory requirements. The net impact on system
11 operating conditions is determined both for the coming year as well as by
12 projection of trends three years and ten years out. System improvements needed
13 to accommodate changing system conditions without loss of service reliability are
14 identified, evaluated, and added to the construction plan. The construction plan is
15 re-evaluated with each annual planning cycle, and projects needed to support
16 reliability may appear and disappear as customers join or leave the system.
17 Physical and cyber security incidents can also impact service reliability,
18 and the Company has examined exposures in this area, expending resources both
19 during and since the Test Period. These efforts have included a corporate wide
20 Cyber Security Penetration Test, internal reviews and revisions of security
21 policies and procedures at company facilities, and upgrading of physical security
22 at gas distribution system facilities. These efforts are ongoing at this time, and
23 more investment and expenditures are expected over the rate effective period.
22 1 The most significant impact of widespread development and economic
2 prosperity in New Castle County, particularly in the southern reaches of the
3 county, was the requirement to move ever increasing volumes of gas from the
4 northern terrtorial border with Pennsylvania all the way across the system to the
5 southern reaches of the terrtory. The Company built a new supply point nearer
6 the southern portion of the service area to ensure service reliability prior to the
7 last base rate case in 2003. No additional supply points have been either needed
8 or built since the 2003 rate case, but Delmara has entered into an agreement to
9 expand service at two existing major gate stations. Service reliability issues under
10 changing operating conditions at one of these stations have required a limited
11 reconstruction of a portion of the facility in 2006 to ensure service reliability to all
12 customers downstream of the station.
13 Weather has always been a key driver of Gas Delivery financial
14 performance, but until 2004 and 2005, weather events in other regions had not
15 threatened service reliability to Delmarva's gas distribution customers. Hurrcane
16 Ivan in 2004, and Hurrcanes Katrina and Rita in 2005, demonstrated that security
17 of gas supply to our region is partially dependent upon weather events in other
18 areas, as well as other possible natural or man-made disasters. As a result of
19 Katrina and Rita, for eleven days in September 2005, a large portion of the
20 Company's system gas supply was provided by either diverting gas intended for
21 injection into winter storage or withdrawals of gas already in storage. Delmarva's
22 normal suppliers in the Gulf Coast were unable to either produce or ship their gas
23 through the interstate pipeline system during that period. The diversion had
23 1 negligible effect on adequacy of storage volumes in the winter period, but did
2 illustrate that upstream reliability issues needed to be considered in planning
3 efforts to a greater degree than previously recognized.
4 Delmarva is therefore involved in several efforts to be better positioned to
5 either minimize disruptive effects, or to provide an alternative source of supply in
6 the event of an interstate pipeline supply disruption that threatens service
7 reliability in the region in which we live.
8 To this end, the Company saw both economic value for customers and
9 opportunities for improved supply reliability in a project under development by
10 Eastern Shore Natural Gas to bring gas up the peninsula from the south. The
11 Company therefore subscribed to the project in the FERC Open Season process.
12 The costs of this project, if successfully completed, wil be recovered through the
13 annual GCR filing process, and are not discussed further in this filing. The
14 impact of the project from a reliability aspect is to reduce exposure to a "common
15 mode failure" type of risk with the interstate pipelines supplying the service
16 terrtory from the north.
17 Delmarva also actively participated in development of a national mutual
18 aid agreement by the American Gas Association, working with the American
19 Public Gas Association and the Southern Gas Association, subsequent to the
20 devastation created by Hurrcanes Katrina and Rita, and the Company was an
21 early signatory to the national agreement. Additional parallel efforts have been
22 underway to institute greater coordination and planning in the Mid-Atlantic region
23 among gas distribution utilities in mutual aid situations, with Delmara leading
24 1 this initiative. And finally, Delmarva's parent company, PHI, has upgraded its
2 emergency response planning and support system to incorporate Incident
3 Management / Incident Command principles, and the Gas Business management
4 team is working to integrate existing Gas Emergency Plan practices within that
5 corporate framework while continuing to satisfy the requirements of Pipeline
6 Safety regulations.
7 These efforts all have a central focus of maintaining both service
8 reliability to customers and compliance with state and federal regulations, and all
9 involve expending additional time and resources to improve our ability to
10 maintain service reliability under an expanded range of contingencies since
11 Docket No. 03-127.
12 20. Q: Has the company made any sil!nifcant capital improvements that specifically
13 addressed reliabilty or safety?
14 A: Yes. During the period 2003 - 2006, the Company continued pipeline
15 surveillance and improvement programs, and expanded compliance efforts to
16 implement new requirements resulting from the Pipeline Safety Improvement Act
17 of2002.
18 Delmarva's construction activity, including both pipe replacement /
19 renewal and new business installations, resulted in an increase in installed plastic
20 pipe of 88 miles, and reductions in cast iron pipe and steel pipe of 6 miles and 1
21 mile respectively. These figures neither reflect the miles of pipe relocated in
22 kind, nor pipe replaced in kind to repair damaged mains or services. Since the
23 close of the Test Year in Docket No. 03-127, the Company has added 3,131 (net)
25 1 service lines serving customers, but installed more than this net figure in
2 providing service renewals and relocations.
3 As already noted, the Company worked with DelDOT to improve major
4 highway corrdors, with DelDOT's goal being improved reliability of
5 transportation routes in serving the needs of residents and visitors in Delaware. In
6 some instances, coordination of major gas system reliability improvement projects
7 with DelDOT's project schedules resulted in either delay or acceleration of
8 planned gas system improvements. In other instances, no gas system
9 improvements were warranted within a DelDOT project, and otherwise sound gas
10 mains and associated service lines had to be replaced to accommodate DelDOT
11 road reconstruction. As DelDOT activity has been extensive during the past three
12 years, coordination remains a major effort and considerable investment continues
13 to be required on the Company's part. That investment is reflected in the
14 additions to rate base shown on the schedules filed with this application.
15
16 II. Minimum Filng Requirements and Adjustments
17 18 21. Q: Please list the Minimum Filnl! ReQuirements that YOU are sponsorinl!.
19 A: I am supporting the following fiing requirements:
20 . Schedule B - System Map
21 . Schedule B - Gas Utility Plant Capacity in Service
22 . Schedule 3B - Deferred Cost Accounting
23 22. Q: Please list the adjustments that YOU wil sponsor in this proceedinl!.
26 1 A: As explained further by Mr. Yon Steuben, the Company has included a
2 series of adjustments to test period revenues, expenses and rate base, some of
3 which I am sponsoring. The adjustments I am sponsoring are needed to better
4 reflect expectations of revenues and expenses in the rate effective period. I will
5 provide a rationale for their inclusion as known and reasonably measurable 6 events. 7 Pre-Cost Adiustments
8 23. Q: Please discuss the Non-Firm Marl!in Sharinl! Adjustment.
9 A: The Settlement Agreement in Docket no. 95-44 authorized the Company
10 to retain 20% of any non-firm margins related to interrptible transportation, FPS 11 services, storage services, off-system sales, and capacity release transactions 12 beginning on April 1, 1996. The other 80% of these non-firm margins are
13 returned directly to customers through the operation of the gas fuel clause
14 mechanism (the "GCR"). The Settlement Agreement also provided that all non-
15 gas revenues, except transition charges, from any customers who switched from a 16 firm to an non-firm service subsequent to April 1, 1996 shall be retained by the
17 Company in their entirety until a future proceeding in which base rates are reset. 18 The Settlement Agreement in Docket No. 00-314 amended the sharing
19 mechanism for off-system sales and capacity release transactions by setting a $1.7 20 milion threshold which must be reached before margins are shared in the
21 proportions agreed upon in Docket No. 95-44. Prior to reaching the $1.7 milion
22 threshold, all margins from off-system sales and capacity release are returned to
23 customers through the GCR.
27 1 The Non-Firm Margin Sharing Adjustment removes margins from the
2 Company's "above-the-line" income that are subject to the margin sharing
3 agreement resulting from Docket no. 95-44. This is authorized by Section ILF.5
4 of the Phase II Settlement Agreement dated December 14, 1995, which states:
5 "During the period that the margin sharing mechanism described
6 herein remains in effect, revenues received from non-frm services,
7 including revenues retained by the Company, shall be excluded from
8 the computation of base revenues (revenue requirement) ".
9 Margins realized from provision of non-firm services to customers who
1 0 switched from a firm to a non-firm service subsequent to April 1, 1996 are
11 included as "above-the-line" income, and are not subject to the Non-Firm Margin
12 Sharing Adjustment. 13 Pro-Forma Earnings Adjustments
14 24. Q: Please address the Pro-forma earninl!s adjustments that yOU are sponsorinl!.
15 A: I am sponsoring two pro-forma earnings adjustments, as shown on
16 Schedule WMV-23 in Mr. VonSteuben's testimony:
17 · Adjustment No. 11 - Incremental 0 & M Expense Adjustment
18 · Adjustment No. 12 - Compliance Costs Adjustment
19 Adjustment No. 11 captures the increase operations and maintenance
20 expense that is associated with unusual cost escalation that has been experienced, 21 and wil continue to impact the Gas Delivery business line. Two items in
22 particular will impact expenses in the rate effective period, as shown in Schedule
23 CLD-3, page 1, under the heading of "Other Inflationary Increases". The Fleet
28 1 Vehicle operating expense increase reflects the impact of higher fuel and
2 lubricants prices. The Facilities - Finished & Unfinished Space increase reflects
3 the impact of an increase in costs associated with offce space assigned to the gas 4 business.
5 25. Q: Please describe Adjustment No. 12.
6 The Company cannot describe the specific actions being taken to improve
7 physical and cyber-security, for obvious reasons. Federal guidelines described in
8 the filing for Docket No. 03-127 made it clear that these issues are not to be
9 treated openly. The Company, however, continues to minimize these non-
10 revenue producing costs while achieving reasonable compliance with the
11 guidelines. Delmarva believes that the costs incurred in this effort primarily 12 protect reliability of service to customers. The security measures already
13 implemented tend to reduce the likelihood of extended and damaging loss of
14 facilities serving customers, and Delmara continues to periodically evaluate the 15 adequacy of security measures. 16 I briefly described current Pipeline Safety initiatives in the US Congress
17 and within the US Department of Transportation earlier in this testimony. The
18 Pipeline Safety Improvement Act of 2002 (PSIA '02) required implementation of
19 a national "Pipeline Integrty Management Program", and regulations mandated
20 development of such a program for each company covered by the legislation
21 before the end of 2004. Delmarva Power is a covered company and did comply,
22 incurrng ongoing anual expense.
29 1 Ongoing efforts within the Pipeline & Hazardous Materials Safety
2 Administration (PHMSA) are now focused upon expanding Integrty
3 Management into a distribution level program and defining the associated
4 regulation needs, with emphasis on improving Damage Prevention ("Miss Utility"
5 in Delaware) programs in particular. The PHMSA efforts may also result in
6 regulations requiring "voluntary" installation of excess flow valves, which
7 Delmarva already supports.
8 The Company instituted compliance efforts with the transmission level
9 Integrity Management regulations. That initiative requires anual O&M
10 expenditures, and wil require additional capital investment. The second page of
11 Schedule CLD-3 presents the anticipated impacts of current and future Integrty
12 Management (transmission & distribution) activities by Delmarva in the format
13 being used by the industry steering committee for the Distribution Integrty
14 Management Program initiative. The incremental costs shown justified the
15 addition of two personnel noted under the heading of "Pipeline Integrty
16 Management Expense Fully Loaded" in the second block of costs shown on the
17 first page of Schedule CLD-3. One of these engineers is currently on-board, and
18 an offer has been extended to a second person as of the time of this filing.
19 Operator Qualification programs intended to verify competency of persons
20 working on the pipeline system are also under study for expansion of minimum
21 requirements, and a new standard, AS ME B31-Q, is in final stages of
22 development. The Company is working both to upgrade its programs in
23 anticipation of the new expectations and to improve the cost-effectiveness of
30 1 existing programs. The expenditure shown in the Operator Qualification section
2 on page 1 of Schedule CLD-3 is for an anual license for intranet softare to
3 replace the training software package that had been developed internally. The
4 new package offers features that provide the tracking and accessibility needed to
5 verify as well as achieve compliance.
6 The Company can and has identified reasonably certain, known and
7 measurable expenses that wil occur in 2006 and beyond, and has estimated the
8 magnitude of their impact. The Company has included an estimate of these costs
9 in Earings Adjustment No. 12 as shown on Schedule WMV- 23.
10 11 III - Other Issues
12 26. Q: Please explain the nature of l!as CWIP addressed by Mr. Von Steuben. 13 A: The Gas Delivery business line typically engages in a large number of 14 relatively small projects with durations of weeks to months in any given
15 constrction year. As a result, outstanding Construction Work In Progress tends
16 to be a relatively small percentage of capital expenditures. Many of the projects
17 completed by Gas Delivery also are not eligible for accrual of AFUDC as they do
18 not meet the minimum cost threshold of$100,000.
19 The closing adjustment reflects an assessment of the likelihood of the
20 CWIP balances being closed to plant before completion of this rate case. As of
21 the time of fiing, $6,982,000 of the 13 month average $7.256 milion CWIP 22 balance that existed on the books as of March 31, 2006 has been closed to plant. 23 A significant portion of the remaining balance should also be closed to plant by
31 1 September 30, 2006, and the Company will provide a status update to the parties
2 in this Docket in a subsequent filing with the Commission.
3 iv -- Conclusion
4 27. Q: Please summarize your testimony.
5 A: The passage of time since the last base rate case has brought a variety of
6 cost pressures and placed new demands upon operating resources within the Gas
7 Delivery business line of the Company. These include numerous new or
8 expanded requirements in maintaining compliance with all federal, state and local
9 laws and regulations, necessitating both new investment and increased operating
10 costs. Customer mix is also changing, requiring analysis of changing needs and
11 potential investment to ensure service reliability. Rising, and more volatile, costs
12 for the gas commodity have resulted in reduced consumption by customers at the
13 same time, adding to the difficulty of covering the costs of providing safe, reliable
14 service.
15 28. Q: Does this conclude your testimony?
16 A: Yes, it does.
32 Schedule CLD-i PSC Docket 06-
Comparison of Actual Gas Delivery Sales By Year Firm / Bundled Firm Interruptible Transport Yr!yr Sales Transport Transport Combined % Growt, %
1998 14,23°,776 4,860,157 2,480,741 21,571,674 34.0% 1999 14,912,175 5,290,992 3,258,187 23,461,354 36.4% 8.8% 2000 14,723,919 6,468,568 4,610,959 25,803,446 42.9% 10.0% 2001 14,471,644 4,918,303 3,374,584 22,764,531 36.4% -11.8% 2002 14,662,560 5,231,948 2,919,268 22,813,776 35.7% 0.2% 2003 16,085,539 3,961,992 2,811,062 22,858,593 29.6% 0.2% 2004 15,397,568 4,213,094 1,988,790 21,599,452 28.7% -5.5% 2005 15,044,624 4,009,066 1,597,560 20,651,250 27.1% -4.4%
compound annual 1998-2002 0.7% growth rates 2002-2005 -3.3% Schedw. ../J - 2 psc Dockèt06- ____
Gas System Load Factor Unadjusted for Weather
Peak Deliveiy Day Operatig Fir Tuesday, Januaiy 18th Load Factor Combined Avg / Peak MCF As%Of MCF As%Of Calendar Year 2005 Throughput T ora T ora
Fir Sales 150,138 86% 14,983,983 73% 27%1 Fir Trasporttion 20,331 31% 12% 4,009,745 19% 54% FPS & Interrptible Trasporttion 4,648 3% 1,596,881 8% 94% Deliveiy Throughput 175,117 100% 20,590,609 100% 32%
Peak Deliveiy Day Thurday, Januaiy 15th Calendar Year 2004 Throughput T ota T ota Fir Sales 152,101 88% 15,092,730 71% 27°1 Fir Traporttion 31% 20,361 12% 4,226,082 20% FPS & Interrptible Trasporttion 57% 46 0% 1,975,842 9% 11768% Deliveiy Throughput 172,508 100% 21,294,654 100% 34%
Peak Deliveiy Day Thurday, Janua 23rd Calendar Year 2003 Throughput Fir Sales 155,796 83% 17,110,118 72% 3°°1 Fir Trasporttion 32% 24,875 13% 4,311,031 18% 47% FPS & Interrptible Trasporttion 7,507 4% 2,462,976 10% 90% Deliveiy Throughput 188,178 100% 23,884,125 100% 35%
Peak Deliveiy Day Thurday, December 3rd Calendar Year 2002 Throughput Fir Sales 118,765 78% 12,146,408 60% 28°1 Fir Trasporttion 34% 21,890 14% 5,237,762 26% 66% FPS & Interrptible Trasporttion 12,583 8% 2,899,765 14% 63% Deliveiy Throughput 153,238 100% 20,283,935 100% 36%
Peak Deliveiy Day Thurday, Febni 22nd Calendar Year 2001 Throughput Fir Sales 122,652 80% 15,781,086 68% 35°1 Fir Trasporttion 39% 22,372 15% 4,910,064 21% 60% FPS & Interrptible Trasporttion 8,179 5% 2,512,051 11% 84% Deliveiy Throughput 153,203 100% 23,203,201 100% 41% Schedule CLD - 3 page 10f2 PSC Docket 06 - vas Delivery Estimates of Expenses Not Captured in Test Year
WM Adiustment 11
Other Inflationary increases Fleet Vehicle Operating Expense Increase 1,168,020 1,506,540 Facilties - Finished & Unfinished Space Increase 338,520 587,333 778,002 190,669 Other 1,755,353 2,284,542 529,189
WM Adiustment 12 Employee Additions - Not Captured in Test Year - Fully Loaded
% O&M in O&M- Employee Name ATP Total Hours Capital Split O&M Hours O&M Impact
Opns - Control Room Engineer 1 $103 1,915 100% 1,915 $ 197,245 Opns - Supervsing Engineer 2 $90 945.5 100% 946 85,095 Field Supervsor 3 $83 1,635 60% 981 81,423
Total Employee Adds $ 363,763 Pipeline Integrity Management Expense - Fully Loaded Capital O&M * Engineering new hire 4 * Engineering new hire 5 * 5225722 Gas Public Safety Education see attached 1M worksheet * 5229001 Pipeline Integrity Management LDC page 2 * Joint Pipeline
Tota PIM 1,000,000 421,760
SCADA system support In Test Year Actal Variance $ $ Diagnostic support servces 7,020 14,040 7,020 Total Telvent 14,040 7,020 PHMSA Operator Qualification -- CBT System Replacement Annual maintenance fee 20,000 20,000
Total OQ 20,000 20,000 Symantec - Cyber Security / Gas Systems Penetration Test & Remediation Test Performed May 20 Allocation To Gas Delivery To Be Detennined
Total Cyber Security
Total Adjustments $ 812,543 notes: * See attached 1M Worksheet 1 New position as of April 2006 -- upgrade of control room technical support 2 Position open for 6 mos of test period -- candidate has an offer as of Aug '06 3 New position as of April 2006 -- knowledge transfer prior to a retirement 4 New hire as of August 2006 -- Pipeline Integrity Management support & PHMSA compliance 5 New hire -- knowledge transfer prior to a retirement, codes & standards support -- candidate has an offer as of Aug '06
GJM 07/20/0¡¡ Schedule CLD - 3 page 2 of2 PSC Docket 06 - ¡Implications of Distribution Integrity Management Plan Rules . Seven Identified Elements for Distribution Integrity Management Programs 1 Develop and Implement a Written Integrity Management Plan 2 Know Infrastructure 3 Identify Threats, both existing and of Potential Future Importance 4 Assess and Prioritize Risks 5 Identify and Implement appropriate Measures to Mitigate Risks 6 Measure Performance, Monitor results, and Evaluate Effectiveness of Program, Making Changes Where Needed 7 Periodically Report a Limited Set of Performance Measures to the Regulator
ROUf!h Incremental Cost Estimate ofDIMP Rule In 2006 Dollars Large Operators ( Unit Annual Cost One Time ANAL INCREMENTAL ;: 12,000 svcs) Unit Tve Cost Units 2007 - 2010 Cost O&M CAPITAL Preparing the Engineerinl! $ 82 240 $ la,680 $ '\9,360 $ 19,680 $ - DlMP plan. Consultant $ 5,000 $ i;o,ooo $ 5,000 $ - Documenting Eni!:neerinl! $ 95 ¿l00 $ '\8,000 $ - $ '\8,000 $ - the DIM process Field $ 8:~ 1000 $ 83,000 $ 8,300 $ - Assessing Kelvin Obara $ 82 ¿l80 $ 39,::60 $ 39,360 $ - threats Gas $ 83 80 $ 6,640 $ - $ - Integrating data Engineering $ 82 800 $ 6i;,600 $ 6i;,600 $ - Consultant 25,000 - / estimating / $ $ $ - Field $ 8'\ 41,.i;00 - prioritizing risks 500 $ $ $ - Risk Model $ 11;,000 $ ~oo,ooo $ 1!),000 $ - Data Gathering Engineerinl! $ 82 200 $ 1.'i,000 $ 15,000 $ - & Performance Field $ 83 $ 15,000 $ 11;,000 $ - Managing / Engineerinl! $ 82 240 $ 15,000 $ 15,000 $ - reducing the Field $ 83 $ ii;,OOO $ ii;,OOO $ - Gas Public $ 65,000 $ 13.000 Pipeline $ 62.000 12,400 £\..;YN: ...:..\:,;~ SUBTOTAL $ 2'76. "lLlO $ - field acton in areas of concern Increasin actions done under Part 1 2: 1866 miles of mam' -120 000 servce hnes . 120000 customers Cast Iron Main $ 3,000,000 $ $ Unprotected $ 2,000,000 $ $ Steel Main Protected Steel $ $ $ Plastic Main $ $ $ Steel Servce $ $ $ Co er Servce $ $ $ Plastic Servce $ $ $ Excess Flow $ $ S stem $ $ $ 500,000 Increasing Preventive Measures $ 500,000 $ 500,000 Gathering $ 1 ,760 $ 1 ,760 $ Distribution data and $ 8 ,000 performance metrics $ 8,300 $ 250 000 $ $ $ $ $ $ SUBTOTAL $ $ 1 000 000 TOTAL $ $ 1,000,000 Schedule CLD- 4 PSC Docket 06 -
O&M Summary Comparison Delmarva Power & Light - Gas Delivery Docket 03-127 Test Year vs. Test Year ending March 31, 2006
Updated: May 30, 2006 - 5 year History
10/01 - 09/02 04/05 - 03/06 Actual Actual 05 vs 02 05 vs 02 Operating Expenses Gas Meter Work 388 1,381 993 256.0% Gas Leak Survey 525 901 376 71.7% Regulator/Gate Operations 539 771 232 42.9% Operate Gas Delivery System 417 637 221 52.9% Operate LNG Facility 501 694 193 38.4% Gas System Mapping 119 281 162 136.0% Gas Meter Reading 1,011 1,171 160 15.8% Gas Utility Locates 790 943 154 19.5% Offce & Record Operation 372 520 148 39.8% Operate Gas LDC 4,700 7,468 2,768 58.9% Gas System Equipment Maintenance 692 1,163 471 68.0% Gas Valve Work 707 1,101 394 55.7% LNG Preventive Maint. 518 760 242 46.8% Gas CP Work 441 665 224 50.7% Maintain Gas LDC 3,106 4,374 1,268 40.8% Gas Emergencies 2,973 2,852 (121 ) -4.1% Gas Planning 35 120 86 248.1% Gas Energy 1,497 953 (544) -36.4% Other 1,142 646 (496) -43.5% Gas Processes (includes Gas Residual) 13,452 16,413 2,961 22.0% Manage Customer Relationships 487 459 (28) -5.7% Manage Revenue 5,773 4,937 (837) -14.5% Operate The System 208 130 (77) -37.3% Manage Customer & Distribution Construct 164 225 62 37.5% Manage System Maintenance 1,166 125 (1,040) -89.2% One Time Environmental Adjustments (1,000) 0 1,000 -100.0% Other (893) 107 1,000 0.0% Core Electric Processes 5,904 5,983 79 1.3% Support Processes 492 548 56 11.3% Other Support & High Level Costs 252 1,236 984 390.8% Corp Services Non-Process 2,920 3,065 145 5.0% Other 901 31 (870) -96.5% Shared Service Allocations 4,565 4,880 315 6.9% Total Direct O&M (excluding Enviromental Adj.) 23,921 27,276 3,355 14.0% Depreciation and Amortization 9,554 11,707 2,153 22.5% Taxes-Other than Income Taxes 1,783 0 (1,783) -100.0% Property Tax Expense 1,922 2,512 589 30.7% Taxes-Gross Receipts Tax 0 2,572 2,572 Taxes other than Income Taxes 3,705 5,084 1,379 37.2% Total Operating Expenses (excluding Enviromental Adj.) 37,180 44,067 6,887 18.5%
Customers 114,1550 120,466 I 6,311 5.5% I 1 DELMARV A POWER & LIGHT COMPANY 2 TESTIMONY OF KATHLEEN A. WHITE
3 BEFORE THE DELAWARE PUBLIC SERVICE COMMISSION 4 CONCERNING AN INCREASE IN GAS BASE RATES 5 DOCKET NO. 06-
6 1. Q: Please state your name. address and position.
7 A: Kathleen A. White, 630 Martin Luther King Jr. Boulevard, Wilmington,
8 Delaware 19899. I serve as Assistant Controller for PEPCO Holdings, Inc.
9 ("PHI") and its utility operating companies, which includes Delmarva Power and
10 Light ("DPL"). DPL's operations include the regulated gas operations serving
11 Delaware.
12 2. Q: What are your responsibilties in your role as Assistant Controller for PHI?
13 A: I direct and monitor the PHI costing model, general accounting functions,
14 compliance with Cost Accounting Manual and Service Agreements to support
15 internal and external financial results, which includes reporting requirements for
16 the Service Company, under the Public Utility Holding Company Act of 2005
17 ("PUHCA05"), and compliance with the Company's cost allocation procedures
18 within the Service Agreement previously filed under the repealed Public Utility
19 Holding Company Act of 1935 ("PUHCA35").
20 3. Q: What is your educational and professional backl!round?
21 A. I received my undergraduate degree and MS in accounting from the
22 University of Delaware and I am a Certified Public Accountant. I have held
23 various financial accounting and managerial positions at PHI, Conectiv and DPL
1 1 since 1989. Prior to joining DPL, I was an instructor for financial and
2 managerial accounting classes at the University of Delaware.
3 4. Q: Have you previously testifed before the Delaware Public Service
4 Commission?
5 A: Yes. I previously filed testimony before the Delaware Public Service
6 Commission in Docket No. 05-304.
7 5. Q: What is the purpose of your testimony?
8 A: I am supporting the actual amounts recorded in DPL's ("Company or the
9 Company's") books and records for the test period, which is the twelve months,
10 ended March 31, 2006. The test period cost data for the gas business was
11 supplied to Mr. V onSteuben for use in determining revenue requirements.
12 6. Q: Please describe how your testimony is structured.
13 A: My testimony is outlined below:
14 VII. Supporting Filing Requirements.
15 VIII. Books and Records.
16 ix. Company's Cost Management Structure.
17 7. O. Please list the minl! requirements that yOU are sponsorinl!.
18 A: i am supporting the following Minimum Filing Requirements:
19 Filed supportinl! documents listed below:
20 · Anual Report to the Commission (FERC Form No .2) for 2005.
21 · March 2006 FERC Form 3-Q.
22 · PHI and DPL SEC Form 10K for 2005.
23 · PHI and DPL SEC March 2006 10Q.
2 1 · Proxy Statement dated March 31 2006.
2 · Prospectus dated March 31 2006.
3 Supportinl! documents included in this fiinl!:
4 · Schedule No. 3D - Executive Compensation.
5 . Schedule No.3N - AFUDC.
6 8. Q: Does the Company maintain its books and records in accordance with the
7 FERC's Uniform System of Accounts and l!enerallv accepted accountinl!
8 principles?
9 A: Yes.
10 9. Q: Are the Company's books and records audited by an independent
11 accountinl! firm?
12 A: Yes. PricewaterhouseCoopers LLP ("PWC"), an independent public
13 accounting firm, audited the Company's financial statements included in the
14 2005 DPL 10-K, March 2006 10-Q and the 2005 FERC Form Nos. 1 and 2.
15 A copy of the audit reports issued by PWC, related to the Company's 2005
16 10-K and March 2006 10-Q financial statements and FERC Form 1 and 2, are
17 attached as Schedule KA W -1. As shown on Schedule KA W -1, PWC
18 concluded that, based on its audit work, the Company's financial statements
19 conform with generally accepted accounting principles ("GAA") and the
20 requirements of the FERC's Uniform System of Accounts in all material
21 respects.
3 1 10. Q: What is the source of the unadjusted test period data supplied to Mr.
2 V onSteuben for use in the determininl! revenue reQuirements in this
3 minl!?
4 A: The source of the unadjusted test period data for the twelve months ended
5 March 31, 2006, is the books and records of the Company reported under its
6 FERC accounting system. As discussed earlier, this data was supplied to Mr.
7 V onSteuben for use in determining revenue requirements.
8 11. Q: Please briefly discuss the Company's orl!anizational structure.
9 A: PHI continues to use a legal entity structure in segregating costs for its
10 operations, which was previously required under the repealed PUHCA35. In
11 addition PHI also has a service company, which provides mutual services to
12 the operating companies. This service company provides a variety of support
13 services to PHI subsidiaries, including DPL, which are in compliance with a
14 service agreement fied under PUHCA35. These support services, included in
15 the service agreement, includes allocation methods for costs related to services
16 that benefit multiple subsidiaries.
17 12. Q: Please discuss the Company's cost manal!ement principle.
18 A: The Company adheres to a cost management principle, in which the
19 underlying principle is the use of a fully distributed cost assignent. The
20 process is accomplished by assigning costs to regulated and nonregulated
21 companies through: 1) direct assignent of employees and related costs
22 within the operating companies; 2) direct charging of service company costs or
23 incidental cross-company charges to operating companies using standard rates,
4 1 known as activity type prices which reflect full costs, and; 3) allocation of
2 certain shared service costs benefiting multiple companies that cannot be
3 specifically direct charged.
4 13. Q: Has this Commission previously approved the Company's cost mana2ement
5 principles?
6 A: Yes. The Commission has previously issued Orders regarding the
7 Company's cost management principles. As to the transfer of services between
8 the service company and the regulated utility, the Commission requires that fully
9 allocated cost principles be used.
10 14. Q: Does the Company have any requirements by this Commission rel!ardinl!
11 transactions with the Service Company?
12 A: Yes. The Company is required to file an annual affliate transaction report
13 detailing the affliate transactions, including the service company, of DPL. 14 Further these transactions have been audited by an independent auditor for
15 compliance with the cost principles documented in the Company's CAM.
16 These audits are conducted every third year and reports have been issued for the 17 years 1997, 1998,2001 and 2004. These reports, and anual transactions of
18 DPL, have been previously submitted to the Commission. Attached as Schedule
19 KA W-2 are the independent audit reports for the years 1997, 1998, 2001 and 20 2004.
21 15. Q: Does this conclude your testimony? 22 A: Yes it does.
5 Schedule KAW-1 Page 1 of 2 Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors of Pep co Holdings, Inc.:
We have completed integrated audits of Pep co Holdings, Inc.'s 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31,2005, and an audit of its 2003 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Consolidated financial statements and financial statement schedules
In our opinion, the consolidated financial statements listed in the accompanying index, present fairly, in all material respects, the financial position of Pep co Holdings, Inc. and its subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15(a)(2) present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As disclosed in Note 15 to the consolidated financial statements, the Company restated its financial statements as of December 31, 2004 and for the years ended December 31, 2004 and 2003.
Internal control over financial reporting
Also, in our opinion, management's assessment, included in Management's Report on Internal Control Over Financial Reporting appearing under Item 8, that the Company maintained effective internal control over financial reporting as of December 31, 2005 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control- Integrated Framework issued by the COSO. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management's assessment and on the effectiveness of the Company's internal control over financial reporting based on our audit. We conducted our
156 Schedule KAW-1 Page 2 of 2 audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Thòse standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
PricewaterhouseCoopers LLP Washington, D.C. March 13,2006
157 Schedule KAW-2 Page 1 of 4 Deloitl & Touche Deloitte &Touche LLP Telephone: (973) 683-7000 o Two Hilton Court Facsimile: (973) 683-7459 P.O. Box 319 Parsippany, New Jersey 07054..319
INDEPENDENT AUDITORS' REPORT
Delmarva Power & Light Company
We have audited the accompanying Schedules ofNonregulated Expenses and Affiliate Transactions of Delmarva Power & Light Company (the "Company") for the year ended December 31, 1997 (the "Schedules"). These Schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on the Schedules based on our audit.
We conducted our audit in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the Schedules are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the Schedules. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall Schedules' presentation. We believe that our audit provides a reasonable basis for our opinion.
We have been informed that the Company prepared the Schedules presented herein in order to comply
with the Public Service Commission of The State of Delaware Order Number 4768. These Schedules, which present the costs incurred by the Company on behalf of its nonregulated business lines and its nonregulated subsidiaries and the costs incurred by the Company's nonregulated business lines and nonregulated subsidiares on behalf of the Company for the year ended December 3 i, 1997, have been prepared in accordance with procedures set forth in the Company's Cost Accounting Manual, as descnbed in Note 2, which is a basis of accounting other than generally accepted accounting principles.
In our opinion, the Schedules referred to above present fairly, in all material respects, the costs incurred by the Company, on behalf of its nonregulated business lines and its nonregulated subsidiaries, and the cost incurred by the Company's nonregulated business lines and nonregulated subsidiaries, on behalf of the Company for the year ended December 31, 1997, on the basis of accounting set forth in the Company's Cost Accounting ManuaL.
This report is intended solely for the information and use of the Board of Directors and management of the Company, the Public Service Commission of The State of Delaware, the Division of The Public Advocate, the Delawàre Association of Alternative Energy Providers, and The Delaware Allance For Fair Competition, and should not be used for any other purpose. ~ ~ ~~ \.t' June 30, 1999
Deoitl Touch Tohmalsu Schedule KAW-2. Page 2 of 4 Deloitl & Touche Deloitte &Touche lLP Telephone: (973) 683-7000 o Two Hilton Court Facsimile: (973) 683-7459 P.O. Box 319 Parsippany, New Jersey 07054-0319
INDEPENDENT AUDITORS' REPORT
Delmarva Power & Light Company
We have audited the accompanying Schedules of Non regulated Expenses and Affliate Transactions of Delmarva Power & Light Company (the "Company") for the year ended December 3 i, 1998 (the "Schedules"). These Schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on the Schedules based on our audit.
We conducted our audit in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the Schedules are free of material missttement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the Schedules. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall Schedules' presentation. We believe that our audit provides a reasonable basis for our opinion.
We have been informed that the Company prepared the Schedules presented herein in order to comply
with the Public Service Commission of The State of Delaware Order Number 4768. These Schedules, which present the costs incurred by the Company on behalf of its nonregulated business lines and affliates and the costs incurred by the Company's nonregulated business lines and affiiates on behalf of the Company for the year ended December 3 i, 1998, have been prepared in accordance with procedures set forth in the Company's Cost Accounting Manual, as described in Note 2, which is a basis of accounting other than generally accepted accounting principles.
In our opinion, the Schedules referred to above present fairly, in all material respects, the costs incurred by the Company, on behalf of its nonregulated business lines and affliates, and the costs incurred by the Company's nonregulated business lines and affiliates, on behalf ofthe Company for the year ended December 3 i, i 998, on the basis of accounting set forth in the Company's Cost Accounting Manual.
This report is intended solely for the informatiçn and use of the Board of Directors and management of
the Company, the Public Service Commission of The State of Delaware, the Division of The Public Advocate, the Delaware Association of Alternative Energy Providers, and The Delaware Alliance For ~air Competition, and should not be used for any other purpse. ~ ., \~ \.t'
August 5, 1999
Deloitle Touche Tohmatsu Delaine & Touche LLP Schedule Two Hilton Court KAW-2 P.o. Box 319 Page 3 of 4 Parsppany, New Jersey 07054~319
Tel: (973) 683-7000 Faic(9731683-7459 www.deoitte.com Deloitte & Touche
INDEPENDENT AUDITORS' REPORT
Delmaa Power & Light Company
We have audited the accompanying Schedules of Nonregulated Expenses and Affliate Transactions of Delmaa Power & Light Company (the ..Company") for the yea ended December 31, 2001 (the "Scheules"). These Schedules ar th reponsibilty of the Company's maagement Our resibility is to express an opinion on the Scheules bas on our audit.
We conducte our audit in accordance with auditing stadards generally accepted in the United States of Amrica. Those stadards require that we plan and pedonn the audit to obtn reasonable assurance about whether the Schedules ar free of material nñsstatement. An audit includes examining, on a test basis, evidence supportng th amounts and disclosures in the Schedules. An audit also includes assesing the accounting principles use and signficant estimates made by magement, as well as evaluating the overal Scheules' presentation. We believe tht our audit provides a reaonable bais for our opinion.
We have ben infor that the Company prepar the Schedules presented herein in order to comply with th Public Service Commssion of The State of Delaware, Order Numbr 4768, as amended by Orer Number 549. Thes Schedules, which present the costs incurred by the Company on behalf of its nonregulated business lines and affliates and the costs incur by the Company's nonregulated buiness lines and affiiates on behaf of the Company for the yea ended December 31. 200 1, have ben prepar in accordance with procedur set fort in the Company's Cost Accountig Manual
("CAM"), as desribe in Note 2, which is a bais of accounting other tha generally accepted accunting principles.
hi our opinion, the Scheules referr to above present fairly, in all material respets, the costs incur by the Compy, on behalf of its nonregulated business lines and affliates, and the costs incured by th Company's nonrgulated business lines and afliates, on behalf of the Company for the yea ended Dember 31,2001, on the basis of accounting set fort in the Company's CAi\l referred to above.
Tlus report is intended solely for the informtion and use of the Board of Directors and management of
th Compy, the Public Serice Commssion of The State of Delaware and the Division of Th Public Advocate,~'\~U-f and should not be use for any othr purose. May 31, 2002
Deloitte Touche Tohmatsu Schedule KAW-2 PRCIW7fRHOUSf(PERS i Page 4 of 4
PricewaterhouseCoopers LLP ¡ 751 Pinnacle Drive Report of Independent Auditors Mclean VA 22102-3811 Telephone (703) 918 3000 Facsimile (703) 918 3100
To the Board of Directors of Delmarva Power & Light Company:
We have audited the accompanying Summary Schedule of Affliate Transactions between Delmarva Power & Light Company and Pepco Holdings Inc.' s Operating Subsidiaries and Service Company (the "Schedule") of Delmarva Power & Light Company (the "Company") for the year ended December 31,2004. The Schedule is the responsibility of the Company's management. Our responsibilty is to express an opinion on the Schedule based on our audit.
We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the Schedule is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the Schedule. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the Schedule. We believe that our audit provides a reasonable basis for our opinion.
As described in Note 2, the Schedule was prepared pursuant to the Company's Cost Accounting
Manual and the Public Service Commission of the State of Delaware ("PSC") Order No. 5469, issued in conjunction with PSC Docket No. 99-582, in force as of August 21,2000, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America. The Schedule was prepared for the purpose of complying with those requi~ements and is not intended to be a complete presentation of the Company's financial statements.
In our opinion, the Schedule referred to above, presents fairly, in all material respects, the information required to be set forth therein, for the year ended December 3 1,2004, in accordance with the Company's Costs Accounting Manual and the PSC Order No. 5469 issued in . conjunction with PSC Docket No. 99-582, in force as of August 2 1,2000.
Ou.r audit was conducted for the purpose of forming an opinion on the Schedule taken as a whole. The Supplemental Schedules included in Appendix I are presented for purposes of additional analysis and are not a required part of the Schedule. Such information has been subjected to the auditing procedures applied in the audit of the Schedule and, in our opinion, is fairly stated in all material respects in relation to the Schedule taken as a whole.
This report is intended solely for the information and use of the Company and the PSC and is not intended to be and should not be used by anyone other than these specified parties.
!/~jll~fJ~ lLfJ December 8, 2005 DELMARVA POWER & LIGHT COMPANY
2 TESTIMONY OF W. MICHAEL VON STEUBEN
3 BEFORE THE DELAWARE PUBLIC SERVICE COMMISSION
4 CONCERNING AN INCREASE IN GAS BASE RATES
5 PSC DOCKET NO. 06-
6 7 1. Q: Please state your name and position. and business address.
8 A: My name is W. Michael VonSteuben, Manager, Revenue Requirements in
9 the Regulatory Affairs Department, Pepco Holdings Inc. My business address is
10 401 Eagle Run Road, Newark, DE 19714.
11 2. Q: Please state your educational backl!round and professional Qualifications.
12 A: I received a Bachelor of Science Degree in Business Administration from
13 the University of Delaware in 1976. In December 1978, I joined Delmarva in the
14 Payroll section of the Accounting Department. In 1980, I was promoted into the
15 Plant Accounting Department with responsibility related to the book and tax
16 treatment regarding the Company's utility plant.
17 In September 1984, I was promoted to Senior Analyst in the Regulatory
18 Practice Department. I was promoted to Staff Analyst in June 1987 and to
19 Supervisor in March 1998. I was designated a Senior Regulatory leader in 2000
20 and promoted to my current position in November 2004. My responsibilities
21 include the coordination of revenue requirement determinations in Delaware,
22 Maryland, Virginia, New Jersey and the District of Columbia as well as
23 coordinating various other regulatory compliance matters. 3. Q: Have YOU previously presented testimony before a rel!ulatory body?
2 A: Yes, I have. I have previously presented testimony as a witness before the
3 Delaware Public Service Commission ("DPSC") in Docket Nos. 93-12SF, 94-22,
4 97-394F, 99-674, 01-S08, 02-231, 03-127 and 05-304 as well as presenting
5 testimony before the Maryland Public Service Commission and the Virginia State
6 Corporation Commission.
7 4. Q: What is the purpose of your testimony?
8 A: The purpose of my testimony is to present the per book Earnings and Rate
9 Base for use in this filing along with the quantification and support of certain
10 adjustments. I summarize the adjustments being proposed by all the witnesses as
11 well as the revenue requirement request of the Company. I sponsor certain
12 adjustments which are described in my testimony. I also sponsor certain
13 Minimum Filing Requirements ("MFR"). In addition, I am also sponsoring
14 Schedules WMV 1 - 24. These schedules and the MFR were prepared under my
15 direction and/or supervision. 16 FILING REQUIREMENTS
17 5. Q: What MFR are yoU sponsorinl!?
18 A: I am sponsoring the following fiing requirements:
19 Schedule C Elements of Rate Increase
20 Schedule 1 Financial Summary
21 Schedule 2 Rate Base Summary
22 Schedule 2A Used and Useful Utility Plant
23 Schedule 2B Intangible Assets
2 Schedule 2C Accumulated Depreciation and Amortization
2 & Customer Advances
3 Schedule 2D Accumulated Deferred Income Taxes &
4 Investment Tax Credit
5 Schedule 2E Materials & Supplies and Investor Supplied
6 Cash Working Capital
7 Schedule 2F Other Elements of Property and CWIP
8 Schedule 3 Summary of Net Operating Income
9 Schedule 3A, Page 1 Revenues
10 Schedule 3B Operating Expenses
11 Schedule 3C Payroll Costs
12 Schedule 3E Sales Promotion and Advertising
13 Schedule 3F Contributions
14 Schedule 3G Association Dues
15 Schedule 3H Rate Case Expense
16 Schedule 31 Income Taxes and Provisions
17 Schedule 3J Federal and State Income Taxes
18 Schedule 3K Deferred Federal and State Income Taxes
19 Schedule 3L Investment Tax Credit
20 Schedule 3M Other Taxes
21 Schedule 30 Other Income
22 Schedule 5 Revenue Conversion Factor
3 6. Q: What is the test period presented in this fiinl!?
2 A: As Dr. Browning notes in his testimony, the test period utilized in the
3 fiing is the twelve months ending March 2006.
4 7. Q: Is this a reasonable test period?
5 A: Yes, the test period, which compnses the latest twelve month period
6 available for cost of service, allows for this case to be processed in a manner that
7 is as effcient as possible. With the adjustments presented in this filing, this test
8 period is a matching of revenues, expenses and rate base consistent with
9 Commission regulations and represents a reasonable basis for establishing the
10 Company's revenue requirements for the rate effective period.
11 8. Q: Please describe the development of per books rate base and earninl!s.
12 A: The rate base for the test period is comprised of actual average balances
13 and is summarized on Schedule No.2 of the MFR. Earnings are shown on
14 Schedule No.3 of the MFR. 15 The source of the data for the test period was the Company's actual books
16 and records provided by Ms. White. Detail for the test period can be found in the
17 workpapers contained in Book 3 that accompanies the Company's application.
18 Earings include Operating Revenues less Operating Expense and Interest
19 on Customer Deposits plus AFUDC, as shown on Schedule WMV-1. A number
20 of pre-cost study adjustments have been made to the books to allow the resulting
21 cost of service returns by class to be representative for rate design purposes. As
22 discussed in Mr. Janocha's testimony, the basis for designing rates was the class
23 returns resulting from the cost of service. The pre-cost study adjustments that I
4 have listed on Schedule WMV -1 will be utilized for the resulting class returns for
2 this rate design. The pre-cost study earnings adjustments are detailed on Schedule
3 WMV -1. This schedule also lists the supporting witness for each of these pre-cost
4 study adjustments. I am supporting the following pre-cost study adjustments:
5 · Removal of the effects of Environmental Surcharge Revenues and Expenses;
6 · Remove the effect of the TETCO pipeline;
7 · Removal of the effects of Utility Tax;
8 · Removal of the effects of Un billed Revenues;
9 · Removal of the effects of Gas Cost Recovery Fuel Revenues and Expenses;
10 · Restatement of the Investment Tax Credits and Federal and State Deferred
11 Income Taxes; and
12 · Removal of prior period Income Taxes;
13 The per book rate base is detailed by component on Schedule WMV-2.
14 Additions to rate base are included as they represent investment in facilities used
15 to serve the Company's customers as well as investor-supplied working capital
16 necessary for the Company's day-to-day operations. Certain items are deducted
17 from rate base as they represent funds supplied by customers (or at least not
18 investor-provided). Rate base includes Net Plant, CWIP, Materials and Supplies
19 and Working Capital, less Accumulated Deferred Income Taxes, Unamortized
20 Investment Tax Credits, Customer Advances and Customer Deposits.
5 9. Q: Does the per books rate base and earninl!s conform to the Commission's
2 decision in the Company's last base rate case. Electric Docket No. 05-304?
3 A: Yes, with two exceptions. In Docket No. 05-304, the Company proposed
4 a plant closing adjustment to compensate for reliability based projects that were
5 closed to plant prior to the Company's filing. This adjustment was included in
6 Staffs and Advocate's filed positions and was included in the revenue
7 requirement determination by the Commission. Part of that filed adjustment
8 included recognition of a reduction in CWIP associated with those closing. The
9 remaining CWIP balance was not included in the revenue requirement
10 determination by the Commission.
11 In this case, I have included the 13 month average of CWIP of the
12 Company's rate base claim. Of this $7,256,000 per books Gas specific CWIP
13 claim, $274,000 has not been closed to plant in service as of June 30, 2006.
14 Therefore, $6,982,000 of the Company's $7,256,000 average per books Gas
15 specific CWIP claim has been closed to plant in service. I will provide an update
16 on the $274,000 not yet closed to plant during the discovery process of this
17 proceeding.
18 I did not propose a reliability plant closing adjustment similar to that
19 included in the Company's last base rate revenue requirement determination.
20 While Mr. Driggs provides insight regarding the significant amount of reliability
21 based expenditures in the Company's CWIP claim, I am proposing the inclusion
22 of CWIP in rate base to compensate for that investment. If the parties in this
6 proceeding do not include CWIP in their rate base claim, a reliability plant closing
2 adjustment should be included similar to the Company's last case.
3 The second exception to the Commission's decision in the Company's last
4 base rate case relates to the inclusion of incentive compensation. Company
5 Witness Browning addresses this item in his testimony.
6 7 Cash Workinl! Capital
8 10 Q: How was the Company's cash workinl! capital requirements determined?
9 A: The Company's cash working capital requirements were determined using
10 a lead/lag study developed utilizing 2005 revenue and expense transactions.
11 11. Q: Was this lead/lal! study prepared consistent with Delaware Public Service
12 Commission precedent?
13 A: Yes. This lead/lag study was prepared consistent with Commission Order
14 6930 in the Company's last electric distribution rate fiing.
15 12. Q: What were the results of the lead/lal! study?
16 A: The results of the lead/lag study are provided on Schedule No. 2E of the 17 filing requirements. The total cash working capital requirement for the Company
18 is $9,339,527. The revenue lag days were compared to the lead/lag days for each
19 expense item to determine the cash working capital requirement for each expense 20 item. 21 13. Q: Please describe how the revenue lai: was determined.
22 A: Revenue lags represent the length of time the Company has extended
23 credit for services rendered to its customers until the time payment is received
7 from the customers for such services. In developing the revenue lag, the service
2 lag was first determined, which is the midpoint of the period during which service
3 is rendered. This procedure is followed throughout the test period and results in a
4 service lag of 15.21 days for services billed monthly. The next step was to
5 develop the biling lag. The billing lag reflects the time between the meter
6 reading date at the end of the service period until the time the bil is prepared and
7 rendered. The result of this calculation produces a billing lag of 1.41 days. The
8 calculation of the collection lag is determined by taking the accounts receivable
9 balance at the beginning of the study period, adding the daily customer billings,
10 and deducting daily net customer credits to develop a daily accounts receivable
11 balance outstanding for the twelve month period. Dividing the total customer net
12 credits for the study period into the sum of the daily accounts receivable balance
13 produces the time period between the bill mailing date and the date of payment for 14 all services biled. This calculation results in a collection lag of 35.19 days. The
15 sum of the service lag, billing lag and collection lag equal the total revenue lag of 16 51.82 days.
17 14. Q: Please explain how the expense lal!s were determined.
18 A: Expense lags occur when the Company has received credit for various
19 items and services, which have been advanced to the Company by its creditors.
20 They represent the length of time between receipt of such services and payment
21 for them by the Company.
8 15. Q: Please explain how the catel!ories of expense were selected for the study.
2 A: The most effcient method is to concentrate on the largest dollar expense
3 items. The categories were functionalized into their major components. The
4 major expenses included in the study were purchased gas expense, salaries and
5 wages, service company expenses, taxes other than income taxes, income taxes,
6 interest and preferred dividends, and other operation and maintenance expenses.
7 16. Q: Please explain how the lal! days for these expenses were calculated.
8 A: Except for other operation and maintenance expenses, all of the invoices
9 or transactions for these expenses were examined individually because they
10 represent large elements of expense.
11 17. Q: Please explain how the lal! for other operation and maintenance expenses was 12 calculated.
13 A: The category of other operation and maintenance expenses included all
14 other operating expenses which are represented by a large volume of individual 15 invoices. A representative sample was used to develop an expense lag for this
16 category. In all, 328 invoices were reviewed. The invoices selected were then used
17 to compute the lag for other operation and maintenance expenses. 18 Proforma Adjustments
19 18. Q: Please list the pro forma adjustments that yOU are sponsorinl! in this 20 proceedin2:.
21 A: The pro forma adjustments that I am sponsoring are as follows:
22 1 ) Adjustment No.1 - Removal of Employee Association Expense;
23 2) Adjustment No.2 - Restatement of Association Dues;
9 3) Adjustment No.3 - Normalize Regulatory Commission Expense;
2 4) Adjustment No.4 - Reflect price changes associated with the Company's
3 Wage and FICA expense;
4 5) Adjustment No.5 - Normalize Uncollectible Expense;
5 6) Adjustment No.6 - Normalize Injuries and Damages Expense;
6 7) Adjustment No.7 - Reflect price changes associated with the Company's
7 employee benefits expense;
8 8) Adjustment No.8 - Proform Pension costs;
9 9) Adjustment No.9 - Proform Other Post Employment Benefit costs
10 ("OPEB");
11 10) Adjustment No.1 0 - Reflect January 2006 increase in postal charges;
12 11 ) Adjustment No. 13 - Reflect effect of Common depreciation rate changes
13 approved in Docket # 05-304;
14 12) Adjustment No. 14 - Reflect the ratemaking associated with actual
15 Refinancing transactions;
16 13) Adjustment No. 15 -Reflect the ratemaking associated with proforma
17 Refinancing transactions;
18 14) Adjustment No. 16 - Remove amortization associated with the Gas Pilot
19 Program;
20 15) Adjustment No. 17 - Reflect the ratemaking associated with the Conectiv
21 merger;
22 16) Adjustment No. 18 - Remove Post 1980 vintage ITC Amortization;
23 17) Adjustment No. 19 - Restate Interest on Customer Deposits;
10 18) Adjustment No. 20 - Remove effect of property sold during the test
2 period;
3 19) Adjustment No. 21 - Reflect impact of Mixed Service Deferred Tax; and
4 20) Adjustment Nos. 22 and 23 - Reflect the effects on Interest
5 Synchronization and Cash Working Capital related to all proforma 6 adjustments.
7 19. Q: Why are you makinl! these adjustments?
8 A: These adjustments are being made to the test period to establish the rate
9 effective period as a basis for providing just and reasonable rates. Many of these
10 adjustments reflect the approved ratemaking treatment by the DPSC. Other 11 adjustments have been made to assure that the rate effective period reflects a
12 matching of all elements of the ratemaking formula for known and measurable
13 changes. Workpapers supporting each of these adjustments are included in Book
14 3 of this filing.
15 20. Q: Please describe Adjustment No.1. the removal of Employee Association 16 Expense.
17 A: Consistent with the treatment included in Docket Nos. 92-85, 94-22, 03-
18 127 and 05-304, the amounts charged to expense for support of the Employees'
19 Association were removed for ratemaking purposes. This adjustment is detailed
20 on Schedule WMV-3.
21 21. Q: Please describe Adjustment No.2. the restatement of the Company's
22 Association Expense.
11 A: Consistent with the treatment included in Docket Nos. 94-22, 03-127 and
2 05-304, the payment made to certain organizations were removed from expense
3 since the amounts were not considered to be includable in industry association
4 dues for ratemaking purposes. This adjustment is detailed on Schedule WMV-4.
5 22. Q: Please describe the adjustment made to restate Rel!ulatory Commission
6 Expense. Adjustment No.3.
7 A: Consistent with the treatment included in Docket Nos. 94-22, 03-127 and
8 OS-304, the amount expensed in the test period was adjusted for two items. The
9 first is to normalize the test period level of expense using a three-year average.
10 The second adjustment to the test period level of expense is to reflect the cost of
11 this filing, normalized over a three-year period. This adjustment is detailed on 12 Schedule WMV-S.
13 23. Q: Please describe Adjustment No.4. the adjustment made to reflect the
14 Company's Proposed Wal!e and FICA expense.
15 A: Consistent with the treatment included in Docket Nos. 94-22, 03-127 and
16 OS-304, the Company's test period wage and FICA levels of expense were
17 changed to reflect the known price changes required to be made to be reflective of
18 the rate setting period. These include:
19 1) a non-union wage increase of 3 .30 % effective March 2006,
20 2) a contractual IBEW 1307 wage increase of 3.2S % effective June 2006,
21 3) a contractual IBEW 1238 wage increase of 3.25 % effective February
22 2007,
23 4) a non-union wage increase of 3.S0 % effective March 2007,
12 5) a contractual IBEW 1307 wage increase of3.25 % effective June 2007 2 for nine months,
3 6) a contractual IBEW 1238 wage increase of 3.00 % effective February 4 2008 for two months, and
5 7) a non-union wage increase of 3.50 % effective March 2008 for one 6 month.
7 These wage increases have been applied to the Company's test period salaries and
8 wages to be reflective of the rate effective period, April 2007 through March
9 2008. This adjustment is detailed on Schedule WMV -6.
10 24. Q: Please describe the adjustment made to normalize the Company's
11 Uncollectible Expense. Adjustment No.5.
12 A: Consistent with the treatment included in Docket Nos. 03-127 and 05-304,
13 I have normalized the Company's uncollectible expense using a three year
14 average. This adjustment is detailed on Schedule WMV-7.
15 25. Q: Please describe the adjustment made to normalize Injuries and Damal!es
16 Expense. Adjustment No.6.
17 A: Consistent with the treatment included in Docket Nos. 03-127 and 05-304,
18 I am including an adjustment to normalize Injuries and Damages Expense using a
19 three year period. This adjustment is detailed on Schedule WMV-8.
20 26. Q: Please describe Adjustment No.7. which is the adjustment made to reflect
21 price chanl!es related to the Company's employee benefits prol!ram.
22 A: I have included an adjustment to increase employee benefit expenses by
23 $154,448 as calculated on Schedule WMV-9. This adjustment reflects increases
13 related to medical, dental and vision expenses provided by the Company for its
2 active employee population. The percentage increase reflects the projected
3 change to medical, dental and vision costs that are anticipated for 2007. A similar
4 benefit adjustment was fied in the Company's last Gas base rate case, Docket No. 5 03-127.
6 27. Q: Please describe Adjustment No.8. the adjustment made to proform the
7 Company's Pension expense.
8 A: Consistent with the Company's filing in Docket Nos. 03-127 and 05-304, I
9 have adjusted the Company's booked pension expense to the data provided by the
10 Company's independent actuary. This methodology follows the treatment
11 included in the Company's filing in its last base rate filing and that was included
12 by Staff in its fiing. This adjustment is detailed on Schedule WMV-10.
13 28. Q: Please describe Adjustment No.9. the adjustment made to proform the
14 Company's OPEB expense.
15 A: Consistent with the Company's filing in Docket Nos. 03-127 and OS-304, I
16 have adjusted the Company's booked OPEB expense to the data provided by the
17 Company's actuariaL. This methodology follows the treatment included in the
18 Company's fiing in its last base rate filing and that was included by Staff in its
19 fiing. This adjustment is detailed on Schedule WMV -11.
14 29. Q: Please describe Adjustment No. 10. which is the adjustment made to reflect
2 increases in the Company's postal costs in January 2006.
3 A: I have included an adjustment to increase the Company's postal costs by
4 $13,896 as calculated on Schedule WMV-12. This increase reflects the change in
5 USPS postal rates that went into effect in January 2006.
6 30. Q: Please describe Adjustment No. 13. which is the adjustment made to reflect
7 depreciation rates approved in Docket No. 05-304.
8 A: I have included an adjustment to include the effect on earnings and rate
9 base of the change of the Common depreciation rates approved in Docket No. 05-
10 304. This adjustment is detailed on Schedule WMV-13.
11 31. Q: Please describe Adjustment No. 14. which is the adjustment made to reflect
12 ratemakinl! associated with retinancinl!s that have occurred prior to the end 13 ofthe test period.
14 A: I have included II this filing the earnings and rate base treatment of
15 refinancings that was allocated to the Gas business. This ratemaking treatment is 16 consistent with the approved treatment that has been included in prior
17 Commission decisions, beginning in Docket No. 86-24. Lower cost rates in the
18 Company's capital structure resulting from the Company's refinancings provide a
19 benefit to customers. This adjustment is detailed on Schedule WMV-14.
20 32. Q: Please describe the ratemakinl! for additional refinancinl!s that are planned
21 to occur after the end of the test period. Adjustment No. 15.
22 A: Dr. Morin's capital structure reflects the additional transactions that are
23 planned to occur after the end of the test period. I have included in this fiing the
15 earnings and rate base treatment of the cost associated with the refinancing that is
2 scheduled to occur in 2006. The provided ratemaking is again consistent with that
3 afforded by the DPSC in prior proceedings. The benefits of these refinancings are
4 included in the capital structure supported by Dr. Morin. It is the Company's
5 intent to update any refinancings that occur during the discovery process to actual
6 data during the course of this proceeding. The associated cost rates in the capital
7 structure will also be updated to match the effect of these refinancings. This
8 ratemaking treatment is consistent with approved treatment that has been included
9 in prior Commission decisions, beginning in Docket No. 86-24. Lower cost rates
10 in the Company's capital structure resulting from the Company's refinancings
11 provide a benefit to customers. This adjustment is detailed on Schedule WMV- 12 15.
13 33. Q: Please describe Adjustment No. 16. which is the adjustment made to remove
14 amortization associated with the Gas Pilot Prol!ram.
15 A: I have removed the effect of the amortization of the Gas Pilot Program
16 costs. This issue had been addressed by the parties in the Company's last Gas
17 Base rate case, Docket No. 03-127. The Company's three year amortization of
18 this item will expire in November 2006. As a result, this item should be removed
19 from cost of service as the amortization will be complete prior to the start of the
20 rate effective period. This adjustment is detailed on Schedule WMV-16.
16 34. Q: Please describe Adjustment No. 17. related to the Conectiv merl!er between
2 Atlantic and Delmarva.
3 A: I have included the ratemaking approved by this Commission in Docket
4 No. 97-58 related to the Conectiv merger. Rate reductions to Gas customers
5 related to this merger were included in that decision. This adjustment is detailed
6 on Schedule WMV -17.
7 35. Q: Please describe the adjustment made to remove the Investment Tax Credit
8 Amortization on post-1980 vintal!e assets. Adjustment No. 18.
9 A: Consistent with the ratemaking approved on Docket Nos. 84-23, 91-24
10 and 94-22, I have removed post-1980 vintage Investment Tax Credit (ITC)
11 amortizations. This adjustment reflects the requirements of the Economic
12 Recovery Tax Act of 1981 (ERTA) on post-1980 vintage projects for rate case
13 purposes. The Company has been amortizing ITC on a property service life basis.
14 Under ERTA, Delmarva is an Option One Company for ratemaking purposes for
15 post-1980 vintages. The related ratemaking treatment is to deduct the post-1980 16 accumulated unamortized balance from rate base, and at the same time, not
17 include the related post-1980 vintage amortizations as a reduction of operating
18 expenses. This adjustment is detailed on Schedule WMV-18.
19 36. Q: Please describe Adjustment No. 19. the adjustment made to restate Interest
20 on Customer Deposits.
21 A: I have applied the currently effective interest rate of 4.12% to the
22 Customer Deposit Balance as of the end of the test period to determine an
17 appropriate level of interest expense on customer deposits to be reflected in rates.
2 This adjustment is detailed on Schedule WMV-19.
3 37. Q: Please describe Adjustment No. 20. the adjustment made to reflect the sale of
4 Riverfront property at the end of the test period.
5 A: I have removed the net book value of Riverfront property sold in March
6 2006 from the Company's test period rate base. In addition, test period
7 depreciation expense related to this property has been removed from earnings.
8 This adjustment is detailed on Schedule WMV -20.
9 38. Q: Please describe Adjustment No. 21. the mixed service deferred tax 10 adjustment.
11 A: Consistent with the treatment approved by the Commission in Docket No.
12 OS-304, this adjustment reflects the deferred tax balance effect reflecting the IRS
13 regulation requiring Delmarva and other similarly situated utilities to modify
14 practices concerning how certain overhead costs are deducted or alternatively
15 capitalized and depreciated. This adjustment is detailed on Schedule WMV-21.
16 39. Q: Describe the Interest Synchronization Adjustment that you support in this 17 proceedinl!. Adjustment No. 22. 18 A: This adjustment synchronizes the interest expense utilized in the per books
19 income tax calculation with the adjusted rate base and the tax deductible
20 component included in the cost of capital sponsored by Dr. Morin. This
21 adjustment is detailed on Schedule WMV-22.
22 40. Q: Describe Adjustment No. 23. the Cash Workin2 Capital Adjustment.
18 A: This adjustment reflects the inclusion of the calculated cash working
2 capital effect of all earning adjustments using the ratios supported in my
3 testimony. This adjustment is detailed on Schedule WMV -22. 4 Revenue Requirement
5 41. Q: Can you summarize the adjustments that are included in this fiinl!?
6 A: Yes, I can. Schedule WMV-23 displays all of the proforma adjustments
7 included in this filing and details supporting witness, earnings and rate base 8 impact.
9 42. Q: Please summarize the Company's overall revenue deficiency,
10 A: Schedule WMV-24 displays the calculation of the Company's revenue
11 deficiency of $14,967,412. This calculation includes the effect of all of the
12 proforma adjustments to the test period level of earings and rate base and uses
13 Dr. Morin's supplied rate of return of 8.08 %.
14 43. Q: Does this conclude your testimony?
15 A: Yes, it does.
19 Schedule WMV - 1 Pacie 1 of 2
Delmarva Power & Light Company System Gas Earnings 12 Months Endinci March 31, 2006
(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) Line Per Cost Emp Assoc Exp (12) (13) Association Dues Regulatory Exp Wage & FICA Uncollectible Exp Injuries & Dam Benefis Expense Pension Expense OPEB Postage Increase No. Description 01 Service Adiustment Adiustment Normalization Adjustment Normalization Normalization Adiustment Adiustment Adiustment Adjustment
1 Supporting Witness Von Steuben Von Steuben Von Steuben Von Steuben Von Steuben Von Steuben Von Steuben Von Steuben 2 Von Steuben Von Steuben 3 Operating Revenues 4 Sales $58.721.182 $0 $0 $0 $0 $0 $0 $0 5 Other Revenues $0 $0 $0 $6,463 iQ iQ iQ iQ iQ 6 Total Operating Revenues iQ iQ iQ iQ iQ $58,727,645 $0 $0 $0 $0 $0 $0 $0 7 $0 $0 $0 8 Operating Expenses 9 Operation and Maintenance $25.155.705 ($7.710) ($2,409) $189.022 $949.628 $298,511 $154,448 10 Depreciation and Amortization ($24,049) $599,439 $299.984 $13,896 $12.231.041 $0 $0 $0 $0 $0 $0 $0 11 Taxes Other than Income Taxes $0 $0 $0 $3.601.232 $0 $0 $0 $72.370 $0 $0 $0 12 Income Taxes and Provisions $0 $0 $0 $5.248.292 $3.135 ($76,847) 1$415,493) ($121,360) $9.777 ($62,7911 13 Total Operating Expenses ~ ($243,702) ($121.959) ($5,650) $46.236.270 ($4.575) ($1,429) $112.175 $606,505 $177.151 14 ($14.272) $91.657 $355.737 $178,025 $8.246 15 Operating Income $12,491.375 $4.575 $1,429 ($112.175) ($606.505) ($177.151) $14.272 16 ($91.657) ($355.737) ($178.025) ($8,246) 17 AFUDC $56.226 $0 $0 $0 $0 $0 $0 $0 18 Other Income and Deductions $0 $0 $0 ($63.573) $0 $0 $0 $0 $0 $0 19 $0 $0 $0 $0 20 Net Operating Income $12,484,028 $4.575 $1,429 ($112.175) ($606.505) ($177,151) $14.272 ($91.657) ($355,737) ($178.025) ($8.246) Schedule WMV . 1 PaQe 2 of 2
Delmarva Power & Light Company System Gas Earnings 12 Months EndinQ March 31, 2006
(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) (13) Line Incremental O&M Compliance Depreciation Rates Actual (14) Profomia Remove Gas Dkt 97.58 Merger Post 1980 ITC LOCO Riverfront Interest Adjusted No. Oescriotion Adiustment Costs Aooroved Dkt 05.304 Refinancinas Refinancinas Pilot Amortization Adiustment Amortization Adiustment Prooertv Sale Synchronization Eaminos 1 Supporting Witness Driggs Driggs Van Steuben Van Steuben Van Steuben Van Steuben Van Steuben 2 Van Steuben Van Steuben Van Steuben Van Steuben 3 Operating Revenues 4 Sales $0 $0 $0 $0 $0 $0 5 Other Revenues ~ ~ $0 $0 $0 $0 $0 $58,721,182 6 Total Operating Revenues ~ ~ ~ ~ ~ ~ ~ ~ ~ $6,463 $0 $0 $0, $0 $0 $0 7 $0 $0 $0 $0 $0 $58,727,645 8 Operating Expenses 9 Operation and Maintenance $529,189 $812,543 $0 $0 $0 $0 10 Depreciation and Amortization $0 $0 $0 $0 $0 $28,968,197 $0 $38,900 $226,271 $217,017 $11,840 $377,492 11 Taxes Other than Income Taxes ($165,006) $0 $0 ($43,412) $0 $12,894,143 $0 $0 $0 $0 $0 $0 12 Income Taxes and Provisions $0 $0 $0 $0 $0 $3,673,602 ($215142\ ($346,154 \ ($101 445\ ($5,535\ $67 083 ($153 469) 13 Total Operating Expenses $60 286 $17,649 ($635 159) $2793 126 $314,047 $505,289 $134,280~ $115,572 $6,305 ($97,923) $224,023 $60,286 Ii($17,379) ($25,763) $48,329,070 14 ($635,159) 15 Operating Income ($314,047) ($505,289) ($134,280) ($115,572) $97,923 16 ($6,305) ($224,023) ($60,288) $17,379 $25,763 $635,159 $10,398,575 17 AFUDC $0 $0 $0 $0 $0 $0 18 Other Income and Deductions $0 $0 $0 $0 $0 $56,226 $0 $0 $0 $0 $0 $0 19 $0 $0 ($42,747) $0 $0 ($106,320) 20 Net Operating Income ($314,047) ($505,289) ($134,280) ($115,572) ($6,305) $97,923 ($224,023) ($60,288) ($25,368) $25,763 $635,159 $10,348,481 Schedule WMV . 2
Delmarva Power & Light Company Gas Rate Base 12 Months EndlnQ March 31, 2006
(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) Line Per Cost Compliance Depreciation Rates (12) Actual Profomia Dkl 97.58 Merger Rivenront Mixed Service CWC Adjusted No. Descriotion of Service Costs Aooroved Dkt 05.304 Refinancinos Refinancinas Adiustment Prooertv Sale Deferred Tax Adiustment Rate Base 1 Supporting Witness Dnggs Van Steuben Van Steuben Von Steuben Van Steuben 2 Van Steuben Van Steuben Van Steuben 3 Gas Plant in Service $354,808,865 $1,000,000 $0 $0 4 Intangible Assets $0 $0 ($1,489,452) $0 $0 $354,319,413 $1,298,804 $0 $0 $0 5 Less: Accumulated Depreciation and Amortization $0 $0 $0 $0 $0 $1,298,804 $144732298 $38 gOO $113135 6 Net Plant in Service iQ iQ iQ ($771 487) iQ iQ $144112846 $211,375,370 $961,100 ($113,135) $0 $0 7 $0 ($717,965) $0 $0 $211,505,370 8 Less: Customer Advances ($207,715) $0 $0 $0 $0 9 Accumulated Deferred Income Taxes $0 $0 $0 $0 ($207,715) ($23,364,291 ) ($15,815) $45,995 ($1,311,169) ($52,579) 10 Accumulated Investment Tax Credit ($370,884 ) $291,889 $5,450,000 $0 ($19,326,854) ($904,630) $0 $0 $0 11 $0 $0 $0 $0 $0 ($904,630) 12 Plus: Materials and Supplies $18,281,431 $0 $0 $0 $0 13 Working Capital $0 $0 $0 $0 $18,281,431 $19,676,420 $0 $0 $0 $0 14 Other Elements of Property $0 $0 $0 ($169,224 ) $19,507,196 15 Construction Work in Progress $7,309,188 $0 $0 $0 $0 16 Customer Deposits $0 $0 $0 $0 $7,309,188 ($2,317,383) $0 $0 $0 $0 17 $0 $0 $0 $0 ($2,317,383) Amortizable Balances $0 $0 $0 $2,804,940 18 $112,480 $912,272 $0 $0 $0 $3,829,692 19 Total Claimed Rate Base $229,848,389 $945,285 $1,493,771 ($67,140) $59,901 $541,388 ($426,076) $5,450,000 ($169,224 ) $237,676,294 Delmarva Power & Light Schedule WMV - 3 Employee Association Expenses - Gas 12 Months Ending March 31. 2006
(1 ) (2) (3) Line No. Item $
1 Employee Association expenses - total Pepco $219,022 2 3 Delmarva Power & Light allocation 26.86% 4 5 Employee Association expenses - total DPL $58,826 6 7 Delmarva Power & Light Gas allocation 13.11 % 8 9 Employee Association expenses - total DPL Gas $7,710 10 11 Impact to Operating Expense ($7,710) 12 13 Impact to SIT (g 8.7% $671 14 15 Impact to FIT (g 35% $2,464 16 17 Impact to Operating Income $4,575 Delmarva Power & Light Schedule WMV - 4 Restate Association Dues - Gas 12 Months Ending March 31. 2006
(1 ) (2) (3) Line No. Item $
1 Gas Association Dues to be removed $ 2,409 2 3 Impact to Operating Expense ($2,409) 4 5 Impact to SIT ~ 8.7% $210 6 7 Impact to FIT ~ 35% $770 8 9 Impact to Operating Income $1 ,429 Delmarva Power & Light Schedule WMV - 5 Regulatory Commission Expense - Gas 12 Months Endin~ March 31, 2006
(1 ) (2) (3) (4) Line No. Item !
1 3 Year Average (1) $88,506 2 3 12 Months Ended 3/31/06 $28,484 4 5 Adjustment $60,022 6 7 Cost of Current Case (2) $387,000 8 Amount included in Adjustment $129,000 9 10 Total Adjustment $189,022 11 12 Impact to SIT (g 8.7% ($16,445) 13 14 Impact to FIT (g 35% ($60,402) 15 16 Impact to Operating Income ($112,175) 17 18 (1 ) 3 Year AveraQe Total AlC 928 Regulatory Tax Net 19 12 Months Ended 3/31/06 $ 716,733 $ 688,249 $ 28,484 20 12 Months Ended 3/31/05 $ 510,194 $ 432,779 $ 77,415 21 12 Months Ended 3/31/04 $ 489,618 $ 330,000 $ 159.618 22 Average $ 88,506 23 24 (2) Cost of Current Case 25 Cost of Service Consultant $55,000 26 Cost of Capital Consultant $62,000 27 Legal $45,000 28 DPSC $225,000 29 30 Total $387,000 Delmarva Power & Light Company Schedule WMV - 6 Wage, Salary, and FICA Adjustment - Gas 12 Months Endina March 31.2006
(2) (3) (4) Total Gas Salary and Waae Adjustment Total Adjustment $7,245,718
Gas Expense ratio 13.11 %
Gas Expense $949,628
State Income Tax ($82,618) Federal Income Tax ($303,454 ) Total Expense $563,557
Earnings ($563,557)
FICA Adjustment Total Adjustment $552,190
Gas Expense ratio 13.11 %
Gas Expense $72,370
State Income Tax ($6,296) Federal Income Tax ($23,126) Total Expense $42,948
Earnings ($42,948)
Total Earnings Adjustment ($606,505) Delmarva Power & Light Schedule WMV - 7 Normalization of Uncollectible Expense - Gas 12 Months Ending March 31, 2006
(1 ) (2) (3) Line No. Item $
1 3 Year Average $1,662,546 2 3 12 Months Ended 3/31/06 $1,364,035 4 5 Adjustment $298,511 6 7 Impact to SIT (Ç 8.7% ($25,970) 8 9 Impact to FIT (Ç 35% ($95,389) 10 11 Impact to Operating Income ($177,151)
Account 904 12 Months Ended 3/31/04 $1,966,930 12 Months Ended 3/31/05 $1,656,672 12 Months Ended 3/31/06 $1,364,035
Average $1,662,546 Delmarva Power & Light Schedule WMV - 8 Normalization of Injuries & Damages Expense - Gas 12 Months Endina March 31. 2006
(1 ) (2) (3) Line No. Item $
1 3 Year Average $29,353 2 3 12 Months Ended 3/31/06 $53,402 4 5 Adjustment ($24,049) 6 7 Impact to SIT (Q 8.7% $2,092 8 9 Impact to FIT (Q 35% $7,685 10 11 Impact to Operating Income $14,272 12 13 14 Account 925 12 Months Ended 3/31/04 $33,406 (1 ) 15 12 Months Ended 3/31/05 $1,250 16 12 Months Ended 3/31/06 $53,402 17 18 Average $29,353 19 . 20 21 22 (1 ) 12 Months Ended 3/31/04 - Per Books $289,724 23 1&0 Adjustment recorded 12/03 $256.318 24 12 Months Ended 3/31/04 - without adjustment $33,406 Schedule WMV - 9 DPL . Gas MedicallDentalNision Costs 12 Months Ended 3/31/06
(1 ) (2) (3) (4) (5) Line No. Per Books Benefit Rate Period Amount Rate Change Increase 1 Allocated to DPL 2 Medical 7,184,649 9% 646,618 3 Dental 694,645 5% 34,732 4 Vision 111,366 5% 5,568 5 Total DPL Costs 7,990,660 686,919 6 DPL - Gas Expense ratio 13.11 % 7 DPL - Gas Medical/DentalNision Cost Increase 90,028 8 9 Service Company employees allocated to DPL 10 Medical 3,610,891 9% 324,980 11 Dental 349,118 5% 17,456 12 Vision 55.971 5% 2,799 13 Total allocated Service Company Costs 4,015,979 345,235 14 Expense allocator 89.30% 15 308,309 16 Gas Allocation Factor 21% 17 Service Company Allocated MedicallDentalNision Cost Increase - Gas 64,420 18 19 Total Gas MedicallDentalNision Cost Increase for Rate Effective Period 154,448 20 21 SIT ( 13,437) 22 FIT (49.354) 23 Total Expense 91,657 24 25 Earnings (91,657) Delmarva Power & Light Company Schedule WMV . 10 12 Months Ending March 2006 Pension. Gas
(1 ) (2) (3) (4) Line Total No. Item Delmarva 1 Delmarva Power 2 Pension Expense - 12 mle March 31, 2006 $ (776,481) (1) 3 4 Pension Expense 2006 Actuary measurement $ (177,042) (2) 5 6 Difference $ 599,439 7 8 State Income Tax ($52,151 ) 9 Federal Income Tax ($191,551 ) 10 Expense Adjustment $ 355,737 11 12 Earnings $ (355,737) 13 14 Reference: 15 (1 ) DPL Pension Costs 12 MIE 3/31/06 $ (8,703,789) 16 DPL Gas Expense Ratio 13.11 % 17 DPL Gas Pension Expense $ (1,140,724) 18 19 Service Company Pension Cost 12 MIE 3/31/06 $ 7,315,251 20 Service Company Expense Allocator 89.30% 21 $ 6,532,836 22 23 Service Company System Allocator to DPL 26.55% 24 Service Company Pension Expense Allocated to DPL $ 1,734,489 25 26 Gas Allocation Factor 21.00% 27 Service Company Pension Expense - Gas $ 364,243 28 29 Total Gas Pension Expense 12 m/e March 2006 $ (776,481) (1) 30 31 32 (2) DPL Pension Costs per Actuary 2006 $ (6,579,896) 33 DPL Gas Expense Ratio 13.11 % 34 DPL Gas Pension Expense $ (862,365) 35 36 Service Company Pension Costs per Actuary 2006 $ 13,763,655 37 Service Company Pension Expense Allocator 89.30% 38 $ 12,291,539 39 40 DPL System Allocator 26.55% 41 Service Company Pension Expense Allocated to DPL $ 3,263,443 42 43 Gas Allocation Factor 21.00% 44 Service Company Pension Expense - Gas $ 685,323 45 46 Total Gas Pension Expense - 2006 Actuary $ (177,042) (2) Delmarva Power & Light Company Schedule WMV - 11 12 Months Ending March 2006 OPES - Gas
(1 ) (2) (3) (4) Line Total No. Item Delmarva 1 Delmarva Power 2 OPES Expense - 12 m/e March 31, 2006 $ 1,421,065 (1 ) 3 4 OPES Expense 2006 Actuary measurement $ 1,721,049 (2) 5
6 Difference $ 299,984 7 8 State Income Tax ($26,099) 9 Federal Income Tax ($95,860) 10 Expense Adjustment $ 178,025 11 12 Earnings $ (178,025) 13 14 Reference: 15 (1 ) DPL OPES Costs 12 M/E 3/31/06 $ 5,090,305 16 DPL Gas Expense Ratio 13.11 % 17 DPL Gas Pension Expense $ 667,139 18 19 Service Company Pension Cost 12 M/E 3/31/06 $ 15,222,901 20 Service Company Expense Allocator 89.30% 21 $ 13,594,709 22 23 Service Company System Allocator to DPL 26.41 % 24 Service Company Pension Expense Allocated to DPL $ 3,590,127 25 26 Gas Allocation Factor 21.00% 27 Service Company Pension Expense - Gas $ 753,927 28 29 Total Gas Pension Expense 12 m/e March 2006 $ 1,421,065 (1 ) 30 31 32 (2) DPL OPES Costs per Actuary 2006 $ 6,780,085 33 DPL Gas Expense Ratio 13.11 % 34 DPL Gas Pension Expense $ 888,602 35 36 Service Company Pension Costs per Actuary 2006 $ 16,808,338 37 Service Company Pension Expense Allocator 89.30% 38 $ 15,010,573 39 40 DPL System Allocator 26.41% 41 Service Company Pension Expense Allocated to DPL $ 3,964,032 42 43 Gas Allocation Factor 21.00% 44 Service Company Pension Expense - Gas $ 832,447 45 46 Total Gas Pension Expense - 2006 Actuary $ 1,721,049 (2) Delmarva Power & Light Company Schedule WMV - 12 Adjustment to Gas Postage Costs 12 Months Ending March 2006
(1 ) (2) (3) (4) (5) (6) Line Customer Cost Cost No. Item Count (vintaoe rates) (2006 rates) Chanoe
1 April 2005 118,765 $37,767 $39,311 2 May 2005 118,644 $37,729 $39,271 3 June 2005 118,294 $37,617 $39,155 4 July 2005 118,277 $37,612 $39,150 5 August 2005 118,441 $37,664 $39,204 6 September 2005 118,571 $37,706 $39,247 7 October 2005 118,793 $37,776 $39,320 8 November 2005 119,332 $37,948 $39,499 9 December 2005 119,781 $38,090 $39,648 10 January 2006 120,158 $39,772 $39,772 11 February 2006 120,295 $39,818 $39,818 12 March 2006 120,466 $39,874 $39,874 13 14 Total $459,374 $473,269 $13,896 15 16 O&M Expense Change $13,896 17 18 SIT ($1,209) 19 FIT ($4,440) 20 Total Expense $8,246 21 22 Earnings ($8,246) 23 24 1) Average postage cost. 2005 $0.318 2) Average postage cost - 2006 25 $0.331 Delmarva Power & Light Company Schedule WMV - 13 Gas Depreciation Expense Adjustment Common Depreciation Rate Change - Dkt No. 05-304 12 Months Ending March 2006
(1 ) (2) (3) Line No. Item
1 Earnings 2 Common Plant - Account 390.3 3 Test Period Balance 37,412,464 4 5 Depreciation Rate in Effect during 6 Test Period 3.290% 7 8 Approved Depreciation Rate 9 from DPSC Dkt 05-304 7.070% 10 11 Change in Depreciation Expense 1,414,191 12 13 Allocator to Gas 16.00% 14 15 Change in Gas Depreciation Expense 226,271 16 Deferred SIT (19,686) 17 Deferred FIT (72,305) 18 Total Expense 134,280 19 20 Earnings (134,280) 21 22 Rate Base - Average 23 24 Depreciation Reserve 113,135 25 Net Plant (113,135) 26 27 Deferred SIT Balance 9,843 28 Deferred FIT Balance 36,152 29 30 Net Rate Base (67,140) Delmarva Power & Light Company Schedule WMV - 14 Actual Loss/Gain on Refinancings - Gas 12 Months Endinq March 31, 2006
(1 ) (2) (3) Line No. Item Amount
Total Company $35,950,563 1 Gas Amount Refinanced $3,822,863 2 Deferred SIT ($332,589) 3 Deferred FIT ($1,454,408) 4 5 Earnings 6 Amortization $217,017 7 DSIT ($18,880) 8 DFIT ($82,564 ) 9 Total Expense $115,572 10 Earnings ($115,572) 11 12 Rate Base 13 Amortizable Balance - Beginning $2,913,448 14 Amortizable Balance - Ending $2,696,431 15 Average Balance $2,804,940 16 17 Deferred SIT - Beginning ($253,4 70) 18 Deferred SIT - Ending ($234,590) 19 Average Balance ($244,030) 20 21 Deferred FIT - Beginning ($1,108,421) 22 Deferred FIT - Ending ($1,025,857) 23. Average Balance ($1,067,139) 24 25 Net Average Balance $1,493,771 Delmarva Power & Light Company Schedule WMV -15 Profroma Loss on Refinancing - Gas 12 Months Endinq March 31, 2006
(1) (2) (3) Line Preferred Stock No. Item Nov-06
1 Total Company $740,000 2 Gas Amount Refinanced $118,400 3 Deferred SIT ($10,301 ) 4 Deferred FIT ($45,045) 5 6 Earnings 7 Amortization $11,840 8 DSIT ($1,030) 9 DFIT ($4,505) 10 Total Expense $6,305 11 Earnings ($6,305) 12 13 Rate Base 14 Amortizable Balance - Beginning $118,400 15 Amortizable Balance - Ending $106,560 16 Average Balance $112,480 17 18 Deferred SIT - Beginning ($10,301 ) 19 Deferred SIT - Ending ($9,271 ) 20 Average Balance ($9,786) 21 22 Deferred FIT - Beginning ($45,045) 23 Deferred FIT - Ending ($40,541 ) 24 Average Balance ($42,793) 25 26 Net Average Balance $59,901 Delmarva Power & Light Schedule WMV -16 Removal of Gas Pilot Costs Amortization 12 Months Endina March 31, 2006
(1 ) (2) (3) Line No. Item i
1 Adjustment to Remove Gas Pilot Costs Amortization 2 Gas Pilot Amortization - per books ($165,006) 3 4 Impact to DSIT ~ 8.7% $14,356 5 6 Impact to DFIT ~ 35% $52,728 7 8 Total Expense ($97,923) 9 10 Earnings $97,923 Delmarva Power & Light Company Schedule WMV -17 Merger Adjustment - Gas 12 Months EndinQ March 31. 2006
(1 ) (2) (3) (4) (5) Line Gas No. Item System Allocation Gas
1 EarninQs 2 Revenues 3 Annualize Ordered Rate Reduction (1 ) $0 4 5 Expense 6 7 Amortize out-of-pocket costs - ten year period (3) $9,934,000 0.0380 $377 ,492 8 9 Other Taxes ~ .005 $0 10 State Income Tax ($32,842) 11 Federal Income Tax ($120.628) 12 Total Expense $224,023 13 Earnings ($224,023) 14 15 Rate Base 16 Average Amortizable Balance $912,272 17 18 Deferred State Income Tax Balance ($79.368) 19 Deferred Federal Income Tax Balance ($291.517) 20 Average Net Rate Base $541,388 21 22 23 (1) Total Ordered Rate Reduction - Dkt 97-58 24 Effective 3/1/99 $538,000 25 Amount included in test year (1/00 - 12/00) $538.000 26 Rate Reduction not included in test year $0 27 28 (2) Amortizable Balance 3/1/98 $99,340,000 29 Beginning Balance 4/1/05 $28,974,167 30 Ending Balance 3/31/06 $19.040.167 31 Average Balance $24,007,167 0.0380 $912,272 32 33 34 Months from 3/1/98 to beginning of test year 85 35 36 37 (3) Amortization Balance $99,340,000 38 Amortization period - mths 120 39 Annual Amortization $9,934,000 Delmarva Power & Light Company Schedule WMV - 18 Investment Tax Credit - Gas 12 Months EndinQ March 31, 2006
(1 ) (2) (3) (4) (5) (6) Line (7) (8) Balance Pre 1981 Post 1980 Total Balance Average No. Item March 2005 Amortization Amortization Amortization March 2006 Balance 1 . Gas Investment Tax Credit 2 Total Production (0) 0 0 0 (0) 3 (0) 4 Transmission (47,868) (313) (3,302) (3,615) (44,253) 5 (46,060) 6 Distribution (749,530) (5,076) (44,311) (49,387) 7 (700,143) (724,836) 8 General (27,641) (165) (2,048) (2,214) 9 (25,428) (26,535) 10 Common (112,823) (621) (10,627) (11,248) 11 (101,575) (107,199) 12 Total Gas (937,862) (6,175) (60,288) (66,463) 13 (871,399) (904,630) 14 Adjustment to Remove Post 1980YintaQe ITC Amortization 15 16 Expense 60,288 17 18 Earnings (60,288) Delmarva Power & Light Schedule WMV -19 March 31,2006 Test Year Interest on Customer Deposits
(1 ) (2) (3) Line No. Item $
1 Customer Deposit Balance (i 3/31/06 $2,580,576 2 3 2006 Interest Rate 4.12% 4 5 Annual Interest Expense $106,320 6 7 Test Year Interest Expense 63,573 8 9 Impact to Operating Expense $42,747 10 11 Impact to SIT (i 8.7% ($3,719) 12 13 Impact to FIT (i 35% ($13,660) 14 15 Impact to Operating Income ($25,368) Delmarva Power & Light Company Schedule WMV - 20 Sale of Riverfront Property 12 Months Endinçi March 31, 2006
(1 ) (2) (3) Line No. Item Amount
1 Earninçis 2 Removal of Depreciation Expense ($43,412) 3 4 State Income Tax $3,777 5 Federal Income Tax $13.872 6 Total Expense ($25,763) 7 Earnings $25,763 8 9 Rate Base 10 Removal of Net Plant in Service ($717,965) 11 12 Deferred State Income Tax Balance $62,463 13 Deferred Federal Income Tax Balance $229.426 14 Net Rate Base ($426,076) Delmarva Power & light Company Schedule WMV - 21 Mixed Service Deferred Tax Adjustment
(1 ) (2) (3) No. Item Gas
1 Per Books Adjustment 2 Amount Recorded through March 2006 $4,900,000
3 Included in Average Test Period $2,450,000
4 Adjustment to 3/31/06 ROR Per Books $2,450,000 5 Proforma - 2006 Adjustment 6 Amount Recorded Monthly - 4/06 - 12/06 $3,000,000
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.. N C" -a It to ! ~l ~::~~;!~~~~~~Ñ~~~ææ~regigM~~;;~~~~~~:;~ ~:~~!; ~ Delmarva Power & Light Company Schedule WMV - 23 Gas Adjustments 12 Months Endinq March 31. 2006
(OOO's)
(1 ) (2) (3) (4) (5) (6) Line Rate No. Item Witness Earninqs Base ROR
1 Per Books - 12 m/e March 31, 2006 $6,270 $233,877 2.68% 2 3 Remove Environmental Surcharge WMV ($1) $0 4 Remove TETCO WMV $0 ($4,028) 5 Customer Revenue Adjustment JFJ ($15) $0 6 Weather Normalization KCF $658 $0 7 Remove Utility Taxes WMV $18 $0 8 Bill Frequency JFJ $98 $0 9 Remove Unbilled Revenue WMV $881 $0 10 Remove GCR Fuel WMV $4,953 $0 11 Margin Sharing Adjustment CLD ($796) $0 12 PSC Assessment Annualization JFJ $0 $0 13 Reclassify Tax Data WMV ($70) $0 14 Remove Prior Period Taxes WMV $488 $0 15 Per Books for COS 16 $12,484 $229,848 5.43% 17 18 Adjustments 19 1 Remove Employee Association WMV $5 $0 20 2 Restate Association Dues WMV $1 $0 21 3 Regulatory Commission Exp Normalization WMV ($112) $0 22 4 Wage and FICA Adjustment WMV ($607) $0 23 5 Uncollectible Expense Normalization WMV ($177) $0 24 6 Injuries and Damages Exp Normalization WMV $14 $0 25 Benefis Expense Adjustment 7 WMV ($92) $0 26 8 Pension Expense Adjustment WMV ($356) $0 27 9 OPES Adjustment WMV ($178) $0 28 10 Postage Increase WMV ($8) $0 29 11 Incremental O&M Expense Adjustment CLD ($314) $0 30 12 Compliance Costs Adjustment CLD ($505) $945 31 13 Depreciation Rates - Approved Dkt 05-304 WMV ($134) ($67) 32 14 Actual Refinancings WMV ($116) $1,494 33 15 Proforma Refinancings WMV ($6) $60 34 16 Remove Gas Pilot Costs Amortization WMV $98 $0 35 17 Conectiv Merger Adjustment WMV ($224 ) $541 36 18 Remove Post 1980 ITC Amortization WMV ($60) $0 37 19 IOCD Adjustment WMV ($25) $0 38 20 Riverfront Property Sale WMV $26 ($426) 39 21 Mixed Service Deferred Tax Adjustment WMV $0 $5,450 40 22 Interest Synchronization WMV $635 $0 41 23 Cash Working Capital WMV $0 ($169) 42 43 Total Adjustments ($2,136) $7,828 44 Adjusted Test Period $10,348 $237,676 4.35% Schedule WMV-24
Delmarva Power & Light Company Gas March 2006 Test Period Determination of Revenue Requirements (OOO's)
(1 ) (2) (3) Line No. Item Detail
Adjusted Net Rate Base $237,676
2 Required Rate of Return 8.08%
3 Required Operating Income $19,204
4 Pro Forma Operating Income $10,348
5 Operating Income Deficiency $8,856
6 Revenue Conversion Factor 1.69013
7 Revenue Requirement $14,967 DELMARVA POWER & LIGHT COMPANY 2 TESTIMONY OF JOSEPH F. JANOCHA
3 BEFORE THE DELAWARE PUBLIC SERVICE COMMISSION 4 CONCERNING AN INCREASE IN GAS BASE RATES 5 DOCKET NO. 06-
6 1. Q: Please state your name and position. and business address.
7 A: My name is Joseph F. Janocha. I am a Regulatory Affairs Manager in the
8 Rates and Technical Services Section of Pepco Holdings Inc. ("PHI"). I am
9 testifying on behalf of Delmarva Power & Light Company ("Delmarva", "the
10 Company".
11 2. Q: What is your educational and professional backl!round and experience?
12 A: I have a Bachelor of Engineering degree with a concentration in
13 Mechanical Engineering from Stevens Institute of Technology. I am a Registered
14 Professional Engineer in the States of New Jersey and Pennsylvania. I began my
15 career with Philadelphia Electric Company (now Exelon) in 1982 as an engineer
16 in the Mechanical Engineering Division. From 1982 through 1992, I held various
17 positions in the Mechanical Engineering, Nuclear Quality Assurance and Nuclear
18 Engineering Divisions. I joined Atlantic Electric in 1992 as a Senior Engineer in
19 the Joint Generation Department. In 1998, I joined the Regulatory Affairs group
20 as a Coordinator, responsible for the design and administration of electric rates for
21 Atlantic City Electric Company. My primary responsibility in my current
22 position is the development and administration of unbundled rates for Atlantic
23 City Electric Company and Delmarva Power & Light Company.
1 1 3. Q: Have YOU fied testimony in any other proceedinl!s? 2 A: Yes. I have previously presented and/or fied testimony as a witness
3 before the New Jersey Board of Public Utilities, the Delaware Public Service
4 Commission, the Maryland Public Service Commission and the State Corporation
5 Commission of Virginia.
6 4. Q: What is the purpose of your testimony? 7 A: My testimony is divided into three major areas:
8 i. Rate Design supporting the Company's proposed increase in gas
9 base revenue in the amount of $14,967,412, as contained in the 10 direct testimony of Witness Von Steuben. 11 II. Bill Stabilization Adjustment tariff for the revenue stability 12 mechanism being proposed in this filing
13 III. Minimum Filing Requirements and Adjustments
14 iv. Tariff Changes 1615 Rate Desil!n
17 5. Q: Please provide an overview of the rate desil!n.
18 A: The recommended rate design produces the Company's proposed increase
19 in gas base revenue of$14,967,4l2 or 6.62% or total revenues. It incorporates the
20 results from the Cost of Service Study ("COSS") contained in the direct testimony
21 of Witness Normand. In addition, my recommended rate design considers the
22 unitized rate of return ("UROR") for each customer class in the allocation of 23 overall revenue requirements.
2 6. Q : What are the overall principles that were emploved in the desil!n of the
2 proposed l!as base rates?
3 A: The gas base rates were designed using the following major principles:
4 1) Minimize, to the extent possible, the level that any rate class specific
5 rate of return is more or less than the overall required rate of return. The measure
6 of success in achieving this goal is the UROR, specifically the extent to which
7 each rate class approaches a UROR of unity. The unitized rate of return is simply
8 a mathematical expression which relates the retur from each customer class to
9 the overall return of the entire jurisdiction. A UROR greater than 1.0 means that
10 the customer class is providing a greater than average return; a UROR less than
1 1 1.0 means that the customer class is providing less than the average return for the
12 jurisdiction.
13 2) Provide customers with price signals that accurately reflect the cost of
14 providing service. This is accomplished by establishing customer, commodity
15 and, if applicable, demand rate components that recover costs in direct relation to
16 the classification results of the COSS.
17 3) Introduce gradualism into the revenue allocation process and the
18 functional rate design for each class by recognizing both the overall impact on
19 customers of the requested increase and the benefit of maintaining a level of
20 stability in the inter- and intra-class rate relationships
21 7. Q : Please describe the process for establishinl! the proposed rate desil!n.
22 A: The rate design procedure is described below. Detailed workpapers
23 supporting the rate design are provided in Book 3 of the Company's fiing.
3 First, the rate classes' distribution revenue, net operating income, net rate
2 base, rate of return and UROR from the COSS were summarized as a starting
3 point for the allocation of the revenue increase. This summar on page 1 of the
4 rate design workpapers shows that the URORs for four classes, R, MVG, GL and
5 LVG, are outside of the desired range. The Rand MVG classes were significantly
6 below unity, with UROR's of 0.76 and 0.70, respectively. LVG and GL, with
7 URORs of 1. 14 and 2.36 were above the desirable range. These UROR results
8 were used as a benchmark to determine appropriate shifts in UROR in the final
9 rate design.
10 The next step allocated the overall revenue increase to rate classes with the
1 1 goal of achieving a rate class UROR within the desired range of 0.9 to 1.1. For
12 MVG, the UROR was moved to 0.92, slightly more than half way to unity. The
13 L VG rate class was lowered to a UROR of 1.07, half way to unity. The R, GG
14 and GL rate classes were all moved to a UROR of exactly unity. The residual
15 allocation was assigned to rate class RSH, which resulted in a UROR of unity as
16 welL. The results of the allocation process are provided on page one of the rate
17 design workpapers. In addition, the allocation associated with moving all rate
18 classes exactly to unity is provided for comparison. The recommended results,
19 employing gradualism measures in the treatment of MVG and L VG, can be seen
20 to provide a more even distribution of the rate increase across all customer
21 classes.
22 8. Q: Please explain the development of the proposed rate schedule-specific rate
23 components reflectinl! the revenue allocation results.
4 The primary objective of the design of the individual rate schedules is to
reflect cost causation, as shown in the COSS. Gradualism measures were
introduced as required.
The initial step was to modify the customer charges, using the results of
the casso The customer charges for the larger commercial and industrial rate classes, MVG and L VG, were set to levels which fully recover customer related costs. For the residential and smaller commercial classes, however, the increase to the customer charge was limited to half the amount required for full recovery of customer related costs. This was done to mitigate wide swings in intra-class rate impacts.
The next step was to adjust the demand and commodity or delivery components for the L VG and MVG Commercial and Industrial base rates to better reflect the classification results of the COSS. Page 16 of the rate design workpapers shows that based on the results of the COSS 81.19% of MVG costs and 90.41 % of L VG costs are demand related. In the interest of mitigating intra- class rate impacts, the demand and commodity/delivery components were adjusted to recover 70% of MVG costs and 85% of L VG costs through demand charges. This gradual approach gives customers a price signal which better reflects the cost to provide service, while giving them an opportunity to respond to less severe price changes. At the same time, it creates only modest intra-class rate impacts. The rate design workpapers provide analysis supporting the development of this functional rate design change.
5 The UROR Analysis and the customer bil impact analysis provided as
2 Schedule JFJ-l, show that the proposed rate designs provide a reasonably
3 equitable allocation of the proposed rate increase on both an inter- and intra- class
4 basis. Furthermore, the shift of recovery into the customer and demand
S components should lessen fluctuations in customer bils due to usage levels.
6 9. Q: Have YOU performed any bilinl! comparisons?
7 A: Yes. Biling comparisons for the major rate schedules are provided in
8 Schedule JFJ-1. Schedule JFJ-1 provides the impacts of both the proposed base
9 rate increase on a stand alone basis and combined with the proposed gas cost
10 recovery (GCR) and Environmental Surcharge Rider (ESR) changes proposed in
1 1 the Company's parallel filings. Under the base rates proposed by the Company, a
12 typical residential heating customer using an average of 120 CCF in a winter
13 month wil see a total bill increase of $10.49 or 5.S%. However, when the
14 changes to the GCR and the ESR are taken into consideration, the results for a
15 typical residential customer using 120 CCF in a winter month show a bil
16 decrease of $3.08 or approximately 1.6%. On an annual basis, taking the impacts
17 of all three filings into consideration, the amount a residential customer pays
18 should remain approximately the same as current levels.
19 10. Q: Please describe how the Interim Rates were developed.
20 A: The interim rates were developed using the existing rate structure of each
21 rate class and using the interim base revenue increase of $2,SOO,000 to achieve an
22 equal percentage increase to total revenue, including fuel revenue, of 1.1 1 % for
23 each rate class. The Company is not proposing any changes to the existing rate
6 "structures". The Company is only proposing price "level" changes using the
2 existing rate structures of each rate class. The Company proposes to increase
3 each base rate component including the monthly Customer Charge within each
4 rate class by each rate class base rate percent increase, excluding fuel revenue.
5 Please refer to the Rate Design workpapers for each rate class's interim target
6 revenue increase, the biling determinants for the weather normalized test year,
7 the interim rates and the interim revenues for each rate class.
8 11. Q: What is the impact of the Company's Interim Rates on the customer's bils? 9 A: Attached to this testimony as Schedule JFJ-1 are typical biling 10 comparisons for the interim increase. With the proposed interim base rate
1 1 increase, on November 1, 2006, a typical residential customer using an average of
12 120 CCF in a winter month would see the delivery portion of the bil increase by
13 $1.84. However, when this interim increase is considered along with the
14 proposed GCR and ESR changes, the total bil will decrease by $11.73, or 6.2%,
15 from $189.62 to $177.89.
16 17 Bil Stabilization Adiustment
18 12. Q: Please describe the Bil Stabilization Adjustment (BSA) 19 A: The Bil Stabilization Adjustment (BSA) is a biling adjustment to be
20 applied on a monthly basis to the delivery charge for all firm customers. The
21 adjustment is intended to stabilize revenues based on the weather normalized test
22 year monthly revenue per customer resulting from the base rates approved in this 23 proceeding.
7 1 13. Q: What benefits are associated with the stabilization of l!as delivery revenue?
2 A: Customers benefit from a relatively stable biling level which would
3 prevent large spikes particularly during periods of cold weather. The Company
4 benefits by having assurance of a reasonably steady revenue stream in line with
5 the level of revenues approved in this proceeding. Gas usage varies widely from
6 year to year and from season to season during the year. The costs associated with
7 the delivery of gas, however, are, for the most par fixed. The BSA provides an
8 additional mechanism, along with adjustments to customer and demand charges,
9 to enable base delivery rates to recover the appropriate level of fixed costs in the
10 face of wide fluctuations in usage.
11 14. Q: Please describe the proposed method to calculate the BSA. 12 A: The BSA wil be calculated on a monthly basis and wil be developed
13 separately for each firm rate class. In a given biling month, the approved test
14 year weather normalized revenue per customer for each firm rate class is applied
15 to the actual number of customers in the biling month to arrive at a target 16 monthly revenue for each rate class. The difference between the target revenue
17 and the actual revenue form the basis for the BSA for the given biling month. To
18 avoid unduly large swings in the BSA from month to month, the Company
19 proposes to cap the level of the BSA charge or credit at 10% of the test year 20 average rate for the applicable month for each rate class. This capping
21 mechanism wil result in a level of charge or credit which wil be carried over into
22 a subsequent month's adjustment. This amount is added to the revenue
23 difference. In addition to the carryover due to the capping mechanism, an
8 adjustment wil be necessary each month to true up for over or under collections
2 in the BSA in prior months. The over/under balances wil also be added to the
3 revenue differences to arrive at a final BSA revenue targets for each rate class for
4 the current biling month. The revenue is divided by projected sales for the
5 upcoming bil period. As noted previously, this rate will be compared to 10% of
6 the rate class test year weather normalized average monthly rate to determine the
7 final BSA for the month.
8 Schedule JFJ-2 provides a series of workpapers providing an ilustrative
9 example of the BSA calculation, using test year data and proposed rates contained
10 in this fiing. The Tariff Sheets fied with this proceeding also contain a new
1 1 Section pertaining to the BSA.
12
13 Minimum Filnl! Requirements and Adiustments
14 15. Q: Are YOU supportinl! any minimum fiin2: requirements?
15 A: Yes, my testimony includes the following minimum filing requirements:
16 Schedule D Amount and Percent Increases by Class
17 Schedule No. 3A - Sales and Revenue by Class page 2 18 Rates and Tariffs
19 16. Q: Please list the proforma adjustments that you are sponsorinl!. 20 A: The pre cost study adjustments that I am sponsoring are as follows: 21 1) Bill Frequency Adjustment
22 2) PSC Assessment Annualization
23 3) Customer Adjustment
9 17. Q: Please describe the Bil Frequency Adjustment.
2 A: This adjustment was required to reconcile the minor difference between
3 actual booked base delivery revenue and the revenue as calculated using the
4 proposed billng determinants. W orkpapers supporting this adjustment are
5 included in Book 3 of this filing.
6 18. Q: Please describe the PSC Assessment Annualization Adjustment.
7 A: On September 1, 2005, the PSC Assessment rate embedded in the
8 Company's rates was increased from $0.002 per dollar of revenue to $0.003 per
9 dollar of revenue retroactive to January 1, 200S. As a result the rates from
10 September 1, 2005 to December 31, 200S were set at a level to recover the new
11 higher assessment rate plus whatever was necessary to make up the difference in
12 the assessment during the initial eight months of 2005. Since the test year
13 encompasses a period before, during and after this rate compression period, the
14 level of the PSC Assessment included in test year per books revenues is higher is than the appropriate anual leveL. To adjust for this, the revenues calculated by
16 month using the actual rates in effect during the period were compared to
17 annualized revenues using rates effective on March 1, 2006. The difference
18 between these amounts has been classified as the PSC Assessment Annualization
19 Adjustment. W orkpapers supporting this adjustment are included in Book 3 of
20 this fiing.
21 19. Q: Please describe the Customer Adjustment.
22 A: This adjustment was required to remove the impact of a meter constant
23 error involving several customers served on the L VG and MVG rate schedules.
10 The overall impact is to reduce sales and revenues by the indicated levels. The
2 impact of this adjustment is included in the Biling Determinant workpapers
3 included in Book 3 of this fiing.
4 5 Tariff Changes
6 20. Q: Are you supportinl! any other chanl!es to the Company's Gas Tariff?
7 A: The Company is proposing to increase the Reconnection fee and the Premise
8 Collection fee. The Company is proposing to increase the premise collection fee
9 from $15.00 to $38.00. The current fees for reconnection are on a sliding scale
10 from $30 to $90 depending on when the restoration is requested (work-day,
1 1 weekend and holidays, after hours). The proposed restoration fees are based on
12 the same sliding scale design with fees ranging from $75 to $175. The approval
13 of these fees will result in making the fees for these services consistent with the
14 Company's electric tariff fees previously approved by the Commission. The
15 proposed fee structure wil bring them more in line with the costs associated with
16 their related activities. To establish the target revenue to be recovered via firm
17 base rates, the overall revenue requirement of $14,967,412 has been adjusted to
18 remove the increased revenue of $13,222 associated with the modification of
19 these fees. The new fee structure is provided in the modified tariff sheets
20 included in this filing. Workpapers supporting this adjustment are included in
21 Book 3 of this fiing.
22 21. Q: Does this conclude your testimony?
23 A: Yes, it does.
11 Schedule JFJ-1 DELAWARE GAS BILLING COMPARISON Page 1 of 16 RESIDENTIAL fRI & RESIDENTIAL SPACE HEATING rRSHl
Current Rates Effective January 1, 2006 vs. Proposed Rates Effective April 1 , 2007 Delivery Rate Only ANNUAL - ol SUMMER & a WNTR 4 SUMMER _ TOTAL BILL PER MONT AT CONSTANTMONTLY USAGE 8 WNTR - TOTAL BILL PER MONT ANNUAL iMPACT. TOTAL BILL Present MONTHLY Present ProPosed Total Proposed Present Proposed Total Annual Annual Total SN.ES Base GCR Total Base GCR Total %OlFF Base GCR .Q ru &! §f !2 .Q Total OIFF, %DIFF (CCF) ~ .I " $840 SOljl) $840 $1227 $000 $1227 $367 451% $840 $000 $84') $1227 $0')1 $1227 $387 461% $10080 $14724 "644 461% , $875 $118 $994 $1268 $118 $1386 $392 394% $876 $118 $994 $1268 $118 $1386 $392 394% $11928 $16632 '" 04 394% , $911 $237 $1148 $1309 $231 $1546 $396 ,,,% $911 $237 $1148 $n')9 $237 $1546 $398 ,,,% $H176 , $947 $35S $13')2 $1351 $355 $1706 310% $18552 $4776 ,,,% "," $947 $355 $n02 $1351 $355 $1705 " 04 310% $15624 $20472 $4848 310% 4 $983 $1457 $1392 $1866 $409 281% "" "" $963 "" $1457 $13,92 $1866 $4 09 281% $17484 $22392 $4908 281% 5 $1018 $592 $1610 $1433 $592 $2025 258% "" "15 $1')18 $592 $15W $1433 $592 $2025 $415 258% $193.20 $24300 ,., $1191 $1164 $2381 $1639 $1164 $2823 186% $4980 258% "" $1197 $1184 $2381 $1639 $1184 $2823 $4 " 185% $28572 166% 'oj $1554 $2368 $3922 $2.)51 $2368 $419 " 97 127% $33816 $5304 $1554 $23 68 $3922 $2')51 $2368 $4 19 "97 12.7% $47064 $53028 $5964 127% 25 $1732 $2960 $4692 $2257 $2961) $52.17 $525 '12% $1732 $296') $4592 $2257 $29.60 $5217 $525 112% $56304 $62604 112% 40 $2258 $4735 $7003 $2816 $4735 $7611 $6oJ6 ,,% $6300 $2268 $4735 $1003 $2876 $4735 $1511 $506 ,,% $84')36 $91332 59 $2982 $7103 $10(185 $3700 $7103 $10803 $718 ,,% $7296 ,,% $2929 $7103 $10032 $3548 $1103 $10751 $119 ,,% $1,20596 $1.9220 $8624 79 $3660 $9352 $130\2 $4 " $9352 $13835 $823 ,,% .,% $3508 $9351 $12660 $4331 $9351 $13563 $823 5.4% $1,54928 $1.548.04 $9876 100 $4 09 $11838 $16247 $5349 $1\838 $1787 $9.40 5.8% ,,% $4141 $11838 $15985 $5085 $11838 $169.24 $939 5.9% $1,92868 $2.04140 $11272 12. $5123 $14206 $19329 $6173 $14206 $20379 $1'150 ,,% ,,% $4756 $14205 $18962 $58.05 $14206 $20011 $1049 55% $2,29012 $2,41604 $12592 55% 140 55637 $16574 $22411 $6997 $16514 $23511 $1160 ,,% $5354 $16574 $21938 $6524 $16574 $23098 $1160 ,,% $2,65148 $2.9068 $13920 '" $6551 $18941 $25492 $1821 $16941 $26162 $1270 ,,% ,,% $5973 $18941 $24914 $1243 $18941 $26184 $1270 51% $3.01280 $3,16520 $15240 51% 180 $7265 $213')9 $26574 $8646 $21309 $29955 $1361 ,,% $6582 $21309 $27891 $7963 $21309 $19172 $1381 5.0% $3,31424 $3.53996 $165,72 ,,% 2M $7979 $23677 $31656 $9470 $23677 $33147 $1491 4.7% $7191 $23617 $30658 $8681 $23617 $32359 $lol91 ,,% $3.735.68 $3,91460 $17892 48% 22 $8692 $26')44 $34736 $102,94 $26044 $36338 $1602 ,,% $1799 $26044 $33843 $94"1 $26044 $35445 $1602 ,,% $4.')9688 $4,28912 $19224 ,,% 240 $9406 $26412 $37818 $11119 $26412 $39531 $1713 ,,% $8406 $28412 $36820 $10120 $26412 $38532 $1712 ,,% $4.45832 $4,66380 $105ol8 ,,% 2M $10120 $30780 $40900 $11943 $30760 $42723 $1823 ,,% $9')17 $30181) $39797 $10839 $30780 $41619 $1622 ,,% $4.131976 $5,03844 280 $10834 $33148 $43962 $12761 $33148 $45915 $1933 "% $21868 ,,% $9526 $33148 $42174 $11559 $33148 $44707 $1933 ,,% $5.18120 $5.41316 $23196 30') $115.48 $35515 $47063 $13592 $35515 $491.)7 $2044 43% ,,% $10234 $35515 $45749 $12278 $35515 $477 93 $2044 ,,% $5,54244 $5.18172 $24526 ,,%
CUSTOMER WRW & "RSH- RATE 1$..CFl SUMMER WINTER CHARGE 1ST BLOCK TAIL BLOCK PRESENT $840 ~$0356930 $0356930 $0304370 PROPOSED $1227 $0412150 $0412150 $0359590 ~onmentaISurchargeRl,jer '$ Pr-:posed Envronmental Surd'arçe Ri.jer 000138
PRESENT GCR $11836400 IMCF OR $1183840 ICCF PROPOSED GCR $11838400 hvCF OR $1183640 ICCF DELAWARE GAS BILLING COMPARISON Schedule JFJ.1 GENERAL GAS (GG) Page 2 of 16
Current Rates Effective January 1, 2006 vs. Proposed Rates Effective April 1, 2007 Delivery Rate Only
4 SUMMER _ TOTAL BILL PER MONT 8 WNTR - TOTAL. BILL PER MONT ANNUAL IMPACT. TOTAL BILL MONTHLY Present Proposed Total Present PrOPosed Total Total SAlES OCR Total Basi DIFF. ~ Q£ Base OCR Q£ W! %DIFF PRESENT PROPOSED OIFF, %DIFF (CCFj ~ ~ I2 ~ .. .) $1900 $000 $1900 $3282 $000 $3282 $1382 727% $1900 $1)01) $19..)0 $3282 $01)1) $3282 $1382 727% $2281)0 $39384 $16584 721% 25 $2705 $2960 $5665 $4199 $2960 $7159 $14!W 264% $271)5 $2960 $5665 $4199 $2960 $1159 $1494 26.4% $61980 $85908 $17928 264% 5. $3510 $5919 $9429 $5117 $5919 $11036 $1607 170% $3510 $5919 $9429 $5117 $59.19 $11035 $161)7 110% $t.3148 $1,32432 $19284 11,0% 75 $4315 $8879 $13194 $6034 $8879 $14913 $1719 131)% $4315 $8879 $131.94 $5034 $8879 $14913 $1719 131)% $1.58328 $1.8956 $21)628 130% 1')0 $5120 $11838 $16958 $6951 $11638 $18789 $1831 108% $5120 $11838 $16958 $5951 $11838 $18789 $1831 108% $i.)3496 $2,25468 $21972 108% 200 $8339 $23671 $32016 $10620 $236.77 $34297 $2281 71% $8339 $236,77 $32016 $10520 $236.77 $34297 $2281 71% $3.84192 $4.11564 $21312 71% 300 $11559 $35515 $47074 $142.89 $35515 $49804 $2730 58% $11559 $35515 $41074 $14289 $35515 $4981)4 $2730 58% $5.64888 $5,97648 $32760 58% 41)0 $14778 $47354 $62132 $17958 $47354 $65312 $3180 51% $14718 $47354 $62132 $17958 $41354 $65312 $3113 51% $1,45564 $1,83144 $38160 51% 500 $17998 $59192 $77190 $21627 $59192 $80819 $3629 47% $11998 $59192 $11190 $21627 $59192 $80819 $3529 47% $9.26280 $9.69828 $43548 47% 1000 $31884 $1.8384 $1.5.)268 $37726 $1.8384 $1.56110 39% $5842 $31884 $1.18384 $1.50268 $31126 $t.8384 $1,55110 $5842 39% $18..)3216 $18.1332') $701,)4 39% 1501) $43557 $1,77576 $2,21133 $51571 $t,7516 $2.29153 $8021) ,,% $43551 $1.77576 $2,211:B $51577 $1.7576 $2.29153 $8020 35% $26,53596 $27,4836 $96240 35% 21)1)) $55230 $2,36768 $2,91998 $65428 $2.36768 $3.02196 $10198 35% $5523') $2,36768 $2.91998 $65428 $2,35168 $3.0196 $1')198 35% $35,03976 $36,25352 $1.22315 3.5% 2501) $66903 $2,95960 $3,62863 $19279 $2,95960 $3.75239 $12376 34% $66903 $2.95960 $3.62853 $19279 $2,959.60 $3.75239 $12376 34% $43,54355 $45,02868 $1,48512 34% 30')0 $18516 $3,55152 $4,33728 $93130 $3,55152 $4,48282 $14554 34% $78576 $3,55152 $4.33728 $93130 $3.55152 $4.48282 $14554 34% $52,04735 $53.79384 $1,74648 34% 3500 $90249 $4.14344 $5,1)4593 $1,06981 $4,14344 $5,21325 $16132 33% $90249 $4,14344 $5.04593 $1,06981 $4.14344 $5.21325 $15732 33% $60,55115 $62.5591)1) $2.00784 3.3% 4.'" $1,01922 $4.13536 $5.75458 $1.0832 $4.73536 $5,94368 $1891') 33% $1,01922 $4.73536 $5.75458 $1,20832 $4.13536 $5,94368 $1891') 33% $69,05496 $71.2415 $2,25920 33% 4500 $1,13595 $5,32128 $6,46323 $1,34683 $5,32728 $6,614,11 33% $21088 $1,13595 $5,32128 $6,46323 $134683 $5,32128 $6,57411 $21088 3.3% $77,55876 $8'),089.32 $2,53056 33% 5.'" $1,25268 $5.91920 $7.11188 $1,48534 $5,91920 $7,404 54 $23266 32% $1.5268 $5,91920 $1,17188 $1,48534 $5.91920 $1.41)454 $23266 12% $85.05256 $88,85448 $2.9192 32% MOi) $1,48614 $1,1')304 $8,58918 $t,6236 $7,103.04 $8.86540 $27622 32% $1,48514 $7,103')4 $8,58918 $1,76236 $1.103.04 $8,86540 $27622 32% $103,01016 $106.38480 $3.31464 3.2% 11)0') $1,11960 $8,28688 $10,00648 $2,1)3938 $8,28688 $10,32626 $31978 32% $1.71960 $8,26688 $10,00648 $2,03938 $8,28688 $10,32626 $31918 32% $120.07776 $123,91512 $3.83736 32% 80M $1,95306 $9.47072 $11.42318 $2,31641) $9,47072 $tt.18712 $36334 32% $1.95306 $9,47012 $11,42318 $2.31640 $9.47072 $11.78112 $35334 32% $137,08536 $141,44544 $4.35008 3.2% 90')1) $2,18652 $10.65456 $12.84108 $2,59342 $10,65456 $13,24198 $40690 32% $2.18652 $10.65456 $12,84108 $2.59342 $10,654,55 $13,24798 $4059') 32% $154.09296 $158.97576 $4.88280 32% 10000 $2.41998 $11.83840 $14,25838 $2.87044 $11,83840 $14,70884 $45046 32% $2,41998 $11.83840 $14,25838 $2,810.44 $11,83840 $14.70884 $45046 32% $17t.O')55 $175,50608 $5,40552 32% 12000 $2.88690 $14.20608 $17.09298 $3,42448 $14,20608 $11,63055 31% $53158 $2.88690 $14.20608 $17.09298 $3,424.48 $14,20508 $17.63056 $53758 31% $205.11576 $211.56672 $6,45096 31% 14000 $3.35382 $16,57376 $19.92158 $3.97852 $16.57316 $20.55228 $62470 31% $3,353.82 $16,57376 $19,92158 $3,91852 $16,57376 $20,55228 $62410 31% $239,13096 $246,62136 $7,49640 31% 16000 $3,82014 $18,94144 $22.75218 $4,53255 $18,94144 $23,4141)1) $1tt82 31% $3.82014 $18.94144 $22,762.18 $4,53256 $18.94144 $23,4400 $71182 31% $273,14616 $281.68800 $8,54184 31% 18000 $4,28156 $21.')912 $25,59518 $5.08550 $21,30912 $25.39572 31% $198.94 $4,28165 $21.0912 $25.59678 $5,08660 $21,30912 $26.39572 $79894 31% $31)7.\6136 $315.14864 $9.58728 31% 2001)0 $4,75458 $23,67680 $28,43138 $5,64064 $23.67680 $29,31744 31% $886.06 $4.754.58 $23.67681) $28.43138 $5,64064 $23.67680 $29,31744 $88606 31% $341.11656 $351,Si928 $10.63272 31%
CUSTOMER SUMMER WINTER "GG" RATE /$/CCFJ CHAAGE 1ST 750CCF ::750CCF 1ST 750CCF ::750CCF PRESENT $1900 $0321950 $0233460 $0321960 $0233460 PROPOSED $3282 $0366900 $0271020 $036690 $0277020
PRESENT GCR $11 836400 IMCF OR $1183840 JCCF PROPOSED GCR $ 11 836400 IMCF OR $1183840 ICCF Curent Environmental Surhare Rider 000138 Prop-:se,j Environmental Surdlarge Rider 000138 DELAWARE GAS BILLING COMPARISON Schedule JFJ-1 MEDIUM VOLUME GAS (MVGI Page3 of 16
Current Rates Effective January 1, 2006 vs. Proposed Rates Effective April 1 , 2007 Delivery Rate Only
MonlNy 4 SU..ER. TOTAL BILL PER MON 8 WINTR. TOTAL BILL PER MONT ANUAL IMPACT. TOTAL SILL Sales Load Present Proposed Tolal Present Proposed Tolal Fador Totl Bas. OCR Tolal lM MQ !- !! Tot" .Q B... OCR Total Bas. Total PROPOSED :& !! .Q :& ~ DIFF. :& 500 66 25 $1.211 $5,923 $7.134 $1,557 $5,923 $7.480 4.9% $37 $1211 $5.923 $7.134 $1.557 $5,923 $7.480 $37 4.9% $8.606 $8,764 $4.158 500 33 50 $87' $5,719 $6,585 $1.04 $5,719 $6.764 $17B 2.7% .... $87' $5.719 $6,592 $1,04 55.719 $6,764 $171 2.6% $79,080 $81.163 $2.083 2."" 500 22 75 $761 $5,650 $6.405 $87' $5.650 $6.525 1.9% $120 $761 SS.650 $6.412 $87' $5,650 56,525 $113 1... $76,914 $78.296 $1.382 1... 1,000 13 25 $2.106 $11.846 $13.939 $2.799 $11.846 $14.646 $707 5.1% $2.106 $11.846 $13,953 $2,799 $11,846 $14.646 $693 5.0% $167.376 $175.748 $8.3n 5.0% 1.000 66 50 $1.32 $11.437 $12,856 $1,775 $11.437 $13.212 $36 2... $1.432 $11.437 $12,870 $1,775 $11.437 $13.212 $33 2.7% $154,379 $158.546 $4,167 2.7% 1.000 44 75 $1.208 $11,301 $12.495 $1.434 $11.301 $12.13 $240 1.9% $1.208 $11.301 $12,509 $1.34 $11.301 $12.134 $26 1... $150,041 $152.812 $2,765 1... 2.000 263 25 $3,887 $23,686 $27,546 $5.268 $23.686 $2.955 $1.08 5.1% $3.887 $2.686 $27,574 $5.268 $23.686 $2.955 $1,381 5.0% $30.715 $37.455 $16,680 2.000 13 50 $2.550 $2.874 $25.397 $3.235 $2.874 5... m,109 $713 2... $2,550 $2.874 52.424 $3.235 $2,874 $26,109 $65 2.7% S3.978 $313.311 58.333 2.7% 2,000 88 75 $2.101 $2.601 $24,674 $2,552 $2,601 $25.154 $479 1.9% $2,101 $22,601 $24,102 $2,552 $2,601 $25,154 $42 1... $296,314 $31.84 SS,529 1... 3,000 395 25 $5.679 $3,533 541.170 $7.753 $3,533 $4.285 5.1% $2,115 $5,679 $3.533 $41.211 $7,753 $3,533 54,285 $2,074 5... $494,371 $519,423 $25,052 5.1% 3.000 197 50 $3.657 $3.305 $37.921 $4,660 $34.305 $3,985 $1.64 2... $3,657 $3 .305 $37.962 $4.680 $3.305 $3,985 $1.023 2.7% $45,381 $467.816 $12.436 2.7% 3.000 13 75 $2,993 $3.902 $3.85 $3.671 $33.902 $37.573 $119 2.0% $2.993 $3,002 $36.896 $3.671 $3,902 $37,573 $677 1... $42,581 $40.875 $8.294 1.9% 4.000 526 25 $7.460 $47,373 $5,777 $10,221 $47,373 $57.594 $2,817 5.1% $7,460 $47,373 $5.833 $10.221 $47.373 $57,594 $2,762 5.0% $657,770 $691.130 53.361 5.1% 4,000 263 50 $4.774 $4,742 $5,462 $6,140 $4,742 $51,882 $1.420 2... '$,774 $4.742 $50.517 $6.140 $4,742 $51.882 $1,365 2.7% $605,980 $622.582 $16,602 2.7% 4,000 17 75 $3.876 $45,197 $49,018 $4,774 $4,197 $49.970 $953 1... $3,876 $4.197 $49.073 $4.774 $45.197 $49,970 $88 1... $58,651 $599.646 $10.995 5,000 658 25 $9.251 $59.219 $68,401 $12,706 $59,219 1... $71,925 $3,524 5.2% $9.251 $59.219 $68.470 $12,706 $59.219 $71,925 $3,455 5.0% $81.366 $83.098 $41,733 5.1% 5,000 329 50 $5.892 $57,179 $63,002 $7,600 $57,179 $6,779 $1.77 2... $5.892 $57,179 $63.071 $7,600 $57.179 $6.779 $1.08 2.7% $756,579 $777.48 $20,769 2.7% 5,000 219 75 $4.169 $5.497 $61,197 $5.892 $5.497 $6,390 1.9% $1,193 $4,769 $56,497 $61.266 $5.892 $5.497 $62,390 $1.124 1... $73,918 $748.677 $13.760 1.9% 6,000 789 25 $11.032 $71,059 $8.009 $15,175 $71.059 $8.23 $4.225 5.2% $11.032 $71.059 $8.091 $15,175 $71.059 $8.23 $4.143 5.0% $98,765 $1,034,806 $5.041 5.1% 6.000 395 50 $7.009 $6,616 $75.543 $9,060 $6,616 $n ,616 $2,133 2... $7.009 $6,616 $75,626 $9,060 $68,616 $n.676 $2,050 2.7% $907,178 $932,113 $24,935 2.7% 6.000 263 75 $5,662 $67,798 $73.377 $7,011 $6,798 $14,809 $1432 2... $5,662 $67.798 $73,460 $7,011 $67,798 $74,809 $1349 1... $81,185 $87.709 $16.524 1.9% 7,000 921 25 $12,823 $8.906 $95,632 $17,659 $8.906 $100,564 $4,932 5.2% $12,823 58,906 $95.n9 $17,659 $8,906 $100,564 $4,836 5.1% $1.148.360 $1,206,774 $5.413 5.1% 7,000 '61 50 $8,127 $8.05 $8.08 $10,520 $8.05 $90.573 $2.489 2... $8.127 $8.05 $8,180 $10,520 $8.05 $90.573 $2,393 2.7% $1.057,777 $1.086,879 $2.102 2... 7,000 307 75 $6,554 $79.099 $8,557 $8.130 $79.099 $87,228 $1.72 2.0% $6.554 $79.099 $8.653 $8.130 $79,099 $87.228 $1.575 1... $1.027.452 $1,046,741 $19.289 1.9% 8,000 1,053 25 $14,615 $9,752 $109,256 $2,143 $94,152 $114,895 $5.639 5.2 $14.615 $94,752 $109,366 $2,143 $94,752 $114,895 $5.529 5.1% $1,311,956 $1.318.741 $66.785 5.1% 8,000 526 50 $9.234 $91.48 $100,608 $11,96 $91 ,48 $103.449 $2,840 2... $9.234 $91.48 $100,718 $11,964 $91.48 $103.449 $2,730 2.7% $1,208,179 $1.241.38 $3.205 2.7% 8,000 351 75 $7.447 $90,399 $97,736 $9,248 $90,399 $9.648 $1,911 2... $7.447 $9,399 $97.847 $9.248 $90.399 $99,648 $1.801 1... $1.17.718 $1.195.772 $2.05 1.9% 9,000 1,184 25 $16,396 $106,592 $122,864 $2,612 $106,592 $129,204 $.34 5.2% $16.396 $106,592 $122.988 52,612 $106.592 $129,204 $6,216 5.1% $1,415,355 $1.550.449 $75,093 5.1% 9,000 592 50 $10.351 $102.922 $113,149 $13,424 $102,922 $116,34 $3,197 2.8% $10.351 $102.922 $113.273 $13,424 $102,922 $116,346 $3.073 2.7% $1.358,779 $1,396,150 $37.371 2.8% 9,000 395 75 $8.340 $101,700 $109,916 $10,367 $101.700 $112,061 $2,151 2... $8.34 $101.100 $110.40 $10,367 $101.00 $112,061 52.027 1... $1,319.985 $1,34.80 $24,818 1... 10.000 1,316 25 $18.187 $118.438 $136,487 $25,097 $118,438 $143,535 $7.041 5.2% $18,187 $118.438 $136,625 $25,097 $118.438 $143.535 $6.910 5.1% $1638,951 $1.722.417 $8.466 5.1% 10,000 658 50 $11,469 $114,359 $125,690 $14,88 $114.359 $129,243 $3,553 2... $11,469 $114.359 $125,827 $14,88 $114,359 $129.243 $3,416 2.7% $1,509,378 $1,550.916 $41.538 2... 10.000 .39 75 $9,233 $113,001 $122,096 $11.485 $113,001 $124,486 $2.300 2... $9.233 $113,001 $122,234 $11,485 $113.001 $124,486 $2,253 1... $1,466,252 $1,493,835 $27,583 1.9%
CUSTO~R DEMD COMMODITY "MG- RA TE lWCF C~RGE CHiRGE CHiRGE OellvervRale PREseNT $315,00 $10.21 $0.429790 PROPOSED $48.39 $15.52 $0.421950
GCR PRESENT $6.2000 $11.027900 PROPOSED $6.2000 $11.027900 ~rlrorrentil SlJcha'ae PRESENT 0.01377 PROPOSED 0.01377 DELAWARE GAS BILLING COMPARISON Schedule JFJ.1 LARGE VOLUME GAS (LVGl Page 4 of 16 Current Rates Effective January 1, 2006 vs, Proposed Rates Effective April1, 2007 Delivery Rate Only M,n\hly Si.MER. TOTAl BILL WINT. TOTAL BIll AtAlIMPACT. TOTAl BILL S." l"" Present Pi-posed Total Present MOO ¡:a¡t'J( T"oJ Proposed Total Total ll !! = !! GCR Q! Base GCR Base GCR Total "FF. ~ ~ ~ ~ PREser PROPOSED "FF. %OIFF 5.000 6,. is 55.718 $59.219 $51.937 $7,319 559.219 $66.538 $1.601 2'" 15.718 159.219 $64,937 17.319 5,000 329 50 $3,402 $51,179 $59.219 $66.538 $1.601 25% $779,247 1798,451 $19.215 25% 550.581 $4.322 $57,179 $61,501 $920 15% $3,402 $57,179 $60,581 $4.322 557.179 5.000 219 15 $2,628 $56.497 $61,501 $920 15% $726.975 1738.017 $11.042 15% $59,125 $3,320 556,497 $59.817 $592 12% $2,628 $56,497 $59,125 53.320 556.497 10.000 1,316 25 $10,936 $118.438 $129.374 $59,817 $892 12% $709,498 5717.808 18.310 12% $13.915 $118,438 $132.353 $2.979 23% 510,936 $118.438 1129,314 $13.915 $118.438 1132.353 10,000 6" 50 $5.304 $114,359 $120.663 $7,920 12,979 23" 11.552.493 51.588.237 135.743 23% $114,359 $122219 $1,617 13% $6.30 $11,(.359 1120.663 $7.920 $114.359 $122,279 11,617 10.000 439 15 $4.762 t113.OCJ1 $117,163 $5,925 13% $1,447.950 $1.~67.349 $19,399 13% $113.001 $118:926 $1,153 10% $4.762 $113,001 $117,763 $5,925 $113,001 $118.925 $1.163 15,000 1,974 25 $16.154 $177,657 $193,812 $20.510 10% $1,413,156 $1427,11/1 $13,959 10% $177.657 $198.168 $4.355 22% 516.154 $17,557 $193.812 120,510 $177,657 $196,168 $4.356 15,000 967 50 $9,206 $171,538 $180.744 $11,519 22% $2,325,740 $2,378,012 $52.272 22% $171.538 $183.057 S2.313 13% $9,206 $171,538 5180,744 111.519 $171,538 1183,057 52.313 15.000 6,. 15 $6.890 $169.498 $176,388 $8.522 $169,498 ,,% $2,158.925 12,196.681 $27.755 ,,% t178,020 $1.632 09% 16,890 1169.498 5176.388 $8,522 1159.498 1178.020 $1,5:2 09% 20,000 2,632 25 $21.72 $2'6.616 $258.249 $21,106 $236.816 12.116.65 12.136.237 $19.583 09% $263.982 $5.733 22% $21.372 1236.876 $258,2.(9 127,106 1236,876 $263.982 $5.733 22% 20,000 1.316 SO 112.108 $228,711 $240.625 115,117 1228,717 $243.83 $3098,987 13.167,788 $68,801 22% $3.009 1.2% 112.108 1228,717 5240,825 $15,117 $228,717 1243,83 $3,009 12% 12.669,900 20,000 an 75 19,01 1225.995 1235,013 $11,118 1225,995 1237.113 12,926,012 $36,112 12% 12.101 09% 19,017 1225,995 1235,013 $11,118 1225,995 1237,113 12.101 09% 12.820,152 12.845,359 25,000 3.289 25 $26.584 $296,089 $322,673 $33.692 $296.089 $:m,782 $7,109 125,207 09% 2.2% 126,584 $296,089 $322673 $33.692 $296.089 1329,782 $7,109 22% 13.87207.( $3,957,360 25,000 1.645 50 $15.010 $285,897 $300,906 $18,716 $285,897 $30,612 $85,305 22" $3,706 12% $15.010 $285.897 $300,906 $18.716 $285.891 $30,612 $3,706 12% $3.610.876 25.000 1.09 75 111,145 $282,493 $293.638 $13.114 $282.493 $296,207 53.55,34 $4..(68 12% $2.569 09% $11,145 $282,493 $293.638 $13,714 $282,493 $296,201 $2,569 09% $3.523,650 $3,55.,482 30.000 3,947 25 $31,602 $355.306 $381.110 $4.266 $355.306 $395,596 $30,831 09% $8.466 22% $31.802 $355.306 $387,110 $.0.266 $355,308 $395,596 $8,-46 22% $4,&15.321 30,000 1,914 50 $17,912 1543.076 $360,988 $22,314 $543.076 $365.390 $4,7.(7, !55 $101,8J 22% $4.402 12% $17,912 $343,075 $360.988 $22,31,( $343,075 $365,390 $.,.(02 12% $..331,851 30,000 1,316 75 $13.219 $336.996 $352,276 $16,319 $338,996 1355.316 $4,38,675 $52,825 12% $3,040 09% $13,279 1338.996 1352,276 116,319 $338,996 5355.316 $3.040 09% $4.227,308 35,000 4,605 2S $37,020 $414,528 $451.547 $46,883 $414,528 S41.41\ $..263.788 $36,~80 09% $9.86 22% $37,020 $414.528 $.51,547 $.6,883 $41.(,528 $.61,411 $9.864 22% $5,418,568 35.000 2,303 50 $20.814 $400.255 $421,069 $25.912 $400,255 $5,536,931 $118,363 22% $426,167 $5,098 12% $20,81/1 $400,255 $421,069 $25,912 $.00,255 S126,167 $5,098 12% 35,000 1,535 7S 115,407 $395.494 $410,901 118.916 $395,494 $5,052,825 $5,114,007 $61.82 12% $414,4£9 $3.509 09% $15,'/07 $395,,(94 $410,901 $18,916 $395,494 $414.,(09 $3.509 09% $4,930,805 40,000 5.263 25 $42.238 S473,747 $515,985 $53,479 $413747 1527,226 $4,972910 $42,104 09% $11.2"1 22% $42,238 $413,M7 $515,985 $53,.(79 $473,7.(7 $527.226 $11,2/11 22% $6,191,8M 40,000 2,532 50 $23.116 $457."34 $41,150 $29,511 $457.434 $46,945 56,326.706 $134,892 22% $5.795 12% $23.116 $.57,./34 $41,150 $29,511 $.57,.(34 $46,945 $5,795 12% ,(0.000 1.54 75 $17.535 $451,991 S489,525 121,512 $.51.991 $.73.503 $5,n3,BOl $5,843,339 $69,538 12% $3977 08% 517,535 $.51.991 $.69,525 $21,512 $.51.991 $.13503 13.977 08% $5.63,304 $5.662,033 50.00 6.579 25 152.67.( $592,185 $54,859 $66,670 1592,185 5658.855 113.996 22% $.7.729 08% $52.674 5592.185 554,859 165.570 $592,185 5558,855 $13.996 22% $7.738.308 $7,906,257 50,000 3,289 50 529,513 $511.87 $601,299 $36,698 $511.87 $608.485 $7,186 12% $167.950 22% $29,513 $571,787 $501,299 $36.698 $571.187 $506,85 $7,186 12% 17,215.592 $7,301.819 50.000 2,193 75 $21.97 $56,992 $586,788 $2ß,714 $56,992 5591.05 $4.917 $86,22ß 1.2% 08% $21.797 $56,992 $586,188 525,71,( 156,992 $591,705 $4.917 08% $7.041,460 60.000 7,895 25 563,110 1110.623 $773,733 519,861 1710,623 $790..i 116.751 $7.100.462 $59.02 08% 22% 15:,110 1710,623 5773,733 $79,861 1710.623 1790,484 116.751 22% $9.2S,801 $9,-45.809 60,000 3,947 50 $35.316 1666.145 $121.462 $43,895 $685,1.5 $730,040 $8,518 1,2% $201,006 22% 135.316 $686,145 $721,462 $43.895 1685.145 $730,040 58,578 12% $8,657,513 $8.760.482 1102,939 60,000 2,632 75 $26,059 $677.992 $7U',051 $31,915 $677,992 $709,906 $5,856 0.8% 12% $2ß,059 $677,992 $704,051 $31,915 $677,992 $709.908 $5,856 08% $8..48,615 $8,518,690 $70,275 08% 70,000 9,211 25 $73,547 $829.061 $002,60 $93,052 $829.061 $922,113 $19,505 2.2% $13.5.7 $829.061 $902.608 $93.052 $829.061 $922,113 $19,505 22% $10,831,294 $11,055,350 $23,066 22% 70,000 4.605 SO $41.20 $800,50 $841.624 $51,091 $800,50 1851.595 $9,971 1.2% $41,120 $800,50 $841,62.( $51,091 $800,50 $851.595 $9,971 12% $10.099,493 $10,219,1.(5 $119,553 12% 70.000 3,070 75 $30,31,( $790,987 $821,301 $37.108 $790,967 $lmm5 $6.794 0.8% S3O.314 $790,987 $821.301 $37.108 $790.987 $828.095 $6,794 08% $9,855,612 $9,937.135 $81.523 08%
OJSTOMER DEMAND COMMODTY DtJietRâtl Q-ARGE Q-ARGE Q-ARGE PRESOO $50000 17040000 1010339 PROPOSED $n380 $9110000 1010546 OCR PRES8' $6200000 $11027900 PROPOSED $6200000 $11027900 ErlronmerlalSlm::ham!l PRESEN 001377 PROPOSED 001377 Schedule JFJ-1 DELAWARE GAS BILLING COMPARISON Page 5 of 16 RESIDENTIAL (Rl & RESIDENTIAL SPACE HEATING (RSH)
Current Rates Effective January 1, 2006 vs. Proposed Rates Effective April1 , 2007 Delivery, GCR and Environmental Surcharge Rates ANNUAL ,4 SUMMeR &8 WNTR AT CONSTANTMONTLY USAGE 4 SUMMER. TOTAL BILL PERMONT 8 WNTR, TOTAL BILL PER MONT ANNUAL IMPACT - TOTAL BILL Present Proposed MONTHLY Present Proposed Total Present Proposed Total Annual Annuii Total $.AES QÇ Total Base GCR Base GCR Total ll ~ .Q Base GCR .Q Total Total D1FF. (CCF) ~ .! ~ " ~ $840 $'JO') $840 $1227 $00-) $1227 $367 461% $840 $000 $840 $\227 $000 $1227 $387 451% $1')080 $14724 $4644 461% , $876 $118 $994 $1266 $107 $1375 $3al 383% $876 $118 .", $1258 $107 $1375 $381 383% $11928 $16500 $4572 383% , $911 $137 $1148 $1310 $214 $1524 $376 328% $911 $237 $1148 $131') $214 $1524 $376 328% $13776 $18288 $4512 328% 3 $947 $355 $1302 $1351 $321 $1572 $370 284% $947 $355 $1302 $1351 $321 $1672 $370 284% $15624 $20064 $4440 284% , $9.83 $..74 $1457 $1392 $1820 $363 249% .", $9.83 .", $1457 $1392 .", $1820 $363 249% $17484 $21840 $43.56 249% 5 $11)18 $592 $1610 $1434 $535 $1969 $359 223% $1018 $592 $1610 $1434 $535 $1969 $359 223% $19320 $235.28 $43')8 223% " $1197 $1184 $2381 $164') $1')70 $27,11) $329 138% $1197 $1184 $2381 $1640 $1')7i $271i $329 138% $28572 $32521) $3948 138% ,oJ $1554 $2358 $ag 22 $2053 $21.40 $4193 $271 "" $1554 $2368 $3922 $2053 $2140 $4193 $271 69% $47054 $5'J315 $3252 is $1732 $2960 $4692 $2260 $2674 $4934 $242 "" 52" $1732 $295') $4692 $2260 $2674 ." " $242 52" $56304 $592.08 $2904 4" $2268 $4735 $7003 $28 B') $4279 $7159 52" $156 "" $2268 $4735 $70')3 $28M $4279 $7159 $156 $84ù36 $85908 $18.72 '" $2982 $7103 $10085 $37Q6 $6419 $10125 "" "" $040 ",,, $2929 $7103 $10'J32 $3654 $5419 $1'J073 $')41 ')4% $1,2')596 $1,21064 ')4% 79 $3660 $9352 $13012 $4491 $8451 $12942 som -05% .", $3508 $9352 $12860 $4339 $8451 $12790 "07", .05% $1,54928 $1,54088 $840 -05% 10') $44139 $11638 $16247 $53 S9 $lQG98 $16057 -12% ($19'3) $4147 $11838 $15985 $5096 $10598 $15794 ($191) -12% $1.92858 $1.90580 -12% Ill) $5123 $142')5 $193.29 $6185 $12837 $19022 -16% ($2288) ($31)7) $4755 $14205 $16962 $5817 $12837 $18654 ($308) .15% $2.29012 $2,25320 -15% "" $5837 $16574 $22411 $7011 $14977 .19% ($3692) $21968 ($423) $5354 $15574 $21938 $5538 $14977 $21515 ($423) -19% $2.65148 $2.0072 -19% 1M $5551 $16941 $25492 $7837 $17116 $24953 -21% ($5076) ($539) $5973 $18941 $24914 $7259 $17116 $24375 ($539) -22% $3.01280 $2.94812 -21% "" $7265 $21309 $28574 $8654 $19256 $27920 -23% ($6466) ($654) $6582 $213iJ $27891 $7981 $19255 $27237 ($554) .23% $3,37424 $3.29576 -2.3% 200 $79.79 $23677 $31656 $9490 $21395 $30885 -24% ($7848) ($771) $7191 $23577 $30858 $8702 $21395 $30097 ($771) -25% $3.73568 $3,54316 -25% "" $8692 $260.44 $34736 $1')316 $13535 $33851 -25% ($9252) ($885) $7799 $25044 $33843 $9423 $23535 $32958 ($885) -26% $4.0688 $3.99058 -25% "" $9405 $28412 $37818 $11143 $25674 $36817 -25% ($106201 ($1001) $8408 $28412 $36820 $1)144 $25674 $35818 ($1002) -27% $4.45832 $4,338.12 -27% "" $10120 $30780 $4090') $11969 $27814 $39783 -27% ($120201 ($1117) $9017 $307.80 $39797 $W865 $27814 $38679 ($1118) -28% $4.81976 $4,68554 -28% 180 $10834 $33148 $43982 $12795 $29953 $42748 ($134121 ($1234) .28% $9626 $33148 $42774 $115137 $29953 $41540 ($1234) -29% $5,18120 $5,03311 -29% 300 $115.46 $35515 $47063 $13622 $32')93 $45715 $1348 ($14808) -1.9% $10234 $35515 $45749 $12308 $32')93 $44401 ;$1348i .29% $5,54244 $5,38068 $16176 -29%
CUSTOMER SUMMER WINTER "R' & "RSH" RATE f$ICCFl CHAAGE ALL BLOCKS 1ST BLOCK TAILBLOCK PRESENT $84') $0356930 $0356930 $03.)4370 PROPOSED $1227 $0413150 $0360590 Cumnt Environmental Surha~e Riojer ~ Pr"posa.: Environmenlal Surcharge Rider ~000236
PRESENT GCR $11 838400 lMCF OR $1183840 ICCF PROPOSED GCR $10697500 MCF OR $1 ù69760 ICCF DELAWARE GAS BILLING COMPARISON Schedule JFJ-1 GENERAL GAS (GGI Page 6 of 16
Current Rates Effective January 1, 2006 vs. Proposed Rates Effective April 1 , 2007 Delivery, GCR and Environmental Surcharge Rates
4 SUl.ER . TOTAL BILL PER MON 8 WINTR. TOTAL BKL PER MONT A~UAL IMPACT. TOTAL BILL MONTHLY Present Proposed Total Present Proposed Total Total SALES Bas. OCR Toto! OCR OIFF. %DIFF Bas. OCR ~ ~ Total Bas. Total OIFF. %D1FF PRESENT PROPOS10 OIFF. %D1FF (CCF .' 0 $19.00 SO.OO $19.00 $32.82 $0.00 $32.82 $13.82 72.7% $19.00 $0.00 $19.00 $32.82 $0.00 $32.82 $13.82 72.7% $28.00 $393.84 $165.84 72.7% 25 $27.05 $2.60 $S.6S $42.02 $26.74 $68.76 $12.11 21.4% $27.05 $2.60 $S.6S $42.02 $26.74 $68.76 $12.11 21.4% $679.80 $85.12 $145.32 21.4% 50 $3.1a $59.19 $94.29 $51.22 $53.49 $104.71 $10.42 11.1% $3.10 $59.19 $94.29 $51.22 $5.49 $104.71 $10.42 11.% $1.31.48 $1.256 .52 $125.04 11.1% 75 $4.15 $8.79 $131.94 $60.41 $8.23 $140.64 $8.70 6.6% $43.15 $8.79 $131.94 $60.41 $8.23 $140.64 $8.70 6.6% $1,583.28 51,687.68 $104.40 6.6% 100 $51.20 $118.38 $169.58 $6.61 $106.98 $176.59 $7.01 4.1% $51.20 $118.38 $169.58 $69.61 $106.98 $176.59 $1.01 4.1% $2.034.96 $2.119.08 $8.12 4.1% 200 $8.39 $236.17 $320.16 $106.40 $213.95 $320.35 $0.19 0.1% $8.39 $236.77 $320.16 $106.40 $213.95 $320.35 $0.19 0.1% $3,841.92 $3,84.20 $2.28 0.1% 300 $115.59 $35.15 $470.74 $143.19 $320.93 $464.12 .$6.62 -1.4% $115.59 $35.15 $470.74 $143.19 $320.93 $4.12 -$6.62 -1.4% $5,64.88 $5,569.44 -$79.44 -1.% 400 $147.78 $473.54 $61.32 $179.98 $427.90 $67.88 -$13.44 -2.2% $147.78 $473.54 $621.2 $179.98 $427.90 $67.88 -$13.44 -2.2% $7.455.84 $7,294.56 -$161.28 -2.2% 500 $179.98 $591.92 $n1.90 $216.17 S5.a8 $751.65 -$20.25 .2.6% $179.98 $591.92 sn1.90 $216.77 $5.88 $751.65 -$20.25 -2.6% $9,262.80 $9.019.80 -$243.00 -2.6% 1000 $318.84 $1,183.84 $1.502.68 $378.01 $1069.76 $1,447.n .$5.91 -3.7% $318.84 $1.183.84 $1,502.68 $378.D $1.0G9.76 $l,447.n -$5.91 -3.7% $18.032.16 $17.373.24 -$68.92 -3.7' 1500 $45.57 $1.175.76 $2,211.33 $516.52 $1604.64 $2.121.16 -$90.17 -4.1% $45.57 $1,775.76 $2.211.33 $516.52 $1,604.54 $2,121.16 -$90.17 -4.1% $26.535.96 $25,453.92 -$1.082.04 -4.1% 2000 $52.30 $2,367.68 $2.919.98 $655.03 $2,139.52 $2,794.55 -$125.43 -4.3% $52.30 $2,367.68 $2,919.98 $655.03 $2.139.52 $2,794.55 -$125.43 -4.3% $3.039.76 $3.534.60 -$1,505.16 ...3% 2500 $69.03 $2.959.60 $3.628.63 $793.54 $2.674.40 $3.467.94 .$160.69 -4.4% $669.03 $2,959.GO $3.628.63 $793.54 $2,674.40 $3.467.94 -$160.69 -4.4% $43.543.56 $41.615.28 -$1.928.28 -4.4% 3000 $785.76 $3,551.52 $4.337.28 $932.05 $3,209.28 $4,141.33 -$195.95 -4.5% $785.76 $3,551.52 $4,337.28 $932.05 $3.209.28 $4,141.33 -$195.95 -4.5% $52.041.36 $49,695.96 -$2,351.40 -4.5% 3500 $92.49 $4.143.44 $5.04.93 $1.070.56 $3,144.16 $4,814.n .$21.21 -4.6% $902.49 $4.143.44 $5,04.93 $1.070.56 $3.744.16 $4,814.n .$21.21 ".6% $6,551.16 $57,n6.64 -$2,774.52 ...'" 4000 $1.019.22 $4,735.36 $5,154.58 $1.209.07 $4.279.04 $5.88.11 -$266.47 ".6% $1.019.22 $4.735.36 $5,754.58 $1,209.07 $4,279.04 $5.488.11 -$266.47 ...'" $69.05.96 $6.857.32 .$3,197.64 -4.6% 4500 $1,135.95 $5.327.28 $6.463.23 $1.347.58 $4,813.92 56.161.50 -4.7% .$301.73 $1.35.95 $5.327.28 $6,463.23 $1,347.58 $4,813.92 $6,161.50 -$31.73 ".7% $77,558.76 $73,938.00 -$3.620.76 ...7% 5000 $1,252.68 $5,919.20 $7.171.88 $1.486.09 $5.34.80 $6,834.89 -$336.99 -4.7% $1,252.68 $5.919.20 $7,171.88 $1.486.09 $5.34.80 $6.834.89 -$36.99 -4.7% $8.062.56 $8,018.68 .$4,04.88 ".7% 6000 $1.86.14 $1.103.04 sa,589.18 $1.63.11 $6.418.56 sa,181.61 -$407.51 -4.7% $1.486.14 $7,103.04 sa.589.18 $1.763.11 $6.418.56 $8,181.67 .$407.51 -4.7% $103.070.16 $98,180.04 -$4,890.12 ".7% 7000 $1.719.60 $8,286.88 $10.006.48 $2.040.13 $7,488.32 $9,528.45 -$478.03 ...'" $1.19.60 $8.286.88 $10,006.48 $2,040.13 $7.488.32 $9,528.45 -$478.03 ...'" $120,077.76 $114,341.40 .$5,736.36 ...'" 8000 $1.953.06 $9.470.n $11.423.78 $2,317.15 sa.558.08 $10.875.23 -$58.55 ...'" $1.953.06 $9.470.n $11.423.78 $2.317.15 sa,558.08 $10.875.23 .$58.55 ...'" $137.065.36 $130,502.76 -$6,582.60 ...'" 9000 $2,186.52 $10,65.56 $12.841.08 $2.594.17 $9,627.84 $12.222.01 -$619.07 ...'" $2.186.52 $10,65.56 $12,841.08 $2.594.17 $9.627.84 $12.222.01 -$619.07 ...'" $154.092.96 $146,664.12 -$7.428.84 ...'" 10000 52.419.98 $11.838.40 $14.258.38 $2,871.19 $10,697.60 $13,568.79 -$689.59 ...'" $2.419.98 $11.838.40 $14.258.38 $2.871.19 $10,697.60 $13,568.79 -$689.59 ...'" $171.100.56 $162,825.48 -$8,275.08 ...'" 12000 $2,886.90 $14.206.08 $17.092.98 $3.425.23 $12,837.12 $16,262.35 4830.63 -4.9% $2,886.90 $14.206.08 $17,092.98 $3.425.23 $12,837.12 $16.262.35 -$80.63 ..... $25,115.76 $195,148.20 .$9,967.56 ..... 14000 $3,353.82 $16,57376 $19,927.58 $3,979.27 $14,976.64 $18.955.91 .$971.67 -4.9% $3,353.82 $16,573.76 $19.927.58 $3,979.27 $14,976.64 $18,955.91 -$97167 ..... $239,130.96 $27,470.92 -$11.660.04 -4.9% 16000 $3.820.74 $18,941.44 $22.762.18 $4.533.31 $17.116.16 $21.649.47 -$1.112.71 -4.9% $3.820.74 $18,941.44 $22.762.18 $4.533.31 $17,116.16 $21.649.47 -$1.112.71 -4.9% $273.146.16 $259,793.64 -$13,352.52 ..... 18000 $4,287.66 $21.309.12 $25.596.78 $5.087.35 $19.255.68 $24,343.03 -$1.253.75 -4.9% $4.281.66 $21,309,12 $2.596.78 $5.087.35 $19.255.68 $24,343.03 -$1,253.75 -4.9% $37,161.36 $22,116.36 -$15,045.00 ..... 20000 $4,754.58 $23,676.80 $2,431.38 $5.641.39 $21,395.20 $27,036.59 -$1,9il.9 ..... $4.754.58 $23,676.80 $2,431.38 $5.641.39 $21,395.20 $27,036.59 -$1394.19 -4.9% $31,176.56 $324,439.08 -$16,737.48 .....
CUSTO~R SUMtÆR WINT "GG" RATE ($ICCA C~RGE 1ST 750 CO: :i750 CCF 1ST 750 CCF :i750 CCF PRESENT $19.00 $0.321960 $0.2330 $0.321960 $0.2330 PROPOSED $32.82 $0.361900 $O.2n020 $0.361900 $O.2n020
PRESENT GCR $11.838400 ßiCF OR $1.163840 ICCF PROPOSEO GCR $10.697600 JMCF OR $1.069760 IeCF ClJeri Envrormenlal S16charge RIder 0.00138 DELAWARE GAS BILLING COMPARISON Schedule JFJ-1 MEDIUM VOLUME GAS (MVG) Page 7 of 16
Current Rates Effective January 1, 2006 vs. Proposed Rates Effective April 1 , 2007 Delivery, GCR and Environmental Surcharge Rates
Monlti 4 SUMMER. TOTAL SILL PER MON 8 WINTR. TOTAL BILL PSl MONT ANiUAL IMPACT. TOTAL BILL Sales load Present Proposed Total Present Factor Proposed Total Total lM I! g£ .b g£ Total DJFF. B~. B~. OCR Total ~ ~ ~ Q. ~ .Q .% PROPOseO DIFF. 500 ~ 66 25 $1,211 $5.923 $7.134 $1.562 ~ $5,326 $6,889 .$245 -3.4% $1.211 500 $5.923 $7,134 $1.562 $5.326 $6.889 -$245 -3.4% $8.606 $8.663 33 50 $874 $5.719 $6.585 $1050 $5.002 $6.052 -$533 -8.1% .$2.943 -3.4% $874 $5,719 $6,592 $1,050 $5,002 $6.052 .$50 -8.2% $79.080 500 22 75 $761 $5.650 $6.405 $879 $4,894 $5,774 $72,628 -$6,452 -8.2% -$61 -9.9% $761 $5,650 $6,412 $87' $4.894 $5.174 -$68 -10.0% 1,000 132 25 $2.106 $11.846 $13.939 $2.809 $10.653 $76.914 $69,283 -$7,630 -9.9% $13.462 -$477 -3.4% $2,106 $11.846 $13.953 $2.809 $10,653 $13.462 1.000 66 50 $1.432 $11.437 $12.856 $1.85 -$490 -3.5% $167,376 $161.54 -$5.831 -3.5% $10.005 $11,790 -$1,066 -8.3% $1.32 $11.437 $12,870 $1,785 $10,005 1.000 44 75 $1,208 $11.790 -$1.000 -8.4% $154.379 $141,476 -$12,903 -8.4% $11.301 $12.495 $1.44 $9,169 $11,232 -$1.263 -10.1% $1.208 $11,301 $12.509 $1,44 2.000 263 25 $9.789 $11.232 -$1.276 -10.2% $1S0,047 $134,766 -$15,261 -10.2% $3,B87 $2,686 $27,546 $5.288 $21,296 $26.58 -$92 -3.5% $3.887 $23,b86 $27.574 $5,288 $21,296 $26,58 -$990 -3.6% $30,775 $319,006 2,000 132 50 $2,550 $2,874 $2.397 $3.255 $2,009 $23.264 -S.4% -$11,769 -3.6% -$2,132 $2,550 $2.874 $25,424 $3,255 $20,009 $23,264 -$2,160 -8.5% S3,978 2,000 88 75 $2,101 $2,601 $24.674 $2.572 $19,577 $2,149 $279.172 -$25.806 .8.5% -$2,525 -10.2% $2,101 $2,601 $24,702 $2,Sn $19.577 $2,149 -$2,553 -10.3% 3,000 395 25 $5,679 $3,533 $41.170 $7.783 $31,948 $26,314 $265,792 -$30,522 .10.3% $39.731 -$1439 -3.5% $5,679 $3.533 $41,211 $7.783 $31.948 $39.731 -$1.480 -3.6% 3,000 ,.7 50 $3.657 $3,305 $37.921 $494.371 $476.772 -$17,599 -3.6% $4.710 $30.00 $3,714 -$3,207 -8.5% $3,657 $3,305 $37.962 $4.710 3,000 132 75 $30.00 $3.714 -$3,249 -8.6% $45.381 $416.564 -$3,817 -8.5% $2.993 $3.902 $36,85 $3,701 $2.366 $3,067 -$3.788 -10.3% $2.993 4.000 $3.902 $36,896 $3.701 $2.366 $3.067 .$3,829 -10.4% $42.581 $36.798 .$4,782 -10.3% 526 25 $7.460 $47,373 $5,n7 $10,261 $42,591 $52,853 -$1,925 -3.5% $7,460 $47.313 $5,833 $10,261 $42,591 $52,853 ~$1,9OO -3.6% $657.170 4.000 263 50 $4.774 $4,742 $5.462 $6.180 $40.009 $46,189 $63.233 -$2.537 -3.6% -$4,273 -9.5% $4,774 $4,742 $5,517 $6,180 $4,009 $46.188 -$4,328 -8.6% 4,000 17 75 $3,976 $4,197 $49,019 $4.814 $65,980 $5,260 -$51.nO .8.5% $39,145 $43.959 -$5.059 -10.3% $3.876 $4,197 $49,073 $4,814 $39,145 5,000 658 25 $9,251 $4.958 -$5.114 -10.4% $58,651 $527.501 .$61,150 .10.4% $59.219 $6.401 $12,756 $5,244 $6,000 -$2,401 -3.5% $9.251 $59.219 $b8.470 5,000 329 50 $12.756 $5,24 $66.000 -$2.470 -3.6% $81,366 $791,998 -$29,368 -3.6% $5,992 $57.179 $63.002 $7.650 $5,013 $57,663 -$5,339 -9.5% $5.892 $57,179 5,000 $6,071 $7.650 $5,013 $57.663 -$5,408 -8.6% $756,579 $691,956 -$64,623 -8.5% 21. 75 $4,769 $5,497 $61.197 $5,942 $4.933 $5,976 -$6,322 -10.3% $4,769 $5,497 $61.266 $5,942 $4.933 $5.876 -$6,391 -10.4% $734,918 $68.507 6.000 789 25 $11,032 $71.059 $8,009 $15,235 $63.887 $79.122 -$2.887 -3.5% -$76.411 -10.4% $11,032 $71,059 $8,091 $15,235 $6,887 $79.122 -$2,970 -3.6% $98,765 6,000 395 50 $7,009 $6,616 $75,543 $9,120 $60,018 $69,138 $949.459 .$3.306 -3.6% -$6,405 -8.5% $7.0Q9 $68.616 $75.626 $9,120 $60,018 $69.138 -$6.488 -8.6% 6.000 263 75 $5,662 $67.798 $73,377 $7.071 S5,n2 $907,178 $89.651 .$n.527 -8.5% $65,793 -$7,584 -10.3% $5,662 $67.798 $73,460 $7.071 $5.722 $6.793 -$7.667 7,000 '21 25 $12,823 $8,906 $95.632 $17,n9 -10.4% $81,185 $789.513 -$91.672 -10.4% $74.540 $92.269 -$3,364 -3.5% $12.823 $8.906 $95,729 $17,n9 $74.540 7.000 461 50 sa.127 saO,05 $92,269 -$3.460 .3.6% $1.148,360 $1,107,224 -$41,136 -3.6% $8,08 $10,590 $70,023 $8,612 -$7,4n -8.5% $8,127 $8,05 $8,180 $10,590 7,000 307 75 $70,023 $8,612 -$7.566 .8.6% $1,057,n7 $967,347 -$90,430 -8.5% $6.554 $79,099 $8,557 sa.200 $b8,510 $76.710 -sa.647 -10.3% $6,554 $79.099 $8.653 8.000 1.053 25 $8.200 $6.510 $76.710 -$8.943 -10.4% $1,027,452 $920,519 .$106,932 -10.4% $14.615 $94.752 $109,256 S2 ,223 $8,192 $105.416 -$3,840 -3.5% $14.615 $9.752 $109,366 $20,223 $8,192 $105.416 -$3,951 -3.6% $1,311,956 $1.264,989 -$46.967 -3.6% 8,000 526 50 $9.234 $91,48 $100.608 $12.04 $8,017 $92,062 -sa,547 -8.5% $9,234 $91,48 $100,718 $12.04 $8.017 $92.062 .sa.657 -8.6% $1,208,179 $1,104,739 8,000 351 75 $7,447 $9,399 $97,736 $9,328 $78,299 sa7.627 -$10.109 -10.3% .$103,40 .8.6% $7,447 $90.399 $97.847 $9,328 $78.299 $87,627 -$10.219 -10.4% $1.173.718 9.000 1,164 25 $16.396 $106.592 $122.864 $22,702 $95,835 $118,538 $1.051,525 -$122,193 -10.4% -$4,326 -3.5% $16.396 $106.592 $122.988 $22,702 $95,835 $118.538 -$4.450 -3.6% 9,000 5.2 50 $10,351 $102,922 $113,149 $13,514 $90.022 $1.475.355 $1.22,450 -$52.905 .3.6% $103,536 -$9,613 -8.S% $10,351 $102,922 $113,273 $13,514 $9.022 $103.536 9,000 395 75 $8,34 $101.00 $109.916 .$9,737 -8.6% $1,358,n9 $1,242,435 -$116.34 .8.6% $10.457 $8.087 $9"'44 -$11,372 -10.3% sa.340 $101,700 $110,04 $10.457 $8,087 10,000 1.316 25 $18,187 $9,54 411,496 .10.4% $1319,985 $1,182,531 -$137.454 .10.4% $118,38 $136.487 $2.197 $106,488 $131.685 -$4,803 -3.S% $18.187 $118.438 $136,625 $2,197 10.000 658 50 $11,469 $106,488 $131.685 -$4.941 .3.6% $1.638,951 $1.580,216 -$5,735 -3.6% $114,359 $125,690 $14.98 $100,027 $115,011 -$10,679 -8.5% $11,469 $114,359 $125,827 $14,98 10.000 439 75 $100,027 $115.011 -$10,816 -8.6% $1,509.378 $1,380,131 .$129.247 -8.6% $9,233 $113,001 $122,096 $11.585 $97,876 $109.461 -$12,63 -10.3% $9,233 $113,001 $122.234 $11,585 $97.876 $109.461 -$12,n2 -10.4% $1,466,252 $1,313.538 -$152,715 -10.4%
CUSTOtJR DEMD COMMODITY "MG" RA TE (WCF CHARGE CHoRGE CHoRGE Dellverv Rale PRESENT $315.00 $10.21 $0.429790 PROPOSEO $49.39 $lS.52 $0.421950
GCR PRESENT $6.2000 $11.027900 PROPOSEO $9.9200 $9.356500 ErPromienal SlIcharce PRESENT 0.01377 DELAWARE GAS BILLING COMPARISON Schedule JFJ.1 LARGE VOLUME GAS (L VGl Page 8 of 16
Current Rates Effective January 1,2006 vs. Proposed Rates Effective April 1 , 2007 Delivery, GCR and Environmental Surcharge Rates
Mo)nthly SUMMER - TOTAL BILL IMNTR ~ TOTAL BILL ANNUAL IMPACT _ TOTAL BILL Sales L.)M Present Proposed Total Present Proposed Total Total Th MDD Fao:tùr Base GCR Totaf Base Total DIFF. %DIFF Q£ Bise Q£ !g !! Q£ Total 01FF, %OIFF PRESENT PROPOSED D1FF, ~ 5.')1)0 658 25 $5,718 $59,219 $64.937 $7,369 $53,244 $60.513 -$4.324 .67% $5,718 $59,219 $64,937 $7,369 $53.244 $60,613 ($4,324) -67% $779,247 $727,361 -$51,886 -67% 5.tJoJ '29 '0 $3.402 $57,179 $60.581 $4,372 $50,013 $54,385 -$6,196 .102% $3,4')2 $57.179 $6'J.581 $4,372 $50.i3 $54,385 ($6,195) -102% $726,975 $652,625 -$7.1,350 -102% 5.')')') ,,, 75 $2,628 $56.497 $59.125 $3.370 $48.933 $52,303 -115% '$6,822 $2,623 $56,497 $59.125 $3.70 $48.933 $52,3')3 ($5,822) -115% $7')9,498 $627,637 -$81.861 -115% 10,01)0 1,316 25 $10.936 $118,438 $129.374 $14,015 $11)6.488 $120.503 -S8,LL?1 -69% $1'J.936 $118,438 $129.374 $14.015 $loJ6,488 $120,503 ($8,871) -69% $1.552,493 $1.446,036 -$106.458 -69% W,O')I) 658 '" $6,304 $114.359 $120.663 $8,0320 $100.027 $108,047 -1')5% -$12.615 $6,3.)4 $114,359 $120,663 $8,020 $100,027 $108.047 ($12,6151 -105% $1,447,950 $1,296,564 -$151,386, -105% 10.000 439 75 $4,762 $113.')1)1 $117.63 $6.025 $91,676 $103,9')1 -$13.852 -118% $4,762 $113,001 $117,763 $6,025 $97,876 $103,9')1 ($13,8621 -118% $1,413,155 $1,245,815 -$166,339 -118% 15.000 1.974 25 $15,154 $177.657 $193.812 $20.650 $159,732 $180,393 -$13.419 -69% $15,154 $177,657 $193,812 $20,660 $159,732 $180,393 $13,419 -69% $2,325,740 $2,164,711 -$161,029 -59% 15,000) '87 '0 $9.2'16 $171.538 $180.744 $11,669 $150,040 $161.')9 -105% -$19.035 $9,206 $171,538 $180,744 $11,569 $\50,040 $161,709 ($19,035) -105% $2,168,925 $1,940,504 -$228,421 -105% 15,0')) 658 " $6,890 $169,498 $176.388 $8,672 $146,8oJ9 $155,481 -119% -$2oJ,9')7 $6,890 $169,498 $176,388 $8,672 $146,809 $155,481 ($20,907) -119% $2,116.554 $1,865,768 .$250,886 -119% 2'J,0oJ'J 2.632 " $21,372 $236,876 $258,249 $27,306 $212.976 $240,282 -70% -$17,967 $21.72 $236,876 $258,249 $27,306 $212,976 $240,282 ($17,967) -70% $3.')98.987 $2,883,386 -$215,501 -1-')% 20.000 1,316 " $12.1')8 $i28,717 $240,825 $15,317 $200,053 $215,370 -106% -$25,455 $12,106 $228,717 $240,825 $15,317 $20'),053 $215,37,) ($25,455) -106% $2,869,9')1) $2.584,443 -$305,457 -10.6% 20.00 67 " $9,017 $225,995 $135,013 $11,318 $195,742 $207,060 -$27,953 -119% $9,017 $225.995 $235.i3 $11,318 $195,742 $207.05ù ($27.953) -119% $2,820,152 $2,484,720 -$335,432 -119% 25,M.) 3,289 " $26-'84 $296,089 $322,673 $33,942 $266,210 $30').153 -70% -$2252oJ $26,584 $296.089 $322,673 $33,942 $256,211 $3(1,153 ($22.520) -1'3% $3,872.'4 $3,601.34 -$270,240 -70% 25.,)i)) 1,645 ,,' $15,010 $285,897 $300,906 $18.966 $250.066 $269.02 -106% -$31,874 $15,010 $285,897 $300,9oJ6 $18,966 $250.066 $269.032 ($31,874) -1')6% $3,610,676 $3,228.383 -$382.493 -1IJ6% 25.000 1,096 " $11,145 $282,493 $293,638 $13,964 $244.675 $258,639 -119% -$34,998 $11,145 $282.493 $293,638 $13,964 $244,675 $258,639 ($34,998) -119% $3,523,650 $3.103,672 -$419,979 -119% 30,000 3,947 " $3\,802 $355,308 $387,11') $40,588 $319,455 $36'),142 -$27,Q8 -7'3% $31,802 $355,308 $387,110 $40,588 $319,.155 $360,042 ($27.068) _7,)% $4,545,321 $4.320,509 -$324,812 -70% 30,000 1,974 ,oJ $17,912 $343,076 $350,986 $22,614 $300,080 -1'J6% $322694 -$38,294 $17.912 $343.076 $360,988 $22,614 $300,080 $322,694 ($38.294) -1')6% $4,331.851 $3,872322 -$459,528 -106% 30,000 1,316 " $13,279 $338,996 $352,275 $16,619 $293,616 $310,238 -119% -$42,oJ38 $13,279 $338,996 $352,276 $16,619 $293,618 $310,238 ($4VJ38) -119% $4,227,308 $3.722,851 -$504.457 -119% 35,oJOO 4,605 25 $37.020 $414,528 $451,547 $47.233 $372699 $419,932 -$31,615 -71)% $37,020 $414.528 $451,547 $47,233 $372699 $419.932 ($31.615) -70% $5,418,568 $5.039,164 -$379,384 -1.0% 35.000 2,303 ,,' $20,814 $400,255 $421,069 $26.252 $351).093 -106% $375,355 -$4,714 $20,81.1 $400,255 $421,069 $26,262 $350,093 $376.355 ($4,714) -106% $5,052,826 $4.516,262 -$536.564 -10Mb 35,000 1,535 " $15.407 $395,494 $410,901 $19,266 $342,551 .11.9% $361.817 -$49,084 $15.407 $395.494 $410.901 $19,266 $342,551 $361.817 ($49,084) -119% $4,930,806 $4,341,803 -$589,003 -119% 40,000 5,263 " $42,238 $473747 $515,985 $53,879 $425,943 $479,822 -70% -$36.163 $42,238 $473,747 $515,985 $53,879 $425,943 $479,822 ($36.163) -1,)% $6,191,814 $5.757.859 -$433.955 -70% 40,000 2,632 '" $23,716 $457,434 $481,151) $29,911 $400,106 $430,017 -$51.33 -106% $23.716 $457,434 $481.150 $29,911 $400,106 $430,017 ($51,133) -106% $5,773801 $5.150,201 -$613,500 -10.6% 40,001) 1.54 75 $17,535 $451.991 $469,525 $21,912 $391,484 $413,396 -120% -$56.129 $17,535 $451,991 $459.525 $21.912 $391,484 $413,396 ($56,129) -12')% $5,634,304 $4,960,755 -$673,550 -120% 50,000 6,579 25 $52,674 $592,185 $64,859 $67.170 $532,431 $599,601 -70% -$45.258 $52.674 $592,185 $64,659 $67.170 $532,431 $599.51)1 ($.5,258) -10% $7,738,308 $7.195,209 -$543.D8 -70% 50,000 3,289 '" $29,513 $571,787 $601,299 $37,198 $500,123 $537,32\ -106% -$63.978 $29,513 $571.81 $601,299 $37.98 $50').123 $537.321 ($63,978) -106% $7,215,592 $6,447,853 -$767.39 -106% 50,000 2,193 " $21,797 $564,992 $586,788 $27,214 $489,360 $516,574 -$70,215 -120% $21.97 $5!),992 $586,788 $27,214 $489,360 $516,574 ($70,215) -120% $7,041,460 $6,198,885 -$842,574 .120% 60,000 7,895 " $63,110 $710,623 $773,133 $80,461 $638,919 -70% $719,380 -$54,353 $63,110 $710,623 $773,133 $80,461 $538,919 $719,38D ($54,353) -7oJ% $9,284,801 $8,632,559 -$652,241 -70% 60,000 3,947 ,,) $35,316 $686,145 $721,462 $44,495 $600.150 $64,64 -$76,818 -106% $35,316 $586,145 $721,462 $4,495 $600,150 $64,644 ($76,818) -10.6% $8.657,543 $7,735,732 -$921.811 -106% 60,000 2,632 " $26.059 $677,992 $704,051 $32,515 $587,236 $619,51 -12.0% -$84,300 $26.059 $677,992 $704,051 $32,515 $587,236 $619,51 ($84,300) -12oJ% $8,4.18,615 $7,437,016 -$1,011599 -120% 70,000 9.211 " $73,547 $829,061 $902,608 $93,752 $745,407 $839,159 -70% -$63,449 $73,547 $829,061 $902,608 $93,752 $745,407 $839.159 ($63,449) -7,)% $10,831.294 $10,069,910 -$761,385 -7.0% 70,000 4,605 '" $41.2') $800,504 $841.624 $51.91 $700,176 $751.968 -107% -$89,657 $41,120 $800,504 $641,624 $51.91 $100,176 $751,958 ;$89.657 -107% $10,099,493 $9,023,611 -$1,075,882 -107% 70,000 3,070 $30,314 $790,987 $821.01 $37,808 " $685,1t2 $722911) -$98,391 -120% $30,314 $790,987 $821,301 $37,808 $685,102 $722.910 -i$98.391 -120% $9,855,612 $8,674,920 -$1,180,592 -12,0%
CUSTOMER DEMAND COMMODITY DoliveNRale CHARGE CHAAGE CHARGE PRESENT $5QOi)) $71)i)))) $010339 PROPOSED $72380 $9110i)lO $01'J646 GCR PRESENT $6200000 $1102790 PROPOSED $982000') $9356500
Environmental Surcharoo PRESENT 001377 PROPOSED 002377 DELAWARE GAS BILLING COMPARISON Schedule JFJ~1 Page 9 of 16 RESIDENTIAL (Rl & RESIDENTIAL SPACE HEATING IRSHI
Current Rates Effective January 1, 2006 vs. Interim Rates Effective November 1, 2006 Delivery Rate Only ANNUAL.4 SUMMER &8 WNTR 4 SUMMER. TOTAL BILL PER MONn AT CONSTANT MONTL V USAGE 8 WNTR. TOTAL BILL PER MONT ANNUAL IMPACT. TOTAL BILL MONTHl Y Present Proposed Total Present Present Proposed S~ES Proposed Total Annual Annuii Total Base GCR Base Q. Total Q! Base GCR Total (CCFj ~ ~ §. Q£ I2 OIFF, %OIFF !& Total .Q 0 $640 $000 $84') ~ $873 $0')0 $873 $'133 ,,% $84') $0')~) $640 $873 $')00 1 S876 $118 IS 94 $911) $873 $1)33 39% $1i)) 80 $10476 $396 39% $118 $N28 $0 ;) 34% $876 $118 $9 94 $910 $118 , $911 $237 $1148 $11)18 $')34 34% $11928 $12336 $4 08 34% $947 $237 $1184 $')36 31% $9.11 $237 $1148 $947 3 $947 $355 $13')2 $237 $1184 $036 31% $13776 $1421)6 $432 31% IS 94 $355 $1339 $037 28% $947 $355 $13')2 $984 4 $983 $474 $355 $1339 $037 28% $15624 $16058 $44. 2.8% $1457 $1021 $474 $1495 $'136 25% $963 $474 $1457 $1021 5 $1018 5592 $414 $1495 $')38 25% $17484 $1794') $4.56 26% $1610 $1058 $592 $1650 $1)40 25% $1018 $592 $1611) $1058 '" $1197 $592 $165.) $04.) 25% $19320 $19800 $480 25% $1184 $2381 $1244 $1184 $2428 $047 20% $1197 $1184 $2381 20 $1244 $1184 $2426 $,)47 203% $28572 $29136 15 84 2')% $1554 $2368 $3922 $1615 $2368 $3983 $')61 15% $1554 $2368 $3922 $1515 $2366 $3963 $061 16% $471164 $47796 $732 1.6% 25 $1132 $29,50 $4692 $1800 529.60 $47.60 $')68 14% $1132 $29 60 40 $4692 $161)0 $2960 $476i $068 14% $5631)4 $57120 $816 14% $2268 $4735 $7,)1)3 $2356 $4735 $7091 $068 13% $2268 $4735 $71)1)3 $2356 $4735 $71)91 $0.66 13% $84036 $85092 $1056 13% 60 $2982 $7103 $101)85 $3')98 $7103 $10201 $116 12% $2929 $7103 $1i032 $3043 $7103 $1i146 $1.14 11% $1,20596 $1.21972 $1376 1.% 19 $3660 $9352 $13112 $3802 $93.52 $13154 $142 11% $351)8 $9352 $128M $3644 $9352 $12996 $136 11% $1,54926 $1.56584 $1656 11% 10' $4,09 $11836 $16247 $4581 $11836 $164.19 $172 11% $41.47 $118.38 $15985 $43')8 $116.38 $16146 $161 10% $1,92866 $1,94844 $1976 ,,% 12' $51.3 $14206 $19329 $5322 $14206 $19528 $199 1')% $4756 $14206 $199,62 $4.40 $142,06 $191.46 $1,84 1,0% $2,29012 $2,31280 $2268 10% "0 $58.37 $16574 $22411 $60)54 $16574 $22638 $227 11)% $5364 $16574 $21938 $5573 $16574 $22147 $2iJ9 10% $2.65148 $2,67726 $2580 10% 160 $6551 $18941 $25492 $68.06 $18941 $25747 $255 10% $5973 $189.-1 $24914 $6205 $18941 $251.46 $232 09% $3,01280 $3,04156 $2876 to% 16' $7265 $21309 $28574 $7547 $213.09 $28856 $282 11)% $6582 $21309 $27691 $6837 $21309 $26146 $255 09% $3,37424 $3.40592 $3168 09% "0 $7979 $23677 $31656 $8189 $236.77 $31966 $311) 11)% $7191 $23677 $30666 $7470 $23677 $31147 $279 i)9% $3,73568 $3,77040 $3472 ')9% ,,, $8692 $26/44 $34736 $9030 $26044 $351)74 $338 11)% $7799 $26044 $33843 '40 $8102 $26044 $34146 $31)3 1)9% $4.')9688 $4,13464 $3776 09% $94.06 $28412 $37818 $97.72 $28412 $38184 $366 10% $64 08 $28412 $36620 $8734 $28412 $37145 $326 09% $4,45632 $4,49904 $4072 09% "0 $11)120 $30780 $409')0 $10514 $30780 $41294 $394 1(1% $9017 $30781) $39797 $9367 $31)780 $41)147 $351) 09% $4,81976 $4,86352 $4376 1)9% 28O $108.34 $33148 $43962 $11255 $33148 $4 03 $421 1 ')~fi $9626 $33146 $42774 $99.99 $33148 $43147 $375 09% $5,18120 $5,22788 $4668 09% 300 $11548 $35515 $47063 $119.97 $35515 $47512 $44' ,,% $10234 $35515 $45749 $1')632 $35515 $46147 $396 09% $5.54244 $5.59224 $4980 0.9%
CUSTOMER SUMMER WINTER "R" & "RSH" RATE fS/CCFI CHARGE AlL BLOCKS 1ST BLOCK TAil BLOCK PRESENT $840 $0356930 $035693') $0304370 PROPOSED $873 $0370790 $') 370790 $0316160 ~onnleniaiSurtiarieRlder $000138 Proposed Environmental Surdiafge Ri':ler 000138
PRESENT GCR $11 838400 IMCF OR $1183840 ICCF PROPOSED GCR $11838400 IMCF OR $1183840 ICCF DELAWARE GAS BILLING COMPARISON Schedule JFJ-1 GENERAL GAS (GGI Page 10 of 16
Current Rates Effective January 1, 2006 vs. Interim Rates Effective November 1, 2006 Delivery Rate Only
4 SUMMER ~ TOTAL BILL PER MON 8 WINTR ~ TOTAl BiLL PER MONT MONTHLY Present Proposed At..,¡AL IMPACT. TOTAL BILL Total Present Proposed Total Total SALES Bu. ToW DIFF. %DlFF GCR ~ .! ~ .! Bu. Total Bu. GCR Total %DIFF %DlFF (CCl .. ~ ~ 0 $19.00 $0.00 $19.00 $19.97 $0.00 $19.97 $0.97 5.1% $19.00 $0.00 $19.00 ~ $19.97 $0.00 $19.97 $0.97 5.1% $28.00 $239.64 $11.64 5.1% 2' $27.05 $2.60 $5.65 $2.4J $2.60 $5.03 $1.38 2.4% $27.05 $2.60 $5.65 $2.4J $2.60 $5.03 $1.38 2.4% $679.80 $696.36 $16.56 2.4% 50 $3.10 $59.19 $94.29 $36.88 $59.19 $96.07 $1.8 1... $35.10 $59.19 $9.29 $36.88 $59.19 $96.07 $1.8 1... $1.131.48 $1,152.84 $21.36 1.9% 7' $4.15 $8.79 $131.94 $4.34 $8.79 $134.13 $2.19 1.% 54.15 $8,79 $131.94 $4.34 $0.79 $134.13 $2.19 1.7% $1.583.28 $1.609.56 $26.28 1.7% 100 $51.20 $118.38 $169.58 $5.80 $118.38 $172.18 $2.60 1.5% $51.20 $118.38 $169.58 $5.80 $118.38 $172.18 $2,60 1.5% $2,034.96 $2,066.16 $31.20 1.5% 200 $8.39 $26.77 $320.16 $87.62 $236.77 $324.39 $4.23 1.3% $8.39 $236.77 $320.16 $87.62 $236.77 $324.39 $4.23 1.3% $3,941.92 $3,892.68 $50.76 1.3% 300 $115.59 $35.15 $470.74 $121.5 $35.15 $476.60 $5.86 1.2% $115.59 $35.15 $470.74 $121.45 $35.15 $476.60 $5.86 1.2% $5,64.88 $5.719.20 $70.32 1.2% 400 $147.78 $473.54 $61.32 $155.27 $473.54 $68.81 $7.49 1.2% $147.78 $473.54 $62132 $155.27 $473.54 $628.81 $7.49 1.2% $7,455.84 $7,54.n $8." 1.2% SOO $179.98 $591.92 $n1.90 $189.10 $591.92 $781.02 $9.12 1.2 $179.98 $591.92 sn1.90 $189.10 $591.92 $781.02 $9.12 1.2% $9.262.80 S9,3n.24 $109.44 1.2% 1000 $318.84 $1.183.84 $1502.68 $3.63 $1.183.84 $1518.47 $15.79 1.% $318.84 $1,183.84 $1,502,68 $3.63 $1,183.84 $1.518.47 $15.79 1.1% $18.032.16 $18,221.64 $189.48 1.1% 1500 $45.57 $1,775.76 $2,211.33 $46.56 $1.775.76 $2.232.32 $20.99 0... $45.57 $1,775.76 $2.211.33 $46.56 $1,115.76 $2,232.32 $2.99 0.9% $26,535.96 $26,787.84 $21.88 0.9% 2000 $52.30 $2,367.68 $2.919.98 $578.50 $2.367.68 $2.94,18 $26.20 0.9% $552.30 $2,367.68 $2,919.98 $578.50 $2,367.68 52.946.18 $26.20 0.9% $3.039.76 $3,35.16 $314.40 0.9% 2500 $669.03 $2,959.60 $3,628.63 $700.43 $2.959.60 $3.660.03 $31.40 0... $S69.03 $2.959.60 $3.628.63 $700.43 $2.959.60 $3.660.03 $31.40 0.9% $4.543.56 $4.920.36 $376.80 0.9% 3000 $785,76 $3,551.52 $4.331.28 $82.31 $3.551.52 $4.313.89 $3.61 0.8% $75.76 $3.551.52 $4.337.28 $82.37 $3.551.52 $4.373.89 $3.61 0.8% $52,047.36 $52.486.68 $49.32 0.8% 3500 $902.49 $4.143.44 $5.04.93 $9.30 $4.143.44 $5,087.14 $41.81 0.8% $902.49 $4,143.44 $5,04.93 $94.30 $4,143.44 $5.087.74 $41.81 0.8% $60,551.16 $61.052.88 $5 1.72 0.8% 4000 $1019.22 $4,735.36 $5.154.58 $1.066.24 $4.735.36 $5.801.60 $47.02 0.8% $1,019.22 $4,735.36 $5,754.58 $1.66.24 $4.735.36 $5.801.60 $47.02 0.8% $69,05.96 $6,619.20 $5.24 0.8% 4500 $1.135.95 $5.327.28 $6,463.23 $1,188.17 $5.327.28 $6.515.45 $52.22 0.8% $1,135.95 $5,327.28 $6.463.23 $1,188.17 $5.327.28 $6.515.45 $52.22 0.8% $77558.76 $78,185.40 $626.64 0.8% '000 $1.252.68 $5.919.20 $7.171.88 $1.10.11 $5.919.20 $7,229.31 $51.43 0.8% $1.252.68 $5,919.20 $7.171.88 $1.10.11 $5.919.20 $7,229.31 $57.43 0.8% $8.062.56 $8.751.72 $689.16 0.8% 6000 $1,486.14 $7.103,04 $8.589.18 $1.553.98 $7.103.04 $8,651.02 $67.84 0.8% $1.86.14 $7,103.04 sa,589.18 $1,553.98 $7,103.04 $8.657.02 $67.84 0.8% $103.070.16 $103,884.24 $814,08 0.8% 7000 $1719.60 $8,286.88 $10.006.48 $1.97.85 $8,286.88 $10,08.73 $78.25 0.8% $1.19.60 $8,286.88 $10,006.48 $1.97,85 $8,286,88 $10.084.73 $78.25 0.8% $120,on.76 $121,016,76 $939.00 0.8% .000 $1,953.06 $9.470,n $11,423.18 $2.041.72 $9,470.72 $11,512.44 $0.66 0.8% $1,953.05 $9,410.n $11,423.78 $2,041.n S9.410.n $11.512.44 $0.66 0.8% $137.085.36 $138,149.28 $1,063.92 0.8% 9000 $2,186.52 $10.65.56 $12.841.08 $2,285.59 $10,65.56 $12,940,15 $99.07 0.8% $2,186.52 $10,65.56 $12,841.08 $2,285.59 $10,65.56 $12.940.15 $99.07 0.8% $154,092,96 $155,281,80 $1,188.84 0.8% 10000 $2,419.98 $11,838.40 $14,258.38 $2.529.46 $11,838.40 $14.361,86 $109.48 0.8% $2.419,98 $11,838.40 $14,258.38 52,529.46 $11.838.40 $14,367.86 $109.48 0.8% $171,100.56 $172,414.32 $1,313.76 0.8% 12000 $2,886.90 $14.206.08 $17,092.98 $3,017.20 $14.206.08 $17 ,223.28 $130.30 0.8% $2,800.90 $14,206.08 $17,092.98 $3.017.20 $14.206.08 $17,223.28 $130.30 0.8% $25,115.76 $26,679.36 $1563.60 0.8% 14000 $),353,82 $16,573.76 $19.921.58 $3,504.94 $16.573.76 $2,078.70 $151.12 0.8% $3.353.82 $16.573.76 $19.927.58 $3.504.94 $16,573.76 $20.08.70 $151.12 0.8% $29,130.96 $240.94.40 $1,813.44 0.8% 16000 $3,820,74 $18.941.44 $2.762.18 $3,992.68 $18.941.44 $2,934.12 $171.94 0.8% $3,820.74 $18,941.44 $2.762.18 $3,992.68 $18,941.44 $2,934.12 $171.94 0.8% $273,146.16 $275,209.44 $2,063.28 0.8% 18000 $4.287.66 $21,309.12 $2,596.18 $4,480.42 $21.309.12 $25.789.54 $192.76 0.8% $4,287.66 $11,309.12 $2.596.78 $4,480.42 $21.309.12 $25,799.54 $192.76 0.8% $37,161.36 $309.474.48 $2,313.12 0.8% 20000 $4.754.58 $23,676.80 $2,431.38 $4,968.16 $2,676.80 $2,64.96 $213.58 0.8% $4,754.58 $2.616.80 $2.43138 $4,968.16 $2.676.80 $2,64.96 $213.58 0.8% $31,176.56 $33.739.52 $2,562.96 0.8%
CUSTOM:R SLMM:R WlNT -tG' RATE ($ICCR CHARGE 1ST 150 Ca: :.750 CCF 1ST 750 CCF ;:750 CCF PRESENT $19.00 $0.321960 $0.23360 $0.321960 $0.23360 PROPOSEO $19.97 $0.338250 $0.243870 $0.338250 $0.243870
PRESENT GCR $11.838400 iMCF OR $1.183840 iea: PROPOSED GCR $11.838400 IMCF OR $1.183840 ICCF ClIe'" ErMrormenlai SlIcharge Rider 0.00138 Proposed ErMromienlai SlIcharge Rider 0.00138 000,~~ doooao,~~, ci~~,~~,~~, dcicicicici cicicici ~~,~~, ci ci ci~ cicici ~,~~ ci cicici,~~ ci,~~ cici "õ iZ -J -, ~ õ " 0 j i- :; :: ~iå~i*mE ~~~ ~ ~;~~ ~!~ ~~~ S ~~~~~~~;~~ "" " ~ ~ ~~~~i~~~g~~i~w~~~~i~~~a~~åw~ .r 01 ; ~I u " Ul Q. 11 t; !: ~ ! ~g!~ ~ âã ~ l¡ 1 i i ã ¡ ~ 5 i i i ~ ~ § ~ 5 3 S ~ 5 ~5 S ~ ~ ~~~~~~~~~~~~ .. i! ~..i ~~~~~~5~~S!~!;~~~~~~~gß~~~~~~~;¡~ '"
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II ~ Ë II ~ "I! 0 1;¡1!ž~~ l ~ æ ~IH I~ 0. b: ~~tj~~;ri~:_ N_ ..~ ~ _I/N_W'"~~~~~ ~~ N~'" m~ NQ) ri Ñ~ ~ ~~~"':IO'"s.. ~~ ~ ~~ ~w~ ~ ~~ §I ~ IoIo~ggg8gg880000000 8888000000000000000000000888 g8 888 g g g g g 8g8 g 8:5 8 0 0 0 "š ...... N N N~ ~ ~ ~~.~~ ~ ~ ~ w~~~ø ø ø ~mm g gg :; U DELAWARE GAS BILLING COMPARISON Schedule JFJ-1 LARGE VOLUME GAS fLVGi Page 12 of 16 Current Rates Effective January 1, 2006 vs. Interim Rates Effective November 1, 2006 Delivery Rate Only M:mlhly SUMMER. TOTAL BILL WINT. TOTAL BIll Al" IMPACT. TOTAL BILL s." l.:id Present Proposed Total MOO Present Proposed Total IM ~ .... OCR 12 .ê Q9 T"'oJ "Ff. %OlFF Base OCR Total I2 .ê Q9 !s .Q ~ fB PROPOSBJ "Ff. %OIFF 5,000 658 25 $5.718 $59,219 $64.937 $5.966 $59.219 $65.188 "50 ,,% $5,118 $59,219 $54.937 $5,968 $59.219 5.000 '29 50 $3,402 $57,119 $60,561 $65.188 iiso 04% $779.247 S782.251 $3,00 04% $3,550 $57,179 $60,730 $148 ,,% $3.402 S57.179 $60.581 $3,550 S57.179 S60,130 5,000 '19 75 Sa28 $56.497 $59,125 $1,1l2 S148 ,,% $726.975 $728,155 $1,180 ,,% $56.497 $59.239 $114 ,,% S2.628 $56.497 $59,125 52,742 S56,497 559.239 10,000 1,316 25 $10.936 $118,438 $129.374 $11.415 5114 ,,% $709.498 $710,869 $\,311 ,,% $1\8,438 $129.853 "''' ,,% 510.936 $118.438 $129.374 $11,415 5118.438 $129,853 10.000 658 50 $6.30 $114.359 $120,663 $6,579 "''' 04% $1.552,493 $1.558.237 $5.744 04% $114,359 $120.937 $275 ,,% $6.30 $114,359 $120.663 $5.579 $114.359 $120,937 10,000 439 75 $0.752 $113.001 $117.63 $275 02'Y. $1,117.950 $1.451.246 $3,296 ,,% $4,969 $113,001 $117.970 1207 ,,% $4.762 $113.001 $117.753 $4,969 $113.001 $117,970 15.000 1,974 . 25 $16,154 $117,651 $193.812 1207 ,,% $1,413.156 $1.415.637 $2,481 ,,% $16.861 $117.657 $194,519 $707 04% $16.154 $177.657 $193.812 $16.861 $177.657 5191.519 15,000 987 50 $9.206 $171.538 $160,744 $707 04% $2,325.740 $2.334.224 $8,481 04% $9.607 $171.538 $181.145 "'" ,,% $9.206 $171.538 $180.744 $9.607 $171,538 $181.145 15.000 658 75 $6.890 $169.498 $176,388 S7,189 $159.498 "'" ,,% $2,168.925 $2.173,738 $4,812 02% $176.681 129' ,,% $6,890 $169,498 $176,388 $1.189 $169.498 $176.687 $299 20.000 2632 25 $21,:m $236.875 $258.249 $22.300 ,,% 52.116,65 $2,120.242 $3,588 ,,% $236.876 $259.184 $935 04% $21,372 S236,876 S258,249 $22.3OS $236,876 $259.184 $935 20.000 1.316 50 $12.108 $228.17 $240.625 $12.635 04% $3.098,987 $3.110.210 $11.224 04% $226.717 $2111.352 $527 ,,% $12.108 $228.117 $240,825 $12.635 $228.117 $241,352 20.000 an 75 $9.017 $225.995 $235.013 $527 ,,% $2.889.900 $2.895,219 $6,328 ,,% $9.409 $225.995 $235.404 $391 ,,% $9.017 $225,995 $235.013 $9,409 $225,995 S235,404 25.000 3.289 25 526.581 $391 ,,% S2,820.152 S2.824.841 l4,695 ,,% $296.089 $322.673 $27.747 5296.(l89 5323.36 51.163 04% $25,584 $296,089 $322,673 $27,747 25.000 t 64' 50 S15.010 $296,089 $323.836 $1.163 04% $3,872074 S3,885.034 $13.960 04% S285.897 S300.906 S15.66i S285.897 $301.560 1654 ,,% $15.010 $285.891 $300,906 $15,664 $285,897 25.000 1.095 75 $11.145 $301,560 1654 ,,% $3,510.876 $3.618.720 $7.844 0.2% $282.493 S293.638 SI1.628 S282.493 S29.12\ "'84 ,,% $11145 $282.193 $293.638 $11,628 $282.493 30.000 3.947 25 S31.802 S355.308 $29.121 "''' ,,% $3,523.650 $3.529.453 $5,802 ,,% S387.110 $33.193 $355.308 S368.502 $1.392 04% $31.802 $355.308 $387.110 $33.193 $355.308 30.000 1.974 50 $17.912 $368,502 $1.392 04% $4.645,321 $4.662,021 $16,100 ,,% $313.076 $360,988 $18,692 $313.076 $361.756 $760 ,,% $17.912 S3I3,076 S360,988 S18,692 30.000 1.316 75 $13.279 $343.016 $361.768 5780 ,,% l4,331,851 $4341.211 $9.360 ,,% $338.996 $352,276 S13.856 S3.6.996 $352.852 1576 ,,% $13.279 $338.996 $352.275 $13.856 $338.996 35.000 4.605 25 $37.020 $352.852 $576 ,,% $4,227,308 $4,234.220 $6,913 ,,% $114.528 $451.547 $38.640 $414.528 $453.167 $1.620 04% $31.020 $414.526 $451,541 $3..840 35.000 2.303 50 $20.814 $414.528 $453.167 $1,620 04% $5.118.568 $5.438.008 $19,440 04% $40,255 $421,069 S21,720 $400.255 $421.975 1906 ,,% 520.814 $40,255 $421,069 S21,12O $400.255 35.000 1.535 75 $15.407 $395.194 $421.975 1906 02% $5.052,825 $5.063,02 $10,8n ,,% $410.901 $16.075 $395,491 $411.569 1668 ,,% 515,407 $395.494 $410,901 $16,075 $395,494 40.000 5.263 is $42,238 $173,747 $411.569 1668 ,,% $4.930,806 $4.938.826 $8.oO 0.2% $515.985 $4,086 $473.747 $517,833 $1,848 04% $42.236 $473.747 $515.985 $4.086 $473.747 S511.833 40.000 2.632 50 $23,16 $457,434 $41.150 $24,748 $1.848 04% $6.191,814 $5,213,99 $22.180 04% $457;134 $482.183 $1,033 ,,% $23.716 $457.434 $41.150 $24,748 $45743/ $42,183 $1.033 40,000 1.754 75 $17.535 $451,991 $469,525 $18,295 0.2% $5,n3.801 $5.786,191 $12,393 02% $451.991 $470.286 $761 ,,% $17,535 $451.991 $469,525 $18,295 $451.991 $470.286 50.000 6.579 25 $52,674 $592.185 $64.859 $54.979 $161 ,,% $5.63,30 $5,643,31 $9,126 ,,% $592.185 $6i7.164 $2.305 04% $52.674 S592.185 S64.859 $54.979 $592,185 $541.164 $2,305 04% 50.000 3.289 50 $29.513 $571,787 $601,299 $30.798 $7.738.308 $7,765.967 $27.660 04% $571.781 $602.58 51.85 02% $29,513 $511.787 $601.299 $30.798 $511.87 $602.58 $1.85 50.000 2.93 75 $21.797 $56.992 $586.788 $22.742 $56.992 $587.734 ,,% $7.215.592 $1.231,013 $15,421 ,,% "." ,,% $21.797 $56.992 $586,788 $21.742 556.992 $587.73 "45 ,,% $7.M1.460 60.000 7.895 is s53,l10 S110,623 $n3.733 $65.872 $710.623 sn6,95 $2.62 0,4% $7.052.80 $11.44 ,,% $63,110 $710,623 $n3.733 S65,812 $710,623 $n6.495 $2.62 04% $9.28.801 $9,317.941 60,000 3.947 50 $35,316 $686.145 $72,462 $36,854 $686,145 $723.000 $1.538 0,2% $33.140 04% $35,316 $686.145 $721.462 $36,851 $686.145 $723,000 Sl,538 ,,% $8.651.513 $8.675,996 $18.453 60,000 2.632 75 S26.059 $671.992 $704.051 $27,189 $677.992 $705.181 $1,130 ,,% $26.059 ,,% 70,000 $677,992 SlO1.051 $27.189 $677992 $705.181 $1.130 02% S8.448,615 $8.462,111 $13.561 9,211 25 S73.547 S829.061 $902.608 $76.765 $819.061 $905.826 $3,218 04% $73.547 ,,% $829,061 $902.608 $76.765 $829.061 $905,826 $3.218 ,,% $10,831.294 $10.859.914 S38,620 04% 70,000 4.505 50 $41.120 $800.5O S841.624 $42.911 $800,50 $843.415 $1,790 0.2% $41.20 70,000 5800,50 $841.624 $42.911 $800.50 $843.415 $1,790 ,,% $10.099,493 $10.120.978 S21,485 3.070 75 $30.314 $790.987 $821,301 $31.529 $190.987 $822.616 $1,315 ,,% $30,314 ,,% $790,987 $821.301 $31.629 $790,987 $822,616 S1.15 ,,% S9.855.612 $9.871.387 $15,775 ,,%
OJSTOMER DEMAN COMMOl) TY DellverRae OiARGE Q-ARGE Q-ARGF. PRESEN S50000 $1040000 $0,10339 PROPOSED $52200 $1,350000 $010826 QQ PRESEN S620OO00 $11 021900 PROPOSED $6200000 $11.021900 EnvlraimerlalSun::har.:i PRESEN 0013n PROPOSED oonn DELAWARE GAS BILLING COMPARISON Schedule JFJ-1 Page 13 of 16 RESIDENTIAL (Rl & RESIDENTIAL SPACE HEATING (RSHl
Current Rates Effective January 1,2006 vs. Interim Rates Effective November 1, 2006 Delivery, GCR and Environmental Surcharge Rates ANNUAL _ 4 SUMMER & 8 'MNTR 4 SUMMER - TOTAL BILL PER MONl AT CONSTANTMONlLY USAGE 9 WNTR - TOTAL BILL PER MONl ANNUALIMPACT . TOTAL BILL Pr.sent MONTHLY Present Proposed Total Present Proposed S.AES Base GCR Proposed Total Annual Annual Total !2 Base Q£ Tot.i .Q Base GCR Total (CCF) ~ ~ QÇ .! DIFF. %DIFF Total Total Q! 0 $84') $i)i)O $840 $873 $0031) .. $an $033 39% $840 $000 $840 $873 $0')0 $873 $033 ,,% 1 $875 $116 $994 $9\0 $1.)7 $1017 $1)23 $10080 $104 76 $396 ,,% 23% $875 $118 $''' $910 $107 $\017 $023 23% , $911 $237 $1148 $947 $214 $1161 $013 11% $11928 $12204 $276 23% $911 $237 $1148 $947 $214 $1161 $013 11% 3 $947 $355 $1302 $965 $321 $1306 $13776 $13932 $156 11% $')1)4 03% $947 $355 $13')2 $985 $321 $1306 $')04 03% , $983 $474 $1457 $1i22 $14503 $15624 $15672 $048 03% $4 " (S007) -05% $963 $474 $1457 $11)22 $426 $1450 .1)5% 5 $1018 $592 $1610 $1059 ($')07) $17484 $17400 ($084) -05% $535 $1594 ($'LI6) -10% $1018 $592 $1611) $1059 $535 10 $1197 $1184 $2381 $1594 ($015) .10% $19320 $19128 ($192) -1,0% $1245 $1070 $2315 ($066) -28% $1197 $1184 $23 81 $1245 $11) 70 20 $1554 $2368 $2315 ($056) -28% $28572 $27780 ($792) -28% $3922 $1617 $2140 $3757 $165 -4,% $1554 $2368 $3922 $1617 25 $1732 $214') $3757 $165) -4,% $47064 $450 " $1980 -4,% $29M $4692 $1802 $2674 $4.76 ($216) -4,% $1732 $296') $4592 40 $18l:2 $2674 $4475 ($215) -4,% $56304 $53712 ($2592) -4,% $2268 $4735 $7'J,n $2360 $4279 $6639 ($354) .52% $2268 $4735 60 $70)')3 $2361) $4279 $6639 ($364) -52% $84')36 $79568 .52% $2982 $71,n $11)1)85 $3104 $6419 $95.23 ($562) -56% $2929 $711B ($4368) 19 $1.)1) 32 $3049 $6419 $9468 ($564) .56% $1.')595 $1.13836 .56% $3660 $9352 $13012 $361.) $8451 $12261 $751 .58% $3508 $9352 ($6760) Ii)i) $1286') $3652 $ß.51 $12103 $757\ .59% $1.54926 $1.45866 $9060 .58% $409 $11838 $16241 $4591 $10698 $15269 ($9581 .59% $4147 $11838 $15985 120 $4316 $10696 $15016 ($969) -61% $1.91868 $1,81284 ($11584) -60% $5123 $142')6 $19329 $5334 $12837 $18171 ($1158) .60% $4756 $14,')6 $18962 140 $4952 $12837 $17789 ($1173) -62% $2,29012 $2,14996 ($14016) -61% $5837 $16574 $22411 $6078 $14977 $21055 ($1356) -61% $5364 $16574 $21938 160 $6551 $5587 $14977 $20564 ($1374) -63% $2,65148 $2,48732 ($16416) -62% $18941 $25492 $6822 $17116 $23938 ($1554) .61% $5973 $18941 $24914 180 $6221 $17116 $23337 ($1577) -63% $3.01280 $2,82448 ($18832) .63% $7265 $21309 $28574 $7565 $19256 $26821 ($1753) .61% $6582 $21309 $27891 200 $6855 $19256 $26111 ($1780) -64% $3,37424 $3.161,72 ($21252) -63% $7979 $23677 $31656 $8309 $21395 $29704 ($1952) -62% $7191 $23677 $30868 220 $7491) $21395 $26885 ($1983) -64% $3.73568 $3.49896 ($23672) -63% $6692 $26')44 $34736 $9052 $23535 $32587 ($21.49) -62% $7799 $261)44 $33843 $8124 $23535 $31659 ($21ß.) -65% $4,09686 $3,63620 ($26068) -64% '" $9406 $28412 $37818 $9796 $25674 $i54 70 ($2348) .62% $8408 $2ß.12 $3682') 260 $8758 $25674 $3432 ($2388) .65% $4.45632 $4,17336 ($28496) -64% $10120 $31)780 $4')900 $10540 $27814 $36354 ($2546) -62% $90.17 $30760 $39797 $9393 $n~ 14 $31207 ($2590) -65% $4.61976 $4.51072 ($3091)4) -64% "0 $10834 $33148 $43982 $11283 $29953 $41236 ($2746) -62% $9526 $33148 300 $42774 $10027 $29953 $39980 ($2794) .65% $5.18120) $4.84784 -64% $11548 $35515 $47063 $12027 $32093 $44120 $2943 -63% $1.)2.34 $35515 ($33336) $45749 $10662 $321)93 $42755 ($2994 -65% $5.542.44 $5,18520 $35724 -64%
CUST OMER SUMMER WINTER "ROO & "'SH" RATE IS/CCFJ CHARGE .Al BLOCKS 1ST BlOCK TAIL BLOCK PRESENT $840 $0356930 $0356930 $0304370 PROPOSED $813 $0371791) $0371790 $0317180 CUllnt En.ír.:nmental Surcharçe Ri.jer $0 0öi Propose,j Environmental Surdiar~e Rider 000238
PRESENT GCR $11 838400 IMCF OR $1183840 /CCF PROPOSED GCR $10 697600 IMCF OR $1069761) fCCF DELAWARE GAS BILLING COMPARISON Schedule JFJ-l GENERAL GAS (GGI Page 14 of 16
Current Rates Effective January 1, 2006 vs. Interim Rates Effective November 1, 2006 Delivery, GCR and Environmental Surcharge Rates
4 SUMMER - TOTAL BILL PER MON a WN'R - TOTAL EALL PER MONT MONlH Y Present At*UAL IMPACT. TOTAL BILL Proposed Total Present Proposed Total SALES OCR OCR Tot DIFF. Total ~ !! ii °/oDIFF Sos. OCR Totl OCR Total DIFF. %D1FF PRESENT (CCF) !! ~ %D1FF 0 $19.00 $0.00 $19.00 $19.97 $0.00 $19.97 $t.97 5.1% $19.00 $0.00 $19.00 $19.97 $0.00 ~ $19.97 25 $27.05 $29.60 $0.97 5.1% $28.00 $29.64 $11.64 5.1% $5.65 $2.45 $26.74 $55.19 -$1.46 -2.6% $27.05 $2.60 $5.65 $2.45 $26.74 50 $5.19 -$1.6 -2.6% $679.80 $662.28 -$17.52 -2.6% $3.10 $59.19 $94.29 $3.93 $53.49 $90.42 -$3.87 -4.1% $3.10 $59.19 $94.29 $3.93 55.49 $90.42 -$3.87 -4.1% $1.131.48 $1.085.04 -$46.44 -4.1% 75 $4.15 $8.79 $131.94 $45.41 $8.23 $125.64 46.30 -4.8% $4.15 $8.79 $131.94 $4.41 $6.23 $125.64 -$6.30 -4.8% $1.583.28 $1.507.68 -$75.60 -4.8% 100 $51.20 $118.38 $169.58 $5.90 $106.98 $160.88 -$8.70 -5.1% $51.20 $118.38 $169.58 $5.90 $106.98 $160.88 -$8.70 ~5.1% $2.034.96 $1,930.56 -$104.40 -5.1% 200 $8.39 $236.77 $320.16 $87.82 $213.95 $31.77 418.39 -5.7% $8.39 $26.77 $320.1& $87.82 $213.95 $31.77 -$18.39 .5.7% $3,841.92 $3,621.24 -$220.68 -5.7% 300 $115.59 $35.15 $470.74 $121.75 5320.93 $42.68 -$28.06 -6.0% $115.59 $35.15 $470.74 $121.75 $320.93 $42.68 -$2.06 -6.0% $5.64.88 $5.312.16 -$36.72 -6.0% 400 $147.78 $473.54 $61.32 $155.67 $427.90 $53.57 -$37.75 -6.1% $147.78 $473.54 $621.32 $155.&7 $427.90 $53.57 -$37.75 -6.1% $7.455.84 $1,002.84 -$43.00 -6.1% 500 $179.98 $591.92 $n1.90 $189.60 $5.88 $724.48 -$47.42 -6.1% $179.98 $591.92 $n1.90 $189.60 $534.88 $724.48 -$47.42 -6.1% $9.262.80 $8,693.76 ~$59.04 -6.1% 1000 $318.84 $1.183.84 $1.502.68 $35.38 $1069.76 $1,405.14 -$97.54 -6.5% $318.84 $1,183.84 $1,502.68 $35.38 $1069.76 $1,405.14 -$97.54 -6.5% $18,032.16 $16,861.68 -$1,170.48 -6.5% 15lD $45.57 $1.775.76 $2.211.33 $47.31 $1.604.64 $2,061.95 -$149.38 -6.8% $45.57 $1.775.76 $2,211.33 $47.31 $1.604.64 $2,061.95 -$149.38 -6.8% $26.535.96 $24.743.40 -$1,792.56 -6.8% 2000 $52.30 $2,367.68 $2.919.98 $579.25 $2.139.52 $2.718.n -$21.21 -6.9% $552.30 $2.367.68 $2,919.98 $579.25 $2,139.52 $2,718.n -$201.21 -6.9% $3.039.76 25lD $669.03 $2,959.60 $3.628.63 $701.18 $32.625.24 -$2,414.52 -6.9% $2.674.40 $3.375.58 -$253.05 -7.0% $669.03 $2.959.60 $3.628.63 $701.8 $2,674.40 $3.375.58 -$253.05 -7.0% 3000 $785.76 $3.551.52 $4.543.56 $40.506.96 -$3.036.60 -7.0% $4.337.28 $83.12 $3,209.28 $4.032.40 -$34.88 -7.0% $785.76 $3.551.52 $4.337.28 $83.12 $3.209.28 $4.032.40 35lD $92.49 -$304.88 -7.0% $52.047.36 $4.388.80 -$3.658.56 -7.0% $4.143.44 $5.04.93 $945.05 $3.744.16 $4.689.21 -$36.72 -7.1% $902.49 $4.143.44 $5,04.93 $95.05 4000 $3.744.16 $4,689.21 -$36.72 -7.1% $6,551.16 $5.270.52 -$4,280.64 -7.1% $1.019.22 $4.735.36 $5,754.58 $1.066.99 $4.279.04 $5,346.03 -$408.55 -7.1% $1.019.22 $4.735.36 $5.754.58 $1.066.99 $4.279.04 $5,346.03 -$408.55 -7.1% $69,05.96 $6,152.36 -$4,902.60 -7.1% 45lD $1.135.95 $5.327.28 $6,463.23 $1.188.92 $4.813.92 $6.002.84 -$460.39 -7.1% $1.35.95 $5,327.28 $6.463.23 $1.188.92 $4.813.92 $6.002.84 -$40.39 -7.1% m.558.76 $72,03.08 -$5.524.68 -7.1% 5000 $1.252.68 $5.919.20 $7,171.88 $1,310.86 $5.34.80 $6.659.66 -$512.22 -7.1% $1.252.68 $5.919.20 $7.171.88 $1.310.86 $5.34.80 $6,659.66 -$512.22 -7.1% $86.062.56 $79,915.92 -$6,146.64 -7.1% '000 $1.486.14 $7.103.04 $8,589.18 $1.554.73 $6.418.56 $1.973.29 -$615.89 -7.2% $1.486.14 $7.103.04 $8.589.18 $1554.73 $6,418.56 $7.973.29 -$615.89 -7.2% $103.070.16 $9.679.48 -$7.390.68 -7.2% 7000 $1.719.60 $8,286.88 $10.006.48 $1.798.60 $7,488.32 $9.286.92 -$719.56 -7.2% $1.19.60 $8,286.88 $10,006.48 $1.98.60 $7.488.32 $9,286.92 -$719.56 -7.2% $120.0n.76 $111,44.04 -$8,634.n -7.2% BOOO $1.953.06 $9.470.n $11.423.78 $2.042.47 $8.558.08 $10,600.55 -$83.23 -7.2% $1.953.06 $9.470.n $11.423.78 $2,042.47 $8,558.08 $10.600.55 -$83.23 -7.2% $137.0B5.is $127,206.60 -$9.878.76 -7.2% 9000 $2.186.52 $10.65.56 $12.841.08 $2.286.34 $9.627.84 $11.914.18 -$926.90 -7.2% $2.186.52 $10.65.56 $12.841.08 $2.286.34 $9.627.84 $11.914.18 -$926.90 -7.2% $154,092.96 $142.970.16 -$11.122.80 -7.2% 10000 $2,419.98 $11.838.40 $14.258.38 $2,530.21 $10.697.60 $13.227.81 -$1.030.57 -7.2% $2,419,98 $11.838.40 $14.258.38 $2.530.21 $10.697.60 $13.227.81 -$1.030.57 -7.2% $171,100.56 $158.733.n -$12,366.84 -7.2% 12000 $2.886.90 $14.206.08 $17.092.98 $3,017.95 $12,837.12 $15,855.07 -$1,237.91 -7.2% $2,886.90 $14,206.08 $17,092.98 $3.017.95 $12,837.12 $15.855.07 .$1.237.91 -7.2% $25,115.76 $190.260.84 -$14.85.92 -7.2% 14000 $3,353.82 $16.573.76 $19.927.58 $3.505.69 $14,976.64 $18,482.33 -$1.44.25 -7.3% $3.353.82 $16.573.76 $19.927.58 $3.505.69 $14.976.64 $18.482.33 -$1.44.25 -7.3% $239.130.96 $21.787.96 -$17.343.00 -7.3% 16000 $3,820.74 $18,941.44 $2,762.18 $3.993.43 $17,116.16 $21,109.59 -$1,652.59 -7.3% $3,820.74 $18.941.44 $2.762.18 $3.993.43 $17.116.16 $21.109.59 ~$1.652.59 -7.3% $273.146.16 $253,315,08 -$19.831.08 ~7.3% 18000 $4.287.66 $21,309.12 $25,596.78 $4,481.17 $19.255.68 $23.736.85 -$1,859.93 -7.3% $4,287.66 $21,309.12 $25,596.78 $4.481.17 $19.255.68 $2,736.85 -$1,859.93 -7.3% $307.161.36 $2,842.20 -$2,319.16 -7.3% 20000 $4,754.58 $23,676.80 $2.431.8 $4.968.91 $21.395.20 $26.36.11 -$2.067.27 -7.3% $4.754.58 $23,676.80 $2.431.38 $4.968.91 $21,395.20 $26,364.11 -$2,067.27 -7.3% $31,176.56 $316.369.32 -$24,807.24 -7.3%
CUSTOM:R Sl.~R WINT "GG' RATE lSlCCFl CHARGE 1ST 750 CCF :-750 CCF 1ST 750 CCF :-750 CCF PRESENT $19.00 $0.321960 $0.23360 $0.321960 $0.23360 PROPOSED $19.97 $0.339250 $0.243870 $0.339250 $0.243870
PRESENT GCR $11.638400 IMCF OR $1.183840 tCCF PROPOSED GCR $10.697600 IMCF OR $1.069760 JCCF CLnsni ErMrormenl~ SlJchargs Rider # 0.00138 DELAWARE GAS BILLING COMPARISON Schedule JFJ-1 MEDIUM VOLUME GAS (MVGI Page 15 of 16
Current Rates Effective January 1, 2006 vs. Interim Rates Effective November 1. 2006 Delivery, GCR and Environmental Surcharge Rates
Monl~ 4 SUMMER - TOTAL BILL PER MON 8 V\NTR - TOTAL BILL PER MONT Sai&S load Present Proposed A..UAL IMPACT - TOTAL BILL Tolal Present Proposed Tolal !M MDQ Fador "os. GCR Tot" "os. Total Total 9. 11 :& GCR W& "os. GCR DIFF. PRESENT ~ I2 :& PROPOSED ~ :& 500 25 " $1211 $5.923 $1,134 $1.270 $5,326 $5,596 .$538 -7.5% 500 $1.211 $5,923 $7.134 $1.270 $5,326 $6.596 -$58 -7.5% 33 50 $874 $5,719 $6,585 $912 $5,002 $5,915 $8.606 $79,153 -$6,453 -7.5% .$671 -10.2% $874 $5.719 $6.592 $912 $5,002 $5.915 500 22 75 $761 $5,650 $6.405 $793 -$678 -10.3% $79,080 $70,976 -$8,104 -10.2% $4,894 $5,687 -$717 -11.2% $761 $5,6SO $6.412 1,000 132 25 $2,106 $793 $4,894 $5.687 -$724 -11.% $76.914 $6,250 -$8,664 -11.3% $11.846 $13.939 $2,224 $10.653 $12.877 -$1.62 -7.6% $2.106 1.000 $11.846 $13,953 $2.224 $10.653 $12,877 -$1.075 -7.7% $167.376 " 50 $1.432 $11.437 $12.856 $1,510 $10.005 $11,514 -$1.341 -10.4% $154.526 ~$12.850 -7.7% $1432 $11.437 $12,870 $1,510 $10.005 $11,514 -$1,55 -10.5% 1,000 44 75 $1.208 $11.301 $12.495 $1.271 $9,789 $154,379 $138.171 -$16.208 -10.5% $11.060 .$1,435 -11.5% $1,208 $11,301 $12.509 $1.271 $9,789 2.COD 263 25 $3,887 $23.686 $27.546 $11,060 -$1.449 -11.6% $150.047 $132.720 -$17.327 -11.5% $4.123 $21,296 $25.419 -$2,128 -7.7% $3,887 $23,686 $27,574 2,000 132 50 $4.123 $21,296 $25.419 -$2,155 -7.8% $30.775 $305,024 -$25.751 -7.8% $2.550 $22.874 $25.397 $2.704 $20,009 $2,714 -$2,683 -10.6% $2,550 2.000 $2,874 $25.424 $2,704 $20,009 $2.714 -$2,711 -10.7% $304.978 88 75 $2.101 $2,601 $24.674 $2.228 $19.577 $21.805 .$2.870 -11.6% $272562 -$32,416 -10.6% $2,101 52,601 $24,702 $2,228 $19.577 $21.805 42,897 -11.7% 3,000 395 25 $5.679 $3,533 $41,110 $6,032 $31.948 $37.981 $26.314 $261,659 -$3,655 -11.% -$3,189 -7.7% $5.679 $3.533 $41.211 $6.032 $31.948 $37,981 3,000 '" 50 $3,657 $3.305 $37,921 $3,888 -$3,230 -7.8% $494.371 $45,770 -$3.601 .7.8% $30,004 $),892 -$4.029 -10.6% $3.657 $3.305 $37,962 $3.888 3,000 132 75 $2.993 $3,902 $36.85 $3,00 $3,892 -$4.070 -10.7% $45.381 $406,706 -$4.675 -10.7% $3,184 $29,366 $32,550 -$4.3D4 -11.7% $2.993 $3,902 $3,896 4.000 526 25 $3,184 $2.366 $32,550 -$4,346 -11.8% $42,581 $30,599 -$51,982 -11.7% $7,460 $47,373 $5,m $7,931 $42.591 $5,522 -$4,255 -7.8% .$7.460 4.000 $47.373 $5 ,833 $7,931 $42,591 $5,522 -$4,310 -7.9% $657,770 263 50 $4.774 $4.742 $5.462 $5.083 $40,009 $4.091 -$5,370 -10.6% $606,268 -$51,S02 -7.8% $4,774 $4.742 $5.517 $5.083 $40.009 $4,091 ~$5,425 -10.7% 4,000 175 75 $3,876 $4,197 $49,018 $4,130 $39.145 $65.980 $51,097 -$64.883 -10.7% $4,274 -$5.743 -11.7% $3,876 $4.197 $49,073 $4.130 $39.145 $4,274 5.000 655 25 $9,251 $59.219 $68.401 $9,840 $5,244 45,798 -11.8% $58,651 $519,290 469.360 -11.8% $6,085 -$5,317 -7.8% $9,251 $59.219 $6,470 $0,84 $53.244 $63.085 5,000 32 50 $5.892 $57.179 $63.002 $6.2n $5,013 -$5,386 -7.9% $81.366 $757,014 -$6.352 -7.8% $5.291 ~$6,712 -10.7% 55,892 $57,179 $6,071 $6.2n $5.013 $5,291 5.000 219 75 $4.769 $5.497 $61,197 -$6,781 ~10.8% $756,579 $675,488 -$81.091 -10.7% $5.086 $4,933 $5,019 -$7,178 -11.7% $4,769 $5,497 $61,266 6.000 789 25 $11.032 $5.086 $4.933 $5.019 .$7,247 -11.8% $734.918 $68.230 -$8,688 -11.8% $71.059 58,009 $11.739 $63,687 $75,626 -$6.383 -7.8% $11,032 6,000 395 $71,059 58,091 $11,739 $6,887 $75.626 -$6,465 -7.9% $98.765 $97.512 50 $7.009 $68.616 $75.543 $7,472 $60,018 $67,490 .$8,053 -10.7% -Sn.252 -7.8% 6.000 $7,009 $6.616 $75,626 $7.n $6.018 $67.490 -$8,136 -10.8% $907,178 $89.879 263 75 $5.662 $6,798 $73.377 $6,042 $5,722 $6,764 -$8,613 -11.7% -$97.299 -10.7% 7.000 $5,662 $6.798 $73,460 $£"'2 $5.n2 $64.764 -$8,695 -11.8% $81.185 92' 25 $12.823 58.906 $95.632 $13,648 $74,540 $8,188 -$7,44 -7.8% $n7,l69 -$104,015 -11.8% $12,823 58,906 $95,n9 $13.648 $74.540 $8,188 -$7.541 -7.9% $1,148,360 7,000 46' 5. $8.127 $8,05 $8,08 $8.667 $70,023 $78,689 $1,058,258 -$90.102 -7.8% -$9.395 -10.7% sa.127 $B,05 $8,180 $8,667 $70,023 $78,689 7,000 307 75 $6.554 $79.099 $8,557 $6,999 -$9.491 -10.8% $l,057,n7 $94.270 -$113.507 -10.7% $68.510 $75,509 -$10.048 -11.7% $6.554 $79.099 $8,653 $6,999 8,000 1,053 25 $14,615 $94,752 $68,510 $75,509 -$10,144 -11.8% $1,027.452 $96.109 -$121,34 -11.8% $109,256 $15.558 $8,192 $100,750 -$8.506 -7.8% $14.615 $94.752 8,000 526 50 $109,366 $15.558 $8.192 $100,750 -$8.616 -7.9% $1.311.956 $1209,00 -$102,952 -7.8% $9.234 $91.48 $100.608 $9,850 $8,017 $8.868 -$10.740 -10.7% $9.234 $91.48 8,000 351 75 $100,718 $9.8SO $8,017 $8,008 -$10,851 -10.8% $1208.179 $1,078.413 -S129,766 -10.7% $7.447 $90.399 $97,736 $7.955 $78.299 $8,25 -$11,482 -11.7% $7.447 9,000 1,184 $90.399 $97,647 $7,955 $78,299 $8,25 -$11,593 -11.% $1,173.718 $1,035,048 25 $16.396 $106.592 $122.864 $17.456 $95,835 $113.292 -7.8% -$138,670 -11.8% -$9.572 $16.396 $106,592 $122,988 $17.456 $95.835 $113.292 -$9,696 -7.9% 9,000 592 50 $10.351 $102.922 $113.149 $11,045 $9,022 $1.475.355 $1,359,S02 ~$115,853 -7.9% $101,067 -$12,082 -10.7% $10.351 $102.922 $113.273 $11,045 $90.022 $101.067 9.000 395 75 sa.340 $101.700 $109,916 $8.912 $8,087 -$12,206 -10.8% $1.358,n9 $1,212.80 -$145,974 -10.7% $96,999 -$12,917 -11.8% $8,34 $101.00 $110.040 $8,912 $8,087 $96,999 10.000 1,316 25 $lS.187 $118.438 $136,487 $19.366 -$13,041 -11.9% $1,319.985 $1,163,988 -$155,997 -11.% $106,488 $125.854 -$10,633 -7.8% $18.187 $118,438 $136,625 $19.366 $106.488 10,000 655 50 $11,469 $114,359 $125,690 $125,854 -$10,ni -7.9% $1,638,951 $1,510.248 -$128.703 -7.9% $12.240 $100,027 $112,266 -$13,423 -10.7% $11,469 $114,359 $125,827 $12,240 10,000 439 75 $9,233 $100.027 $112,266 -$13.561 -10.8% $1.509.378 $1.347,196 -$162,182 -10.7% $113,001 $122,096 $9,868 $97,876 $107,744 -$14,352 -11.8% $9,233 $113,001 $122.234 $9,868 $97,876 $107,744 -$14.490 -11.9% $1.466.252 $1292,927 -$173,325 -11.8%
CUSTOPJR DEMD COMMODITY ~G.RATElWCF CHORGE CHORGE Oel/vervRale ~ PRESENT $315.00 $10.21 $0.429790 PROPOSED $3.28 $10.83 $0.456090
GCR PRESENT $6.2000 $11.027900 PROPOSED $9.8200 $9.356500 Envrorrenlal SlIchiloe PRESENT 0.01377 DELAWARE GAS BILLING COMPARISON Schedule JFJ-1 LARGE VOLUME GAS (L VGl Page 16 of 16 Current Rates Effective January 1, 2006 vs. Interim Rates Effective November 1, 2006 Delivery, GCR and Environmental Surcharge Rates Mi:nthly SUMMER - TOTAL SILL WINTR - TOTAL BILL Safes Loail Present ANNUAL IMPACT - TOTAL BILL Proposed Total Present Proposed Total !M MOO Fa,~t.)( GCR Tolal Total Total !! Q£ DIFF. %DJFF Base Q£ Base Total DIFF. PRESENT ~ ~ Q£ ~ PROPOSED .Q ~ S..)i)i) 558 25 $5,718 $59.219 $64.937 $6.'1l8 $53.244 $59.26:; -$5.675 -87% $5,718 $59,219 $64,937 $6,018 $53,244 $59.263 ($5,615) -87% $779.247 $111,\5') -$68.0)91 -87% S,W) 329 5') $3,402 $57.179 $5'),581 $3.5QoJ 550,013 $53,614 -$5,968 -115% $3.42 $57.179 $60,581 $3,Mü $50.')13 $53,614 ($6,968) -115% $726.915 $643,363 -115% 5,0')0) 219 75 $2.628 $56.497 $59.125 $2,792 $48.933 $51,725 .$7.4')0 -125% 483,612 $2.628 $56.491 $59,125 $2,792 $48.933 $51.25 ($lMO) -125% $709.498 $620,699 "J,000 1,315 25 $10,936 $118.438 $129.374 $11.515 $106,66 $118.",n -$11,371 -88% -$88,800 -125% $10.936 $118.438 $129.374 $11.'515 $105,488 $118,1)03 ($11,371) -88% $1,552.493 $1.416.036 10,000 658 50 $6.304 $114,359 $12",653 $6,519 $100,027 $1"6,705 -$13.957 -116% -$136,457 -88% $6.304 $114,359 $121),653 $6.619 $101).')27 $106,71)5 ($13.957) -11.6% $1,447,950 $1.280).462 -$167.488 -116% 10.000 439 75 $4,762 $113,001 $117,763 $5.069 $91.876 $102,945 -$14,818 -126% $4.162 $113.001 $117.763 $5.')69 $97.876 $102,945 ($14,818) -126% $\.413.156 $1.35.339 15.000 1,974 25 $16,154 $177,657 $193,812 $17,011 $159,732 $176,744 .$17,058 .88% -$177,816 -126% $16,154 $177.657 $193,812 $17.011 $159.732 $176,144 i$17.068\ -88% $2,325.740 $2.120.922 15,001) 987 50 $9.206 $171,538 $18".744 $9,757 $150.')4') $159.797 -$20.947 -116% -$204.818 -88% $9,206 $17,538 $180,744 $9.757 $150.1).) $159.97 ($2'),947) -116% $2.168,925 $1.917.561 -116% 15.00 658 75 $6.890 $169,498 $176.388 $7.339 $146,809 $154,148 -$22,240 .126% 4251,364 $6.890 $169,498 $176,388 $1.339 $146,80)9 $154.148 ($22.240) -126% $2.116.654 $1,649.714 -126% 21LOW) 2,632 25 $21,372 $236,876 $258,249 $22,508 $212.976 $235.484 -$22.65 .88% -$266,880 $21.372 $236.876 $258,249 $22.518 $212,976 $235.464 ($22.65) -8.8% $3.098.987 $2,825M8 -88% 20,000 1.316 50 $12,1')8 $228.717 $240.825 $12,835 $200,053 $212.888 -$27,937 -116% -$273,178 $12,108 $228.717 $240.825 $12.835 $2')0.')53 $212.888 ($27.937) -116% $2,889,900 $2.554,660 -$335,241 -116% 20,')00 87 75 $9.017 $225.995 $235.03 $9,609 $195,742 $2lJ5,351 -$29,662 -126% $9.017 $225.995 $235.013 $9,619 $195.742 $205,351 ($29.662) -126% $2.820,152 $2.464,208 -$355,944 -126% 25,000 3.289 25 $26.564 $296.089 $322.673 $27,997 $266.210 $294,207 -$28.465 -88% $26,564 $295,089 $322,613 $27.997 $266,210 $294,207 ($28.465) -88% $3,872074 $3,530.489 -$341,586 -88% 25.00l 1.645 50 $15,1)10 $285,897 $300.906 $15.914 $250,066 $265,980 -$34,926 -11.6% $15,1)10 $285,891 $301).916 $15,914 $25'),066 $265.960 ($34,926) -116% $3,610,876 $3.191.759 -$419.111 -116% 25,000 1,096 75 $11,145 $282.493 $293,638 $11,878 $244.675 $256.554 -$37.084 -12.6% $11145 $282.493 $293.638 $11,878 $244.675 $256.554 ($37,064) -126% $3,523,650 $3,078,643 -$445.08 -12.6% 30,0')0 3.947 25 $31,802 $355.308 $387,IN $33.493 $319.455 $352,948 -$34,162 -88% $31,802 $355,308 $387.110 $33.493 $319.455 $352,948 ($34,162) -88% $4,645,321 $4,235,315 30.')00 1.914 50 $17.912 $343.016 $360.988 $18.991 $300.080 $319.071 -$41,916 .116% -$409,946 -88% $11,912 $343,076 $360,988 $18.992 $3'JO.1)80 $319,071 ($41.9161 -116% $4,331,851 $3.828,858 -$502.993 -116% 30,OOQ 1.316 75 $13.279 $338.996 $352.216 $14.156 $293.618 $307,774 -$4.5')2 -126% $13.29 $338,996 $352,276 $14,156 $293.618 $307.774 ($4.5021 -126% $4,227,306 $3,693,283 -$534,024 -126% 35,000 4,605 25 $37,020 $414,528 $451.547 $38.99') $372.699 $411.688 -$39.859 -88% $37,020 $414,528 $451,547 $38.990 $372.699 $411.688 ($39,859) -88% $5.418,568 $4,940,261 -$418,307 -88% 35,000 2,303 50 $20.814 $4QQ,255 $421.Q69 $22.')7.) $350,093 $372,163 -$48,906 -115% $20.814 $400.255 $421,069 $22,010 $350.093 $372163 ($48,906) -11,6% $5.052.826 $4.465.957 -$586.869 -116% 35.000 1.535 75 $15.407 $395.494 $410,901 $16,425 $342,551 $358,977 -$51.924 -126% $15,407 $395.494 $410,901 $16.425 $342.551 $358.977 ($51,924) -12.6% $4.930,806 $4,301.18 -12.6% 40.000 5,263 25 $42.238 $473,747 $515,985 $4.486 $425,943 $470.429 -$45.556 -88% -$623.088 $42.238 $473,747 $515.985 $44,486 $425,943 $470.429 ($45,556) -88% $6,191.814 $5.645.141 4Q.000 2.632 50 $23.716 $457,434 $481.150 $25,148 $400,106 $425.255 -$55.895 -116% -$546.667 -88% $23.116 $457.434 $481.150 $25,148 $4')0.105 $425,255 ($55.895) -116% $5,773.801 $5.103,056 -$670.745 -116% 40,000 1.754 75 $17.535 $451,991 $469,525 $18.695 $391,484 $410,\79 -$59,346 -126% $11,535 $451,991 $459,525 $18,595 $391.464 $410,179 ($59.346) -12.6% $5,634,304 $4,922.153 -$712,152 -126% 50,000 6.579 25 $52.674 $592,185 $64.859 $55.479 $532,431 $587,910 -$56.949 -88% $52,614 $592,185 $64,859 $55.479 $532.431 $587,910 ($56,949) -88% $7,138,308 $7,054,919 -$683,388 -88% 50,000 3,289 50 $29,513 $571.787 $601,299 $31.298 $500,123 $531.421 -$69.879 -116% $29,513 $571.787 $601.299 $31,298 $500,123 $531.421 ($69,879) -116% $7,215.592 $6,371.048 -$838,545 -11,6% 50,000 2,193 75 $2\.797 $564.992 $586.788 $23.242 $489,360 $512.62 -$74.186 -126% $21,797 $564,992 $586,188 $23.242 $489,360 $512,602 ($14.186) -12.6% $7,041.460 $6.151,228 '$890,232 -12.6% 60.000 7,895 25 $63.110 $710,823 $773.733 $86,472 $638,919 $705.391 -$68,342 -88% $63,110 $710.623 $773.733 $66,472 $638,919 $105.391 ($68,342) -88% $9,264.801 $8.464,691 -$820,109 -88% 60.000 3,947 50 $35,316 $686,145 $721.462 $37.454 $600,150 $637.604 -$83,858 -116% $35.316 $686,145 $721.462 $31.454 $600.150 $637.64 ($83,858) -116% $8,657.543 $7,651,245 -$1,006,297 -11.6% 60.01JO 2,632 75 $26.059 $677,992 $704,051 $27,789 $587.236 $615.025 -$8g.'J26 -126% $26.059 $677.992 $704,051 $27,789 $587,236 $615.025 ($89,026) -126% $8.448,615 $1,380.303 -$1,068.312 -126% 70.000 9,211 25 $73.547 $829,061 $9')2.6')8 $77.465 $745.407 $822.872 -$79.736 -8.8% $73.547 $829,061 $902,608 $71,465 $745.407 $822.872 ($19.736) -88% $10.831.294 $9,874.464 -$956,830) -8.8% 10,00 4,605 50 $41.120 $800,504 $641.624 $43,611 $700,176 $743,187 -$97,837 -116% $41.20 $800.504 $811.624 $43.611 $700,116 $743,787 $97,837 -116% $10.099,493 $8,925,443 -$1,174.049 -116% 70.0.)0 3,070 75 $30.314 $790.987 $821,3')1 $32.329 $685.102 $717.43\ -$103,870 -126% $30.314 $790,981 $821.01 $32.329 $685,102 $717,431 $11)3,870 -126% $9,855,612 $8,609.172 -$1.246.440 -126%
CUSTOMER DEMAND COMMODITY De\NervRiite CHARGE CHARGE CHARGE PRESENT $50000 $7040000 $010339 PROPOSED $52200 $7350000 $010826
GCR PRESENT $6200000 $11027900 PROPOSED $9820000 $9355500
EnvrQMientalSurcharae PRESENT 001377 PROPOSED 002377 DELMARVA POWER & LIGHT COMPANY Schedule JFJ-2 Delaware - Gas Page 1 of 4 Sample Bil Stabilzation Adjustment (BSA) Calculation - Initial Month
RG GG GVFT MVG MVFT LVG LVFT 1 Actual Calendar Month Base Revenue $ 3,319,525 $ 1,219,974 $ 26,609 $ 249,425 $ 57,434 $ 113,752 $ 260,215 2 Test Year Average WN Revenue per Customer $ 32.08 $ 137.52 $ 2,660.94 $ 4,273.13 $ 3,589.62 $ 19,029.41 $ 26,021.50 3 Current Month No. of Customers 110,033 9,163 10 59 16 6 10
4 Normalized Revenue (2x3) $ 3,529,859 $ 1,260,096 $ 26,609 $ 252,115 $ 57,434 $ 114,176 $ 260,215
5 Reconciliation of Prior Month RNA - $ $ $ - $ - $ - $ - $
6 Carryover from Prior Month(s) Excess Over Cap - $ $ $ - $ - $ - $ - $
7 RNA Adjustment (4-1 +5+6) - $ 210,333 $ 40,121 $ $ 2,690 $ (0) $ 424 $ (0)
8 Budget CCF for 2nd succeeding month 5,515,475 2,952,692 93,670 1,001,538 560,070 813,860 3,224,430 9 Factor ($/CCF) (5/6) $ 0.038135 $ 0.013588 $ - $ 0.002686 $ - $ 0.000521 $ 10 Factor Cap - 10% ofWN Test Year Average Rate $ 0.063998 $ 0.042677 $ 0.028408 $ 0.025173 $ 0.010255 $ 0.014029 $ 0.008070
11 Excess Over Cap - - $ $ $ (0.028408) $ - $ (0.010255) $ $ (0.008070)
12 Amount Applied to Future Month - - $ $ $ (2,661) $ - $ (5,744) $ $ (26,021)
13 Net Factor $ 0.038135 $ 0.013588 $ 0.028408 $ 0.002686 $ 0.010255 $ 0.000521 $ 0.008070
14 Revenue Conversion Factor 1.00302 1.00302 1.00302 1.00302 1.00302 1.00302 1.00302
15 Adjusted Factor $ 0.038250 $ 0.013629 $ 0.028494 $ 0.002694 $ 0.010286 $ 0.000523 $ 0.008094 DELMARVA POWER & LIGHT COMPANY Schedule JFJ-2 Delaware - Gas Page 2 of 4 Sample Bil Stabilzation Adjustment (BSA) Calculation - Succeeding Months
RG GG GVFT MVG MVFT LVG LVFT 1 Actual Calendar Month Base Revenue $ 5,629,571 $ 2,166,521 $ 37,938 $ 273,527 $ 109,361 $ 46,794 $ 261,120 2 Test Year Average WN Revenue per Customer $ 48.25 $ 226.84 $ 3,793.83 $ 4,658.75 $ 6,835.05 $ 7,749.22 $ 26,112.02 3 Current Month No. of Customers 110,401 9,246 10 58 16 6 10 4 Normalized Revenue (2x3) $ 5,326,848 $ 2,097,363 $ 37,938 $ 270,208 $ 109,361 $ 46,495 $ 261,120
5 Reconciliation of Prior Month RNA - - $ $ $ $ $ - $ - $
6 Carryover from Prior Month(s) Excess Over Cap - - $ $ $ (2,661) $ $ (5,744) $ - $ (26,021) 7 RNA Adjustment (4-1 +5+6) $ (302,723) $ (69,159) $ $ (3,319) $ 0 $ (299) $ 0
8 Budget CCF for 2nd succeeding month 10,369,885 5,614,043 134,570 1,335,316 719,960 632,890 3,038,050 9 Factor ($/CCF) (5/6) $ (0.029192) $ (0.012319) $ - $ (0.002486) $ - $ (0.000472) $ 10 Factor Cap -10% ofWN Test Year Average Rate $ 0.051370 $ 0.037359 $ 0.028192 $ 0.020236 $ 0.015190 $ 0.007347 $ 0.008595 11 Excess Over Cap $ (0.080562) $ (0.049678) $ (0.028192) $ (0.022722) $ (0.015190) $ (0.007819) $ (0.008595) 12 Amount Applied to Future Month $ (835,419) $ (278,894) $ (3,794) $ (30,341) $ (10,936) $ (4,949) $ (26,112)
13 Net Factor $ 0.051370 $ 0.037359 $ 0.028192 $ 0.020236 $ 0.015190 $ 0.007347 $ 0.008595
14 Revenue Conversion Factor 1.00302 1.00302 1.00302 1.00302 1.00302 1.00302 1.00302
15 Adjusted Factor $ 0.051525 $ 0.037472 $ 0.028277 $ 0.020297 $ 0.015236 $ 0.007369 $ 0.008621 DELMARVA POWER & LIGHT Delaware - Gas Schedule JFJ-2 Page 3 of4 Sample Bil Stabilzation Adjustment (BSAl Calculation Monthly Weather Normalized Annualized Test Year Data Using Proposed Rates to be Effective March 1, 2007
1 Apr-05 May-05 Jun-05 Jul-05 Aug-05 Sep-05 Oct-05 2 RG Nov-05 Dec-05 Jan-06 F eb-06 Mar-06 3 Number of Customers 109,463 109,385 109,065 109,057 109,225 109,353 109,560 110,033 110,401 4 Total Delivered Sales (CCF) 110,746 110,861 111,028 9,254,920 3,404,180 2,479,035 1,575,050 1,336,015 1,655,005 2,156,915 5,515,475 10,369,885 5 Delivery Revenue 16,229,615 12,498,462 13,318,148 $ 4,897,704 $ 2,750,208 $ 2,358,134 $ 1,985,873 $ 1,889,819 $ 2,022,183 $ 2,200,036 $ 3,529,774 6 Average Use per Customer $ 5,327,012 $ 7,440,005 $ 6,102,305 $ 6,397,665 84.55 31.12 22.73 14.44 12.23 15.13 19.69 50.13 7 Average Revenue per Customer 93.93 146.55 112.74 119.95 $ 44.74 $ 25.14 $ 21.62 $ 18.21 $ 17.30 $ 18.49 $ 20.08 $ 32.08 8 Average Rate ($/CCF) $ 48.25 $ 67.18 $ 55.04 $ 57.62 $ 0.529200 $ 0.807891 $ 0.951230 $ 1.260832 $ 1.414519 $ 1.221859 $ 1.019992 $ 9 GG 0.639977 $ 0.513700 $ 0.458422 $ 0.488244 $ 0.480372 10 Number of Customers 9,171 9,128 9,099 9,092 9,087 9,090 9,101 9,163 9,246 9,279 9,303 9,308 11 Total Delivered Sales (CCF) 4,561,022 2,069,949 1,560,739 1,250,955 1,093,182 1,218,477 1,510,161 2,952,692 5,614,043 7,737,514 6,746,022 6,748,642 12 Delivery Revenue $ 1,757,546 $ 993,347 $ 814,859 $ 713,630 $ 664,663 $ 703,073 $ 797,097 $ 1,260,130 $ 2,097,374 $ 2,713,765 $ 2,441,333 $ 2,420,795 13 Average Use per Customer 497.33 226.77 171.53 137.59 120.30 134.05 165.93 322.24 607.19 833.87 725.14 725.04 14 Average Revenue per Customer $ 191.64 $ 108.82 $ 89.55 $ 78.49 $ 73.14 $ 7735 $ 87.58 $ 137.52 $ 226.84 $ 292.46 $ 262.42 $ 15 Average Rate ($/CCF) 260.08 $ 0.385340 $ 0.479890 $ 0.522098 $ 0.570468 $ 0.608007 $ 0.577009 $ 0.527823 $ 0.426773 16 GFT $ 0.373594 $ 0.350728 $ 0.361892 $ 0.358708 17 Number of Customers 10 10 10 10 10 10 10 10 10 10 10 9 18 Total Delivered Sales (CCF) 82,500 69,800 47,470 49,040 44,870 44,720 71,410 93,670 134,570 114,310 103,040 101,800 19 Delivery Revenue $ 23,492 $ 19,968 $ 13,692 $ 14,103 $ 12,961 $ 12,964 $ 20,444 $ 26,609 $ 37,938 $ 32,326 $ 29,138 $ 28,795 20 Average Use per Customer 8,250.00 6,980.00 4,747.00 4,904.00 4,487.00 4,472.00 7,141.00 9,367.00 13,457.00 11,431.00 10,30400 11,311.11 21 Average Revenue per Customer $ 2,349.24 $ 1,996.84 $ 1,369.21 $ 1,410.31 $ 1,296.13 $ 1,296.40 $ 2,044.36 $ 2,660.94 $ 3,793.83 $ 3,232.65 $ 2,913.84 $ 22. Average Rate ($/CCF) 3,199.44 $ 0.284757 $ 0.286081 $ 0.288437 $ 0.287583 $ 0.288864 $ 0.289893 $ 0.286285 $ 0.284076 23 MVG $ 0.281922 $ 0.282797 $ 0.282788 $ 0.282858 24 Number of Customers 54 53 54 54 53 51 55 59 58 57 56 57 25 Total Delivered Sales (CCF) 1,065,536 598,593 492,688 409,618 375,088 480,509 550,318 1,001,538 1,335,316 1,651,815 1,563,097 1,554,049 26 Delivery Revenue $ 251,079 $ 216,025 $ 208,005 $ 202,446 $ 204,282 $ 206,921 $ 216,096 $ 252,115 $ 270,208 $ 285,631 $ 276,601 $ 279,200 27 Average Use per Customer 19,732.15 11,294.21 9,123.85 7,585.52 7,07713 9,421.75 10,005.78 16,975.22 23,022.69 28,979.21 27,912.45 27,264.02 28 Average Revenue per Customer $ 4,649.60 $ 4,075.94 $ 3,851.94 $ 3,748.99 $ 3,854.38 $ 4,057.27 $ 3,929.02 $ 4,273.13 $ 4,658.75 $ 5,01106 $ 4,939.31 $ 29 Average Rate ($/CCF) 4,898.24 $ 0.235636 $ 0.360888 $ 0.422184 $ 0.494231 $ 0.544624 $ 0.430629 $ 0.392675 $ 0.251728 30 MFT $ 0.202355 $ 0.172919 $ 0.176957 $ 0.179660 31 Number of Customers 18 18 18 18 18 18 16 16 16 16 16 32 Total Delivered Sales (CCF) 562,280 15 520,030 386,530 381,540 410,700 424,140 435,530 560,070 719,960 643,070 623,970 578,220 33 Delivery Revenue $ 109,742 $ 107,229 $ 99,147 $ 99,555 $ 100,486 $ 101,730 $ 93,386 $ 57,434 $ 109,361 $ 105,100 $ 101,516 $ 101,985 34 Average Use per Customer 31,237.78 28,890.56 21,473.89 21,19667 22,816.67 23,563.33 27,220.63 35,004.38 44,997.50 40,191.88 38,998.13 38,548.00 35 Average Revenue per Customer $ 6,096.76 $ 5,957.18 $ 5,508.15 $ 5,530.84 $ 5,582.56 $ 5,651.68 $ 5,836.60 $ 3,589.62 $ 6,835.05 $ 6,568.75 $ 6,344.74 $ 36 Average Rate ($/CCF) 6,798.98 $ 0.195173 $ 0.206198 $ 0.256504 $ 0.260930 $ 0.244670 $ 0.239851 $ 0.214418 $ 0.102548 $ 0.151898 37 LVG $ 0.163435 $ 0.162694 $ 0.176377 38 Number of Customers 6 7 6 5 6 8 7 6 6 6 5 6 39 Total Delivered Sales (CCF) 1,115,570 665,540 565,890 483,340 419,100 559,150 644,910 813,860 632,890 984,380 594,540 796,370 40 Delivery Revenue $ 83,260 $ 111,418 $ 73,195 $ 102,667 $ 219,215 $ 80,037 $ 85,691 $ 114,176 $ 46,495 $ 56,712 $ 141,930 $ 54,712 41 Average Use per Customer 185,928.33 95,07714 94,315.00 96,668.00 69,850.00 69,893.75 92,130.00 135,643.33 105,481.67 164,063.33 118,908.00 132,728.33 42 Average Revenue per Customer $ 13,87667 $ 15,916.93 $ 12,199.10 $ 20,53336 $ 36,535.84 $ 10,004.57 $ 12,241.58 $ 19,029.41 $ 7,749.22 $ 9,451.95 $ 28,385.91 $ 9,118.61 43 Average Rate ($/CCF) $ 0.074635 $ 0.167411 $ 0.129344 $ 0.212411 $ 0.523061 $ 0.143140 $ 0.132873 $ 0.140290 $ 0.073465 $ 0.057612 44 LFT $ 0.238722 $ 0.068701 45 Number of Customers 10 10 10 10 10 10 10 10 10 10 10 10 46 Total Delivered Sales (CCF) 2,692,680 2,722,090 1,710,340 1,641,230 2,111,890 1,915,870 2,255,240 3,224,430 3,038,050 3,797,010 3,741,130 3,488,610 47 Delivery Revenue $ 271,184 $ 221,838 $ 208,406 $ 207,671 $ 212,678 $ 210,592 $ 217,346 $ 260,215 $ 261,120 $ 264,029 $ 268,973 $ 264,456 48 Average Use per Customer 269,268.00 272,209.00 171,034.00 164,123.00 211,189.00 191,587.00 225,524.00 322,443.00 303,805.00 379,701.00 374,113.00 348,861.00 49 Average Revenue per Customer $ 27,118.40 $ 22,183.83 $ 20,840.60 $ 20,767.08 $ 21,267.77 $ 21,059.25 $ 21,734.56 $ 26,021.50 $ 26,112.02 $ 26,402.86 $ 26,897.30 $ 50 Average Rate ($/CCF) $ 0.100712 26,445.56 $ 0.081496 $ 0.121851 $ 0.126534 $ 0.100705 $ 0.109920 $ 0.096374 $ 0.080701 $ 0.085950 51 GL $ 0.069536 $ 0.071896 $ 0.075805 52 Number of Customers 20 20 19 18 19 19 19 19 19 19 19 18 53 Total Delivered Sales (CCF) 360 360 345 330 330 330 330 330 330 330 315 315 54 Delivery Revenue $ 125 $ 125 $ 119 $ 113 $ 119 $ 119 $ 119 $ 119 $ 119 $ 119 $ 119 $ 113 55 Average Use per Customer 18.00 18.00 18.16 18.33 17.37 17.37 17.37 17.37 17.37 17.37 16.58 56 Average Revenue per Customer $ 6.26 $ 6.26 17.50 $ 6.26 $ 6.26 $ 6.26 $ 6.26 $ 6.26 $ 6.26 $ 6.26 $ 6.26 $ 6.26 $ 6.26 57 Average Rate ($/CCF) $ 0.347778 $ 0.347778 $. 0.344754 $ 0.341455 $ 0.360424 $ 0.360424 $ 0.360424 $ 0.360424 $ 0.360424 $ 0.360424 $ 0.377587 $ 0.357714 DELMARVA POWER & LIGHT Delaware - Gas Schedule JFJ-2 Page 4 of 4 Sample Bil Stabilzation Adjustment (BSA) Calculation Monthly Annualized Test Year Data Using Proposed Rates to be Effective March 1,2007 - w/o Weather Normallzlion
1 Apr-05 May-05 Jun-05 Jul-05 Aug-05 Sep-05 Oct-05 Nov-05 2 RG Dec-05 Jan-06 F eb-06 Mar-06 3 Number of Customers 1 09,463 109,385 109,065 109,057 109,225 109,353 109,560 110,033 110,401 110,746 110,861 111,028 4 Total Delivered Sales (CCF) 8,694,160 4,151,450 2,500,965 1,575,050 1,336,015 1,413,135 1,804,385 4,928,915 11,213,975 13,889,105 12,621,242 12,703,038 5 Delivery Revenue $ 4,696,700 $ 3,018,065 $ 2,367,141 $ 1,985,873 $ 1,889,819 $ 1,922,840 $ 2,073,673 $ 3,319,525 $ 5,629,571 $ 6,601,066 $ 6,146,314 $ 6,177,185 6 Average Use per Customer 79.43 37.95 22.93 14.44 12.23 12.92 16.47 44.79 101.57 125.41 113.85 114.41 7 Average Rate ($/CCF) $ 0.540213 $ 0.726990 $ 0.946491 $ 1.260832 $ 1.414519 $ 1 .360691 $ 1.149241 $ 0.673480 $ 0.502014 8 GG $ 0.475269 $ 0.486982 $ 0.486276 9 Number of Customers 9,171 9,128 9,099 9,092 9,087 9,090 9,101 9,163 9,246 9,279 9,303 9,308' 10 Total Delivered Sales (CCF) 4,408,092 2,257,209 1,565,999 1,250,955 1,093,182 1,166,307 1,430,981 2,807,722 5,863,683 7,044,934 6,782,942 6,566,192 11 Delivery Revenue $ 1,715,186 $ 1,045,216 $ 816,316 713,630 $ $ 664,663 $ 688,622 $ 775,165 $ 1,219,974 $ 2,166,521 $ 2,521,927 $ 2,451,559 2,370,258 12 Average Use per Customer 480.66 247.28 $ 172.11 137.59 120.30 128.31 157.23 306.42 634.19 759.23 729.11 705.44 13 Average Rate ($/CCF) $ 0.389099 $ 0.463057 $ 0.521275 $ 0.570468 $ 0.608007 $ 0.590430 $ 0.541702 $ 0.434507 $ 0.369481 14 GFT $ 0.357977 $ 0.361430 $ 0.360979 15 Number of Customers 10 10 10 10 10 10 10 10 10 10 10 9 16 Total Delivered Sales (CCF) 82,500 69,800 47,470 49,040 44,870 44,720 71,410 93,670 134,570 114,310 103,040 101,800 17 Delivery Revenue $ 23,492 $ 19,968 $ 13,692 $ 14,103 $ 12,961 $ 12,964 $ 20,444 $ 26,609 $ 37,938 $ 32,326 29,138 18 Average Use per Customer 8,250.00 $ $ 28,795 6,980.00 4,747.00 4,904.00 4,487.00 4,472.00 7,141.00 9,367.00 13,457.00 11,431.00 10,304.00 19 Average Rate ($/CCF) 11,311.11 $ 0.284757 $ 0.286081 $ 0.288437 $ 0.287583 $ 0.288864 $ 0.289893 $ 0.286285 $ 0.284076 $ 0.281922 20 MVG $ 0.282797 $ 0.282788 $ 0.282858 21 Number of Customers 54 53 54 54 53 51 55 59 58 57 56 57 22 Total Delivered Sales (CCF) 825,000 698,000 474,700 490,400 448,700 447,200 714,100 936,700 1,345,700 1,143,100 1,030,400 1,018,000 23 Delivery Revenue $ 248,787 $ 219,052 $ 208,094 $ 202,446 $ 204,282 $ 205,795 $ 214,521 $ 249,425 $ 273,527 $ 277,019 $ 277,100 $ 276,874 24 Average Use per Customer 15,277.78 13,169.81 8,790.74 9,081.48 8,466.04 8,768.63 12,983.64 15,876.27 23,201.72 20,054.39 18,400.00 17,859.65 25 Average Rate ($/CCF) $ 0.301560 $ 0.313828 $ 0.438369 $ 0.412818 $ 0.455275 $ 0.460185 $ 0.300408 $ 0.266281 $ 0.203260 26 MFT $ 0.242340 $ 0.268924 $ 0.271978 27 Number of Customers 18 18 18 18 18 18 16 16 16 16 16 15 28 Total Delivered Sales (CCF) 562,280 520,030 386,530 381,540 410,700 424,140 435,530 560,070 719,960 643,070 623,970 578,220 29 Delivery Revenue 109,742 $ $ 107,229 $ 99,147 $ 99,555 $ 100,486 $ 101,730 $ 93,386 $ 57,434 $ 109,361 105,100 30 Average Use per Customer $ $ 101,516 $ 101,985 31,237.78 28,890.56 21,473.89 21,196.67 22,816.67 23,563.33 27,220.63 35,004.38 44,997.50 40,191.88 38,998.13 31 Average Rate ($/CCF) 38,548.00 $ 0.195173 $ 0.206198 $ 0.256504 $ 0.260930 $ 0.244670 $ 0.239851 $ 0.214418 $ 0.102548 32 LVG $ 0.151898 $ 0.163435 $ 0.162694 $ 0.176377 33 Number of Customers 6 7 6 5 6 8 7 6 6 6 5 6 34 Total Delivered Sales (CCF) 1,085,220 721,810 567,770 483,340 419,100 535,590 612,590 773,990 660,980 896,410 597,790 774,870 35 Delivery Revenue $ 82,937 $ 112,017 $ 73,215 $ 102,667 $ 219,215 $ 79,786 $ 85,347 $ 113,752 $ 46,794 $ 55,776 $ 141,964 $ 54 ,483 36 Average Use per Customer 180,870.00 103,115.71 94,628.33 96,668.00 69,850.00 66,948.75 87,512.86 128,998.33 110,163.33 149,401.67 119,558.00 129,145.00 37 Average Rate ($/CCF) $ 0.076424 $ 0.155189 $ 0.128951 $ 0.212411 $ 0.523061 $ 0.148968 $ 0.139322 $ 0.146969 $ 0.070795 $ 0.062221 $ 0.237482 38 LFT $ 0.070312 39 Number of Customers 10 10 10 10 10 10 10 10 10 10 10 10 40 Total Delivered Sales (CCF) 2,692,680 2,722,090 1,710,340 1,641,230 2,111,890 1,915,870 2,255,240 3,224,430 3,038,050 3,797,010 3,741,130 3,488,610 41 Delivery Revenue $ 271,184 $ 221,838 $ 208,406 $ 207,671 $ 212,678 $ 210,592 $ 217,346 $ 260,215 $ 261,120 $ 264,029 $ 268,973 $ 264,456 42 Average Use per Customer 269,268.00 272,209.00 171,034.00 164,123.00 211,189.00 191,587.00 225,524.00 322,443.00 303,805.00 379,701.00 374,113.00 348,861.00 43 Average Rate ($/CCF) $ 0.100712 $ 0.081496 $ 0.121851 $ 0.126534 $ 0.100705 $ 0.109920 $ 0.096374 $ 0.080701 $ 0.085950 $ 0.069536 44 GL $ 0.071896 $ 0.075805 45 Number of Customers 20 20 19 18 19 19 19 19 19 19 19 18 46 Total Delivered Sales (CCF) 360 360 345 330 330 330 330 330 330 330 315 315 47 Delivery Revenue $ 125 $ 125 119 $ $ 113 $ 119 $ 119 $ 119 $ 119 $ 119 $ 119 $ 119 $ 113 48 Average Use per Customer 18.00 18.00 18.16 18.33 17.37 17.37 17.37 17.37 17.37 17.37 16.58 17.50 49 Average Rate ($/CCF) $ 0.347778 $ 0.347778 $ 0.344754 $ 0.341455 $ 0.360424 $ 0.360424 $ 0.360424 $ 0.360424 $ 0.360424 $ 0.360424 $ 0.377587 $ 0.357714 1 DELMARVA POWER & LIGHT COMPANY 2 TESTIMONY OF KEMM C. FARNEY, PhD 3 BEFORE THE DELAWARE PUBLIC SERVICE COMMISSION 4 CONCERNING AN INCREASE IN GAS BASE RATES 5 DOCKET NO. 06-
6 1. Q: Please state your name and position. and business address.
7 A: My name is Kemm C. Farney. I am a Lead Analyst, Cost Allocations and
8 Economic Analysis, for Pepco Holdings Inc. ("PHI"). I am testifying on behalf of
9 Delmarva Power & Light Company ("Delmarva", "the Company").
10 2. Q: What are your responsibilties at PHI?
11 A: I am responsible for the forecasting and economic analysis activities at
12 PHI pertaining to our regulated businesses.
13 3. Q: What has been your professional experience?
14 A: Prior to joining PHI, I was the Principal or Vice President responsible for the
15 utility practice at Global Insight, Inc. and its predecessor companies DRI- WEF A,
16 WEF A and Chase Econometrics. I also held this same position with Resource
17 Strategies, the US consulting arm of the British firm CRU, Inc. Between 1980
18 and 2005 I assisted more than 125 utilities around the world as they met their
19 planning and forecasting challenges.
20 In the early and mid 1990s I served as Corporate Economist and Principal
21 Planning Executive for NIPSCO Industries, the holding company for Northern
22 Indiana Public Service Company (NIPSCO). This company now does business as
23 NiSource, Inc. At that time NIPSCO was the fourteenth largest gas distribution
24 company in the US and a Fortune 500 service company. My responsibility was to
1 1 direct the corporation's economic forecasting, strategic planning, merger and
2 acquisition analysis, corporate financial modeling and sales forecasting. I also
3 directed special studies for the Chief Financial Offcer and the Chief Executive
4 Officer and chaired various budgeting committees.
5 4. Q: What was your earlier experience?
6 A: Before joining NIPS CO, I was director of the Harry A. Cochran Research
7 Center, located in Temple University's School of Business and Management. The
8 Cochran Research Center is Temple University's bureau of business and
9 economic research. I also served as contracts and grants officer for the School of
10 Business. While at Temple I completed a number of consulting projects for the
11 US Department of Energy/Energy Information Agency.
12 Still earlier I was Senior Research Economist at the Florida Public Service
13 Commission. My service at the Florida Commission began immediately after the
14 passage of the Public Utilities Regulatory Policy Act of 1978, an exciting time
15 fraught with uncertainty and change, not unlike today. I have also worked
16 extensively with the commercial real estate and fisheries industries, and I have
17 taught undergraduate and graduate level economics and statistics at Florida State
18 University, The University of North Carolina at Charlotte, The University of
19 California at Santa Barbara, Temple University, Philadelphia University, Chestnut
20 Hill College, Drexel University and Villanova University.
2 i 5. Q: What is your academic traininl!?
22 A: During my academic career I studied at Brevard Community College,
23 Harvard University, Florida State University and The University of California at
2 1 Santa Barbara. I hold a bachelor of arts, masters of science and doctor of
2 philosophy degree from Florida State University, all in economics. My fields
3 within economics were econometrics and mathematical statistics, resource
4 economics and intellectual history, especially as it relates to capital theory. My
5 dissertation studied the prediction of construction cost overrns in large budgeted
6 capital expenditures such as nuclear power plants.
7 6. Q: Have you testifed before the Delaware Public Service Commission?
8 A: No.
7. Q: Have you served as an expert witness before?
9 A: Yes, many times. I have served as an expert witness on economic and
10 forecasting issues relating to gas and electric utilities before the Florida Public
11 Service Commission, the Iowa Commerce Commission, the Ohio Department Of
12 Development Division Of Energy, the US Senate Committee On Energy and
13 Natural Resources, the Indiana Utility Regulatory Commission and the Public
14 Service Commission Of Kentucky.
15 8. Q: What is the purpose of your testimony?
16 A: The purpose of my testimony is to support the Company's Application for
17 an increase in Gas Base Rates. I am sponsoring the calculation of weather
18 normalized gas sales by rate class during the test year. These calculations were
19 prepared by me, with the assistance of other analysts.
20 I am also sponsoring a discussion of the sensitivity of natural gas
21 consumption to changes in the real price of natural gas. I will be presenting
3 1 estimates of this sensitivity. These estimates were prepared by me, with the
2 assistance of other analysts.
3 Finally, I am sponsoring a calculation of the contribution to the gas design
4 day that is made by those customers whose sales are not controlled by contractual
5 Maximum Daily Quantities (MDQs) - the Residential Non-Space Heat, the
6 Residential Space Heat, General, Medium Volume and General Volume customer
7 classes. Once again, these estimates were prepared by me, with the assistance of
8 other analysts.
9 9. Q: Why is the weather normalization of natural l!as sales important?
10 A: The consumption of natural gas is very weather sensitive. Most of the
11 weather sensitive demand for gas is derived from the need for heated space, either
12 for businesses or homes. It is desirable to know what the demand for natural gas
13 would be if the weather was "normaL." The actual sales data from the test year
14 reflects actual weather conditions that were different from normal, and the goal is
15 to remove that weather effect from the actual sales data.
16 10. Q: How is normal weather defined?
17 A: Many different definitions of normal weather are used for different
18 purposes. Normal weather is defined in this calculation as the average number of
19 Heating Degree Days (HDD) in each calendar month over the thirty year period
20 1976 to 2005. For an individual day, the number of the HDD that occur is defined
21 as the average of the hourly temperatures differenced from a comfort threshold of
22 65 degrees Fahrenheit if the average is below the comfort threshold, or zero if the
23 average is above the comfort threshold. HDD for each of the days in the month
4 1 are summed to total monthly HDD, and then averaged by month over the thirty
2 year period 1976 to 2005 to yield monthly normal HDD. It is important to keep
3 in mind that since normal HDD is calculated as a statistical average, it also has a
4 standard deviation - in other words, normal weather is not known with certainty
5 and any estimate of normal weather will have some dispersion to reflect this
6 uncertainty.
7 11. Q: What estimates of weather normalization adjustments to natural l!as sales
8 have been prepared?
9 A: I have prepared estimates of the adjustment to sales by month and revenue 10 class during the test year to reflect the impact on natural gas sales of actual
11 weather that differed from normal weather.
12 12. Q: When were these estimates prepared? 13 A: These estimates were finalized in mid-July of 2006. They were prepared 14 over a period of several months. The estimates take advantage of new statistical
15 work that is completed each year in support of our annual planning and budgeting 16 cycle.
17 13. Q: How is the calculation conducted? 18 A: For each revenue class - Residential Non Space Heat, Residential (with
19 natural gas space heat), General and Medium Volume - we estimate Weather
20 Normalization Factors that measure the increase in natural gas consumption that
21 is associated with a change in HDD. These Weather Normalization Factors are on 22 a per customer basis.
5 1 These Weather Normalization Factors are taken from the Delmarva
2 natural gas sales model that is used in our annual planning and budgeting cycle
3 for all applications involving the forecasting of sales, and especially in estimating
4 the impact of weather on sales. This sales model is developed, maintained and
5 used under my direction.
6 14. Q: What are the weather normalization factors that were used in these
7 calculations?
8 A: The Weather Normalization Factors that we are currently using are
9 0.000485 mcf/customer/HDD for the Residential Non-Space Heat customer class,
10 0.011218 mcf/customer/HDD for the Residential Space Heat customer class, and
11 0.047842 mcf/customer/HDD for the General customer class. These Weather
12 Normalization Factors were re-estimated during this present planning cycle, and
13 are reflective of internal Company data through April 2006.
14 15. Q: Do YOU have a Schedule presentinl! the estimated weather normalization 15 adjustments? 16 A: Yes, I do. It is titled Schedule KCF-l.
17 16. Q: Would you describe the material presented in your Schedule?
18 A: Yes. Schedule KCF -1 reports the calculated Weather Normalization
19 Adjustments by month and revenue class. Each monthly value is equal to the 20 departure from normal weather multiplied by the appropriate Weather
21 Normalization Factor and the number of customers. The right-most column, titled
22 Total Effect, reports the sum of the Weather Normalization Adjustments for the 23 three revenue classes.
6 1 17. Q: Have you also studied the sensitivity of natural l!as consumption to chanl!es
2 in the real price of l!as?
3 A: Yes. The consumption of natural gas is very sensitive to the real price of
4 natural gas, and the real price of natural gas has been rising for more than a
S decade. The result has been that consumers have measurably reduced their
6 consumption of natural gas, and they continue to conserve natural gas as a result
7 of real price increases.
8 18. Q: You use the phrase "the real price of natural l!as." What does that mean?
9 A: From year to year, the purchasing power of our money changes as the
10 result of inflation. Usually, the purchasing power of our money goes down as a
11 result of the general price level going up. Economists have always known that
12 consumers are aware that their purchasing power changes over time, and they
13 react accordingly. Some individual prices go up faster than others, making those
14 commodities relatively more expensive. Consumers are aware of these relative
15 price changes almost as quickly as they happen, and they quickly change their
16 consumption habits.
17 19. Q: Do you have an Schedule showiul! the real and nominal price of natural l!as?
18 A: Yes, I do. It is titled Schedule KCF-2.
19 20. Q: How should Schedule KCF-2 be interpreted?
20 A: Nominal prices, the prices actually paid by the Residential Non-Space
21 Heat customer class is depicted as the black line. The red line is the estimated
22 real price of natural gas, expressed in dollars that have the same purchasing power
23 that they had in 200S. In order to convert prices into real terms I have used the
7 1 Consumer Price Index for All Urban Consumers that is published each month by
2 the US Deparment of Labor Bureau Of Labor Statistics. I have expressed these
3 real prices in 2005 dollars, because we all have an intuition for the purchasing
4 power that we enjoyed in 2005. As you can see, real natural gas prices have been
5 steadily rising.
6 21. Q: Is it possible to measure the effect of chanl!inl! prices on consumer behavior?
7 A: Yes, it is. Delmara has been measuring these statistical relationships for
8 many years, simply because it is so very important to our business.
9 22. Q: Have you prepared an Schedule that ilustrates how consumers respond to
10 chanl!inl! real natural l!as prices?
11 A: Yes, I have. It is Schedule KCF-3.
12 23. Q: How should we interpret this Schedule?
13 A: This Schedule presents a calculation of just how sensitive consumers are
14 to a change in the real price of natural gas. In the left most column I have listed
15 the five customer classes that we customarily use - Residential Non-Space Heat,
16 Residential Space Heat, General, Medium Volume and Large Volume customers.
17 24. Q: How should we interpret the column titled Price Factor?
18 A: The price factors are taken from the same statistical models that we use for
19 weather normalization, sales budgeting and planning. Just like the Weather
20 Normalization Factors described above, they are regression coeffcients drawn from
21 our statistical modeL. Each Price Factor measures the change in natural gas
22 consumption, measured in mcf, of a one cent change in the delivered price of gas to
23 that customer class, measured as average revenue per mcf in real 2005 dollars.
8 1 For example, the Price Factor for the Residential Non-Space Heat
2 customer class is -1919.418, meaning that a conceptual one cent increase in the
3 real price of natural gas will cause the Residential Non-Space Heat customer class
4 to reduce their monthly natural gas consumption by 1,919 mcf.
5 Notice that at the bottom of this column, we use this approach to calculate
6 that if the real price of natural gas measured in 2005 dollars is raised by one cent
7 for each of our customer classes, their aggregate monthly consumption of natural
8 gas wil be reduced by 43,776 mcf. I calculate that during our test year this would
9 have represented a reduction in sales of approximately 3.8%.
10 In short, consumer's response to an increase in the real price of natural gas
11 is short and swift. It comes quickly, it is measurable, and it is significant.
12 25. Q: You say that a conceptual one cent across the board price increase would
13 decrease consumption in the test year by 43.776 mcf. How confident are yOU
14 in that estimate?
15 A: Realizing that nothing is ever known with certainty as a result of statistical
16 analysis, I am very confident. I have calculated that the standard error of the
17 monthly estimate of a decrease of 43,776 mcf is 4,186 mcf. If you will allow me
18 to interpret these results in everyday language, I would draw three conclusions
19 from this result - first, we can be absolutely certain that the effect is negative and
20 large, and that 43,776 mcf is at the center of a relatively narrow band of
21 uncertainty. Second, we can say with 90% certainty that the reduction would be
22 within a range of plus or minus about two standard deviations, or between 37,032
23 mcf and 52,148 mcf. Finally, we can say with the same certainty as the flp of a
9 1 coin (50%) that the reduction would be within a range of plus or minus
2 approximately one standard deviation, or between 39,590 mcf and 47,962 mcf.
3 Clearly, even though we do not know the magnitude of this effect with
4 certainty, we must agree it is very large.
5 26. Q: How should we interpret the third column. titled "Price"?
6 A: The column titled "Price" is the proxy that we use for the price that the
7 customer pays for energy in the form of natural gas. It is measured as the average
8 revenue per mcf sold for that specific class of customer. For example, the average
9 price per customer paid by the Residential Non-Space Heat customer class during
10 the test year was $18.62/mcf.
11 27. Q: How should we interpret the fourth column. titled "Sales"?
12 A: The column titled "Sales" is our unit sales of natural gas measured in mcf
13 to each of the customer classes during the test year. For example, the sales to the
14 Residential Non-Space Heat customer class during the test year were 22,701.74
15 mcf.
16 28. Q: How should we interpret the tifth column. titled "Price Elasticity"? 17 A: The column titled "Price Elasticity" is my calculation of the pnce
18 elasticity for that customer class, based upon our most recent statistical studies. A
19 price elasticity is a metric used by economists to quantify the sensitivity of a
20 consumer to a change in a real price. Technically, it is defined as the estimated 21 percentage change in a consumer's consumption, measured in physical units,
22 given a 1 % change in the price of that commodity. For example, referrng again 23 to our industrial customers, we see that the Large Volume customer class has a
10 1 price elasticity of -3.79. This value implies that a one percent increase in the
2 price of natural gas would cause them to reduce their energy consumption by an
3 estimated 3.79%. Similarly, the Residential Non-Space Heat customer class
4 would reduce its consumption of natural gas by 1.57%. Their demand for natural
5 gas is also very elastic, reflecting the fact that they have many energy choices that
6 are available to them. In contrast, the Residential Space Heat, General and
7 Medium Volume customer classes are relatively price inelastic. When prices
8 change, their response is muted in comparison.
9 29. Q: Would YOU consider these results typical for natural l!as utilties? lOA: Yes, absolutely. These results are consistent with the results I have 11 obtained in previous studies for the Company. These results are also consistent 12 with results I have obtained in similar studies completed for other North
13 American natural gas local distribution companies.
14 30. Q: Have YOU prepared an estimate of the contribution to system peak day sales
15 that is attributable to the Residential. General. Medium Volume and Larl!e
16 Volume customer classes? 17 A: Yes, I have. 18 31. Q: What do you calculate to be the system peak day sales? 19 A: I calculate that the peak day sales in January of the test year would have 20 been 164,952 mcf if there had been 65 heating degrees on that peak day. This
21 calculation includes our Minimum Daily Quantity (MDQ) obligations of 12,281
22 mcf for the Medium Volume customer class and 4,599 mcf for the Large Volume
11 1 customer class. Notice that this is a bottom up calculation of system peak day
2 sales with 65 heating degrees on that day.
3 32. Q: Have you prepared a Schedule iIustratinl! your calculation? 4 A: Yes, I have. It is included as Schedule KCF -4.
5 33. Q: Would you please explain this Schedule?
6 A: Schedule KCF-4 consists of six columns. The first five columns report
7 calculations for the Residential Non-Space Heat, the Residential Space Heat,
8 General, Medium Volume and Large Volume customers. The sixth column
9 reports the totals of the first five columns.
10 The first line in the table, labeled Monthly Sales, reports the monthly sales
11 actually observed in January of the test year.
12 The second line in the table, labeled January Gas HDD, reports that 764
13 Heating Degree Days were actually observed during January of the test year.
14 HDD were defined previously.
15 The third line in the table, labeled WN Factor, reports the sensitivity of the
16 average customer to a one unit change in HDD. In other words, if the Heating
17 Load on the system increases by one HDD, either during the month or on the
18 design day, the average customer in that class wil increase its consumption by the
19 amount of the Weather Normalization Factor. For example, ifHDD increases by
20 one HDD, the average Residential Non-Space Heat customer will increase its
21 consumption of gas by 0.0009 mcf. As discussed above, these Weather
22 Normalization Factors are drawn from the Delmarva Power sales model, and they
23 are used by the Company in all weather normalization calculations.
12 i The fourth line in the table, labeled January Customers, reports the
2 number of customers connected to the system during January of the test year.
3 The fifth line in the table, labeled January HDD Weather Effect, reports
4 the calculated weather normalization adjustment for January of the test year, by
5 customer class. For example, the Residential Non-Space Heat customer class
6 reports a HDD weather sensitivity of 8,340 mcf for the month of January of the
7 test year. This is equal to the observed HDD during the month multiplied by the
8 Weather Normalization Factor and then multiplied by the number of customers.
9 It represents the amount by which sales would have increased if no HDD had
10 been observed during the month.
11 The sixth line in the table, labeled January Seasonal Effect, represents an
12 amount of seasonal (January) sales that occurs with great regularity, but does not
13 seem to be related to HDD. This Effect is taken from the Delmarva Power sales
14 model, and is the coeffcient on a categorical variable that takes on the value of i
15 during the month of January and zero at other times. As an example, the
16 Residential Non-Space Heat customer class normally increases its January natural
17 gas consumption by 2,723 mcf, independent of the number of observed HDD.
18 The seventh line in the table, labeled January Non Weather Sales,
19 represents the amount of sales during January of the test year that is not explained
20 by the Weather Normalization Factor or the January Seasonal Effect. It is equal
21 to January Monthly Sales less the January HDD Weather Effect and the January
22 Seasonal Effect. For example, during January of the test year the consumption of
13 1 the average Residential Non-Space Heat customer that was not related to the
2 weather in any way was 27,067 mcf.
3 The eighth line in the table, labeled January Non- Weather Usage per Day,
4 reports the January Non-Weather Sales divided by the number of days in the
5 month (31 days). For example, the Residential Non-Space Heat customer class
6 had an average non-weather sensitive usage of 873/mcf/day during January of the 7 test year.
8 The ninth line in the table, labeled August Total Usage per Day, reports a
9 similar calculation that is sometimes used in cost of service studies to estimate
lOnon-weather sensitive usage per day. We include it here as another mutually
11 confirming calculation. It simply represents sales during the August prior to the
12 January of the test year divided by the number of days in August (31 days). In
13 examining the right-most column, it is felt that this is mutually confirming with 14 the calculation being used here. We prefer using January data, however, since it
15 is more reflective of the actual January experience. 16 The tenth line in the table, labeled Design Degree Days, simply reports
17 that for the purpose of calculating sales on the day of peak system throughput we
18 use the design criteria of zero degrees Fahrenheit, which implies 65 HDD for that 19 day. 20 The eleventh line in the table, labeled Design HDD Weather Effect, is
21 simply equal to the Design Degree Days multiplied by the Weather Normalization
22 Factor and then multiplied by the number of customers on the system during
23 January of the test year. It represents the amount of natural gas consumption that
14 1 would result from a design day with zero degrees Fahrenheit. For example, if a
2 single day was observed during January of the test year with 65 HDD the increase
3 in natural gas consumption by the Residential Non Space Heat customer class
4 would be 710 mcf.
5 The twelfth line in the table, labeled Design Seasonal Weather Effect,
6 reports the Seasonal Adjustment Factor reported above. It simply takes the
7 January Seasonal Effect and expresses it on a daily basis by dividing by the
8 number of days in the month (31 days). For example, the average customer in the
9 Residential Non-Space Heat customer class increased its consumption by 88
10 mcf/day during January of the test year.
11 The thirteenth line in the table, labeled MDQs For Design Day, reports the
12 Maximum Daily Quantities that we are contractually obligated to serve for the
13 Medium Volume and Large Volume customer classes. These totals were not
14 calculated by me, and were sponsored by another Company witness, Mr. Driggs.
15 The fourteenth and final line in the table, labeled Design Day Total,
16 contains my calculation of the sales that would be made to each customer class on
17 a day in January of the test year that met our design criteria of zero degrees
18 Fahrenheit. For example, on a day during January of the test year that met our
19 design criteria, the Residential Non-Space Heat customer class would have
20 consumed 1,671 mcf. This value is equal to the sum of the January Non-Weather
21 Usage per Day plus the Design Day HDD Weather Effect plus the Design
22 Seasonal Weather Effect.
15 1 Finally, in the lower right hand corner of the Schedule we see that given
2 all of these assumptions and calculations, if the system experienced a design day
3 during January of the test year, the system would have seen total retail sales on
4 that day of 164,952 mcf. This calculation includes the MDQs, for which we are
5 legally responsible. It does not include losses of any kind.
6 34. Q: Is this estimate reasonable?
7 A: Yes, it is. It is consistent with the calculations of our customers' weather
8 sensitivity to sales that we use in our sales forecasting and in the weather
9 normalization of sales for financial reporting.
10 35. Q: Are you sponsorinl! any Pre-cost adjustments in this fiinl!?
11 A: Yes, I am sponsoring the Company's Weather Normalization Pre-cost
12 adjustment.
13 36. Q: Does this complete your testimony?
14 A: Yes, it does.
16 Schedule KCF-1
Delmarva Power & Light Company
Weather Adjustment To Sales (mcf) Residential Residential Non-Heat Heat Commercial Total Effect Effect Effect Effect Apr-05 297 55,779 22,465 78,540 May-05 (394 ) (74,333) (29,816) (104,544) Jun-05 (12) (2,181) (874) (3,066) Jul-05 0 0 0 0 Aug-05 0 0 0 0 Sep-05 127 24,060 9,605 33,792 Oct-05 185 35,068 13,993 49,245 Nav-05 306 58,350 23,338 81 ,994 Dec-05 (440) (83,969) (33,764) (118,172) Jan-06 1,215 232,836 93,596 327,647 Feb-06 (63) (12,215) (4,915) (17,194) Mar-06 316 61,195 24,592 86,104
Annual 1,536 294,589 118,220 414,345 Schedule KCF-2
Delmarva Power & Light Company
The Real and Nominal Price Of Natural Gas
To Delmarva Residential Non-Space Heat Customers
22.00 20.00
1) 18.00 E 16.00--u-. ~ c: 14.00 ..0.- ...'.. ._., , , , ...~ ' ~Q)~ 12.00 .. # .g 10.00 ' a. 8.00 6.00 4.00 Jan-92 Jan-94 Jan-96 Jan-98 Jan-OO Jan-02 Jan-Q4 Jan-06
- - - . Real (2005$) - Nominal Schedule KCF-3
Delmarva Power & Light Company
Consumers Response To Changing Real Natural Gas Prices
PHI Sales Forecast Model Estimated Price Coefficients as of 6/5/06 (mcf or 2005 $) Price Sales Price Customer Class Price Factor ( cents/met) (met) Elasticitv Residential Non Heat -1919.418 18.62 22,701.74 -1.5741 Residential Heat -11717.34 16.13 617,590.64 -0.3059 General -2077.374 13.95 352,616.92 -0.0822 Medium Volume -3292.998 12.84 93,011.78 -0.4546 Large Volume -24768.84 10.02 65,460.67 -3.7926
Monthly Impact of a 1 cent/mcf Price Increase -43,776 mef Schedule KCF-4
Delmarva Power & Light Company
Construction of Gas Design Day Estimate
With January Customers RES RSH GVG MVS LVS Total January Monthly Sales 38,130 1,350,815 705,711 2,094,656
January Gas HOD 764 764 764 WN Factor 0.0009 0.0138 0.0665 January Customers 11,933 98,836 9,278 January HOD Weather Effect 8,340 1,044,204 470,914 1,523,458
January Seasonal Effect 2,723 161,105 70,618 234,447
January Non Weather Sales 27,067 145,506 164,179 336,751 January Non Weather Usage/Day 873 4,694 5,296 10,863
August 2005 Total Usage/Day 372 3,939 3,529 7,840 Desi~in Day Calculation Design Degree Days 65 65 65 Design HOD Weather Effect 710 88,861 40,075 146,526 Design Seasonal Weather Effect 88 5,197 2,278 7,563 MOOs For Design Day 12,281 4,599 16,880
Design Day Total 1,671 98,752 47,649 12,281 4,599 164,952 BEFORE THE DELAWARE PUBLIC SERVICE COMMISSION
Application of Delmarva Power & Lil!ht Company For Approval of an Increased in Gas Base Rates
DPSC DOCKET NO. 06-
DIRECT TESTIMONY
OF
DR. ROGER A. MORIN
ON BEHALF OF
DELMARVA POWER & LIGHT COMPANY
August 28, 2006 DELMARVA POWER & LIGHT COMPANY
2 DIRECT TESTIMONY OF DR. ROGER A MORIN
3 TABLE OF CONTENTS
4 Page
5 i. REGULATORY FRAEWORK AN RATE OF RETUR ...... 6
6 II. COST OF EQUITY CAPITAL ESTIMATES ...... 13
1 A. CAPM Estimates...... 26
8 B. Historical Risk Premium Estimate...... 39
9 C. Allowed Risk Premium...... 42
10 D. DCF estimates...... 48
11 III. SUMMARY AND RECOMMENDATION ...... 61
12 IV. COMPOSITE COST OF CAPITAL...... 70 Delmarva Power & Light Direct Testimony of Roger A. Morin
1 DIRECT TESTIMONY 2 OF 3 DR. ROGER A. MORIN 4 ON BEHALF OF 5 DELMARVA POWER & LIGHT COMPANY 6 7 8 1. Q: Please state your name. address. and occupation.
9 A: My name is Dr. Roger A. Morin. My business address is Georgia State
10 University, Robinson College of Business, University Plaza, Atlanta, Georgia, 30303. I
11 am Professor of Finance at the College of Business, Georgia State University and
12 Professor of Finance for Regulated Industry at the Center for the Study of Regulated
13 Industry at Georgia State University. I am also a principal in Utility Research
International, an enterprise engaged in regulatory finance and economics consulting to 15 business and governent.
16 2. Q: Please describe your educational backl!round.
17 A: I hold a Bachelor of Engineering degree and an MBA in Finance from McGill
18 University, Montreal, Canada. I received my Ph.D. in Finance and Econometrics at the
19 Wharton School of Finance, University of Pennsylvania.
20 3. Q: Please summarize your academic and business career.
21 A: I have taught at the Wharton School of Finance, University of Pennsylvania,
22 Amos Tuck School of Business at Darmouth College, Drexel University, University of
23 Montreal, McGill University, and Georgia State University. I was a faculty member of
24 Advanced Management Research International, and I am currently a faculty member of
25 The Management Exchange Inc. and Exnet, where I continue to conduct frequent national
26 executive-level education seminars throughout the United States and Canada. In the last
2 Delmarva Power & Light Direct Testimony of Roger A. Morin
twenty-five years, I have conducted numerous national seminars on "Utility Finance,"
2 "Utility Cost of Capital," "Alternative Regulatory Frameworks," and on "Utility Capital
3 Allocation," which I have developed on behalf of The Management Exchange Inc. in
4 conjunction with Public Utilities Reports, Inc.
5 I have authored or co-authored several books, monographs, and articles in
6 academic scientific journals on the subject of finance. They have appeared in a variety of
7 journals, including The Journal of Finance, The Journal of Business Administration,
8 International Management Review, and Public Utility Fortnightly. I published a widely-
9 used treatise on regulatory finance, Utilities' Cost of Capital, Public Utilities Reports,
10 Inc., Arlington, Va. 1984. My second book on regulatory matters, Regulatorv Finance, is
11 a voluminous treatise on the application of finance to regulated utilities and was released
2 by the same publisher in late 1994. A revised and expanded edition, The New
13 Regulatorv Finance, has just been published. I have engaged in extensive consulting
14 activities on behalf of numerous corporations, legal firms, and regulatory bodies in
15 matters of financial management and corporate litigation. Schedule RA-I describes my
16 professional credentials in more detaiL.
17 4. Q: Have you previously testified on cost of capital before rel!ulatory bodies?
18 A: Yes, I have been a cost of capital witness before nearly fifty (SO) regulatory
19 bodies in North America, the Federal Energy Regulatory Commission and the Federal
20 Communications Commission. I have also testified before the following state regulatory
21 bodies:
3 Delmarva Power & Light Direct Testimony of Roger A. Morin
1
Alabama Hawaii Nevada Oregon Alaska Ilinois New Brunswick Pennsylvania Alberta Indiana New Hampshire Quebec Arizona Iowa New Jersey South Carolina Arkansas Kentucky New York South Dakota British Columbia Louisiana Newfoundland Tennessee California Manitoba North Carolina Texas Colorado Michigan North Dakota Utah Delaware Minnesota Nova Scotia Vermont District of Columbia Mississippi Ohio Washington Florida Missouri Oklahoma West Virginia Georgia Montana Ontario 2
3 The details of my participation in regulatory proceedings are provided in Schedule
4 RA -1.
5 5. Q. What is the purpose of your testimony in this proceedinl!?
6 A: The purpose of my testimony in this proceeding is to present an independent
7 appraisal of the fair and reasonable rate of return on Delmarva Power & Light
8 Company's ("DP&L" or the "Company") natural gas delivery operations in the State of
9 Delaware. Based upon this appraisal, I have formed my professional judgment as to a
10 return on such capital that would: (1) be fair to the customers, (2) allow the Company to
11 attract capital on reasonable terms, (3) maintain the Company's financial integrity, and
12 (4) be comparable to returns offered on comparable risk investments. I will testify in
13 this proceeding as to the basis for that opinion
14 This testimony and accompanying schedules were prepared by me or under my
15 direct supervision and control. The source documents for my testimony are Company
16 records, public documents, and my personal knowledge and experience.
17 6. Q: Please briefly identify the schedules and appendix accompanyinl! your testimony.
4 Delmarva Power & Light Direct Testimony of Roger A. Morin
A: I have attached to my testimony Schedules RA-I through RA-I 0 and
2 Appendices A and B. These Schedules and Appendices relate directly to points in my
3 testimony, and are described in further detail in connection with the discussion of those
4 points in my testimony. I also sponsor Minimum Filing Requirement Schedules 4A - 4H.
5 7. Q: Please summarize your findinl!s and recommendation.
6 A: I recommend the adoption of an overall return on investment of 8.08% and a rate
7 of return on common equity of 11.0% on DP&L's natural gas delivery operations, assuming
8 that the Bil Stabilization Adjustment ("BSA") is adopted. If the BSA adopted is not
9 approved, I recommend the adoption of an overall return on investment of 8.20% and a rate
10 ofretum on common equity of 11.25% on DP&L's natural gas delivery operations. My
11 recommendation is derived from studies that I performed using the Capital Asset Pricing
2 Model ("CAPM"), Risk Premium, and Discounted Cash Flow ("DCF") methodologies. I
13 performed two CAPM analyses, one using the plain vanila CAPM and another using an
14 empirical approximation ofthe CAPM ("ECAPM"). I performed three risk premium
15 analyses: (1) a historical risk premium analysis on the natural gas utility industry, (2) a
16 historical risk premium analysis on the electric utility industry as a proxy for the Company's
17 natural gas delivery business, and (3) a study of the risk premiums allowed in the natural gas
18 utility industry. I also performed DCF analyses on two surrogates for the Company's natural
19 gas distribution business. They are: a group of natural gas distribution utilities and a group
20 of investment-grade combination gas & electric utilities.
21 My recommended rate of return reflects the application of my professional
22 judgment to the indicated returns from my CAPM, Risk Premium, and DCF analyses, and to
123 the Company's current risk environment which I estimate to be in excess of the industry
5 Delmarva Power & Light Direct Testimony of Roger A. Morin
average.
2 8. Q: Dr. Morin. please describe how your testimony is or2anized.
3 A: The remainder of my testimony is divided into four (4) sections:
4 i. Regulatory Framework and Rate of Return
5 II. Cost of Equity Estimates
6 III. Summary and Cost of Equity Recommendation
7 iv. Composite Cost of Capital
8 The first section discusses the rudiments of rate of return regulation and the basic
9 notions underlying rate of return. The second section contains the application of CAPM,
10 Risk Premium, and DCF tests. In the third section, the results from the various
11 approaches used in determining a fair return are summarized. In the fourth section,
2 DP&L's capital structure, the costs of debt and the cost of equity are combined to arrve
13 at DP&L's composite cost of capitaL.
14
15 i. REGULATORY FRAMEWORK AND RATE OF RETURN
16 9. Q: What economic and financial concepts have l!uided your assessment of DP&L'S cost
17 of common equity?
18 A: Two fundamental economic principles underlie the appraisal of the Company's
19 cost of equity, one relating to the supply side of capital markets, the other to the demand
20 side. According to the first principle, a rational investor is maximizing the performance
21 of his portfolio only if he expects the returns earned on investments of comparable risk to
22 be the same. If not, the rational investor will switch out of those investments yielding i23 lower returns at a given risk level in favor of those investment activities offering higher
6 Delmarva Power & Light Direct Testimony of Roger A. Morin
returns for the same degree of risk. This principle implies that a company will be unable
2 to attract the capital funds it needs to meet its service demands and to maintain financial
3 integrity unless it can offer returns to capital suppliers that are comparable to those
4 achieved on competing investments of similar risk. On the demand side, the second
5 principle asserts that a company will continue to invest in real physical assets if the return
6 on these investments exceeds or equals the company's cost of capital. This concept
7 suggests that a regulatory commission should set rates at a level suffcient to create
8 equality between the return on physical asset investments and the company's cost of 9 capitaL.
10 10. Q: How does DP&L'S cost of capital relate to that of its ultimate parent company.
11 Pepco Holdinl!s. Inc.?
2 A: I am treating DP&L's natural gas distribution operations as a separate stand-alone
13 entity, distinct from the parent company Conectiv and its holding company, Pepco
14 Holdings, Inc. ("PHI") because it is the cost of capital for DP&L's gas business that we
15 are attempting to measure and not the cost of capital for Conectiv or PHI's consolidated
16 activities. Financial theory clearly establishes that the true cost of capital depends on the
17 use to which the capital is put, in this case DP&L's natural gas delivery operations in the
18 State of Delaware. The specific source of funding an investment and the cost of funds to
19 the investor are irrelevant considerations.
20 For example, if an individual investor borrows money at the bank at an after-tax
21 cost of 8% and invests the funds in a speculative oil extraction venture, the required
22 return on the investment is not the 8% cost but, rather, the return foregone in speculative
:'23 projects of similar risk, say 20%. Similarly, the required return on DP&L is the return
7 Delmarva Power & Light Direct Testimony of Roger A. Morin
foregone in comparable risk natural gas delivery operations, and is unrelated to the
2 parent's cost of capitaL. The cost of capital is governed by the risk to which the capital is
3 exposed and not by the source of funds. The identity of the shareholders has no bearing
4 on the cost of equity, be it either individual investors or a parent holding company.
5 Just as individual investors require different returns from different assets II
6 managing their personal affairs, corporations behave in the same manner. A parent
7 company normally invests money in many operating companies of varying sizes and
8 varying risks. These operating subsidiaries pay different rates for the use of investor
9 capital, such as for long-term debt capital, because investors recognize the differences in
10 capital structure, risk, and prospects between subsidiaries. Thus, the cost of investing 11 funds in an operating utility company such as DP&L is the return foregone on
2 investments of similar risk and is unrelated to the investor's identity. 13 I1.Q: Under traditional cost of service rel!ulation please explain how a rel!ulated 14 company's rates should be set.
15 A: Under the traditional regulatory process, a regulated company's rates should be set
16 so that the company recovers its costs, including taxes and depreciation, plus a fair and
17 reasonable return on its invested capitaL. The allowed rate of return must necessarily
18 reflect the cost of the funds obtained, that is, investors' return requirements. In
19 determining a company's rate of return, the starting point is investors' return requirements
20 in financial markets. A rate of return can then be set at a level sufficient to enable the
21 company to earn a return commensurate with the cost of those funds.
22 Funds can be obtained in two general forms, debt capital and equity capitaL. The
cost of debt funds can be easily ascertained from an examination of the contractual
8 Delmarva Power & Light Direct Testimony of Roger A. Morin
interest payments. The cost of common equity funds, that is, investors' required rate of
2 return, is more diffcult to estimate. It is the purpose of the next section of my testimony
3 to estimate DP&L's cost of common equity capitaL.
4 The estimated return on equity capital will be combined with the embedded costs
5 of debt as supplied to me by the Company together with its capital structure, in order to
6 arrve at the Company's overall cost of capital. Since the estimation of the cost of
7 common equity is by far the most complex of these issues, most of the content of this
8 testimony addresses that issue.
9 12.Q: Dr. Morin. what must be considered in estimatini: a fair return on common equity?
10 A: The legal requirement is that the allowable return on common equity should be
11 commensurate with returns on investments in other firms having corresponding risks.
2 The allowed return should be suffcient to assure confidence in the financial integrty of
13 the firm, in order to maintain creditworthiness, and ability to attract capital on reasonable
14 terms. The attraction of capital standard focuses on investors' return requirements that
15 are generally determined using market value methods, such as the Risk Premium, CAPM,
16 or DCF methods. These market value tests define fair return as the return that investors
17 anticipate when they purchase equity shares of comparable risk in the financial
18 marketplace. This return is a market rate of return, defined in terms of anticipated
19 dividends and capital gains as determined by expected changes in stock prices, and
20 reflects the opportunity cost of capitaL. The economic basis for market value tests is that
21 new capital will be attracted to a firm only if the return expected by the suppliers of funds
22 is commensurate with that available from alternative investments of comparable risk.
13.Q: What fundamental principles underlie the determination of a fair and reasonable
9 Delmara Power & Light Direct Testimony of Roger A. Morin
rate of return on common equity?
2 A: The heart of utility regulation is the setting of just and reasonable rates by way of a
3 fair and reasonable return. There are two landmark United States Supreme Court cases
4 that define the legal principles underlying the regulation of a public utility's rate of return
5 and provide the foundations for the notion of a fair return:
6 1. Bluefield Water Works & Improvement Co. v. Public Service Commission of 7 West Virginia, 262 U.S. 679 (1923). 8 9 2. Federal Power Commission v. Hope Natural Gas Company, 320 U.S. 391 10 (1944). 11 12 The Bluefield case set the standard against which just and reasonable rates of return
13 are measured:
14 "A public utilty is entitled to such rates as wil permit it to earn a return on the 15 value of the property which it employs for the convenience of the public equal to that 6 generallv being made at the same time and in the same zeneral part of the country on 17 investments in other business undertakinzs which are attended bv corresponding risks 18 and uncertainties ... The return should be reasonable. suffcient to assure confidence in 19 the financial soundness of the utility, and should be adequate, under effcient and 20 economical management, to maintain and support its credit and enable it to raise money 21 necessary for the proper discharge of its public duties." (Emphasis added) 22 23 The Hope case expanded on the guidelines to be used to assess the reasonableness
24 of the allowed return. The Court reemphasized its statements in the Bluefield case and
25 recognized that revenues must cover "capital costs." The Court stated:
26 "From the investor or company point of view it is important that there be enough 27 revenue not only for operating expenses but also for the capital costs of the business. 28 These include service on the debt and dividends on the stock ... By that standard the 29 return to the equitv owner should be commensurate with returns on investments in other 30 enterprises having corresponding risks. That return, moreover, should be sufficient to 31 assure confidence in the financial integrity of the enterprise, so as to maintain its credit 32 and attract capital." (Emphasis added) 33
\34 The United States Supreme Court reiterated the criteria set forth in Hope in Federal
10 Delmarva Power & Light Direct Testimony of Roger A. Morin
1 Power Commission v. Memphis Light, Gas & Water Division, 411 U.S. 458 (1973), in
2 Permian Basin Rate Cases, 390 U.S. 747 (1968), and most recently in Duquesne Light
3 Co. vs. Barasch, 488 U.S. 299 (1989). In the Permian cases, the Supreme Court stressed
4 that a regulatory agency's rate of return order should:
5 "...reasonably be expected to maintain financial integrity, attract necessary capital, and 6 fairly compensate investors for the risks they have assumed... " 7 8 Therefore, the "end result" of the Commission's decision should be to allow DP&L
9 the opportunity to earn a return on equity that is: (1) commensurate with returns on
10 investments in other firms having corresponding risks, (2) sufficient to assure confidence
11 in the company's financial integrty, and (3) sufficient to maintain the company's
12 creditworthiness and ability to attract capital on reasonable terms.
3 14.Q: How is the fair rate of return determined?
14 A: The aggregate return required by investors is called the "cost of capitaL." The cost
15 of capital is the opportunity cost, expressed in percentage terms, of the total pool of
16 capital employed by the utility. It is the composite weighted cost of the various classes of
17 capital (bonds, preferred stock, common stock) used by the utility, with the weights
18 reflecting the proportions of the total capital that each class of capital represents. The
19 fair return in dollars is obtained by multiplying the rate of return set by the regulator by
20 the utility's "rate base." The rate base is essentially the net book value of the utility's
21 plant and other assets used to provide utility service in a particular jurisdiction.
22 While utilities like DP&L enjoy varying degrees of monopoly in the sale of public
23 utility services, they must compete with everyone else in the free, open market for the
24 input factors of production, whether they be labor, materials, machines, or capitaL. The
prices of these inputs are set in the competitive marketplace by supply and demand, and it
11 Delmarva Power & Light Direct Testimony of Roger A. Morin
is these input prices that are incorporated in the cost of service computation. This item is
2 just as true for capital as for any other factor of production. Since utilities and other
3 investor-owned businesses must go to the open capital market and sell their securities in
4 competition with every other issuer, there is obviously a market price to pay for the
5 capital they require, for example, the interest on debt capital, or the expected return on
6 common and/or preferred equity.
7 15.Q: How does the concept of a fair return relate to the concept of opportunity cost?
8 A: The concept of a fair return is intimately related to the economic concept of
9 "opportunity cost." When investors supply funds to a utility by buying its stocks or
10 bonds, they are not only postponing consumption, giving up the alternative of spending
11 their dollars in some other way, they also are exposing their funds to risk and forgoing
12 returns from investing their money in alternative comparable-risk investments. The
13 compensation that they require is the price of capitaL. If there are differences in the risk
14 of the investments, competition among firms for a limited supply of capital will bring
15 different prices. These differences in risk are translated by the capital markets into price
16 differences in much the same way that differences in the characteristics of commodities
17 are reflected in different prices.
18 The important point is that the prices of debt capital and equity capital are set by
19 supply and demand, and both are influenced by the relationship between the risk and
20 return expected for the respective securities and the risks expected from the overall menu
21 of available securities.
12 Delmarva Power & Light
Direct Testimony of Roger A. Morin
16.Q: How does the company obtain its capital and how is its overall cost of capital
2 determined?
3 A: The funds employed by the Company are obtained in two general forms, debt
4 capital and equity capitaL. The latter consists of preferred equity capital and common
5 equity capitaL. The cost of debt funds and preferred stock funds can be ascertained easily
6 from an examination of the contractual terms for the interest payments and preferred
7 dividends. The cost of common equity funds, that is, equity investors' required rate of
8 return, is more diffcult to estimate because the dividend payments received from
9 common stock are not contractual or guaranteed in nature. They are uneven and risky,
10 unlike interest payments. Once a cost of common equity estimate has been developed, it
11 can then easily be combined with the embedded cost of debt and preferred stock, based
12 on the utility's capital structure, in order to arrve at the overall cost of capitaL.
13 17:Q: What is the market required rate of return on equity capital?
14 A: The market required rate of return on common equity, or cost of equity, is the
15 return demanded by the equity investor. Investors establish the price for equity capital
16 through their buying and selling decisions. Investors set return requirements according to
17 their perception of the risks inherent in the investment, recognizing the opportunity cost
18 of forgone investments, and the returns available from other investments of comparable
19 risk.
20 II. COST OF EQUITY ESTIMATES 21 18.Q: Dr. Morin. how did yOU estimate the fair rate of return on common equity for 22 DP&L?
\23 A: I employed three methodologies: (1) the CAPM, (2) the Risk Premium, and (3)
13 Delmarva Power & Light Direct Testimony of Roger A. Morin
the DCF. All three items are market-based methodologies and are designed to estimate
2 the return required by investors on the common equity capital committed to DP&L.
3 19.Q: Why did YOU use more than one approach for estimatinl! the cost of equity?
4 A: No one individual method provides the necessary level of precision for
5 determining a fair return, but each method provides useful evidence to facilitate the
6 exercise of an informed judgment. Reliance on any single method or preset formula is
7 inappropriate when dealing with investor expectations because of possible measurement
8 difficulties and vagaries in individual companies' market data. Examples of such
9 vagaries include dividend suspension, insuffcient or unrepresentative historical data due
10 to a recent merger, impending merger or acquisition, and a new corporate identity due to
11 restructuring activities. The advantage of using several different approaches is that the
2 results of each one can be used to check the others.
13 As a general proposition, it is extremely dangerous to rely on only one generic
14 methodology to estimate equity costs. The diffculty is compounded when only one
15 variant of that methodology is employed. It is compounded even further when that one
16 methodology is applied to a single company. Hence, several methodologies applied to
17 several comparable risk companies should be employed to estimate the cost of common
18 equity.
19 20.Q: Dr. Morin. are yOU aware that some rel!ulatory commissions and some analysts have
20 placed principal reliance on DCF-based analyses to determine the cost of equity for 21 public utilties?
22 A: Yes, I am.
1,3 21.Q: Do you al!ree with this approach?
14 Delmarva Power & Light Direct Testimony of Roger A. Morin
1 A: While I agree that it is certainly appropriate to use the DCF methodology to
2 estimate the cost of equity, and I myself do rely on such evidence, there is no proof that
3 the DCF produces a more accurate estimate of the cost of equity than other
4 methodologies. As I have stated, there are three broad generic methodologies available
5 to measure the cost of equity: DCF, Risk Premium, and CAPM. All three of these
6 methodologies are accepted and used by the financial community and firmly supported in
7 the financial literature.
8 When measuring the cost of common equity, which essentially deals with the
9 measurement of investor expectations, no one single methodology provides a foolproof
10 panacea. Each methodology requires the exercise of considerable judgment on the
11 reasonableness of the assumptions underlying the methodology and on the reasonableness
2 of the proxies used to validate the theory and apply the methodology. The failure of the
13 traditional infinite growth DCF model to account for changes in relative market
14 valuation, and the practical diffculties of specifying the expected growth component, are
15 vivid examples of the potential shortcomings of the DCF modeL. It follows that more
16 than one methodology should be employed in arrving at a judgment on the cost of equity
17 and that all of these methodologies should be applied to multiple groups of comparable
18 risk companies.
19 There is no single model that conclusively determines or estimates the expected
20 return for an individual firm. Each methodology has its own way of examining investor
21 behavior, its own premises, and its own set of simplifications of reality. Investors do not
22 necessarily subscribe to anyone method, nor does the stock price reflect the application
123 of anyone single method by the price-setting investor. Absent any hard evidence as to
15 Delmarva Power & Light Direct Testimony of Roger A. Morin
which method outperforms the other, all relevant evidence should be used, without
2 discounting the value of any results, in order to minimize judgmental error, measurement
3 error, and conceptual infirmities. I submit that a regulatory body should rely on the
4 results of a variety of methods applied to a variety of comparable groups. There is no
5 guarantee that a single DCF result is necessarily the ideal predictor of the stock price and
6 of the cost of equity reflected in that price, just as there is no guarantee that a single
7 CAPM or Risk Premium result constitutes the perfect explanation of a stock's price or the
8 cost of equity.
9 22.Q: Does the tin3ncial literature support the use of more than a sinl!le method?
10 A: Yes. Authoritative financial literature strongly supports the use of multiple
11 methods. For example, Professor Eugene F. Brigham, a widely respected scholar and
2 finance academician, asserts:
13 In practical work, it is often best to use all three methods - CAPM, bond yield plus risk 14 premium, and DCF - and then apply judgment when the methods produce diferent 15 results. People experienced in estimating capital costs recognize that both careful 16 analysis and some very fine judgments are required. It would be nice to pretend that 17 these judgments are unnecessary and to specif an easy, precise way of determining the 18 exact cost of equity capital. Unfortunately, this is not possible. 1
In a subsequent edition of his best-selling corporate finance textbook, Dr.
Brigham discusses the various methods used in estimating the cost of common equity
capital, and states:
19 However, three methods can be used: (1) the Capital Asset Pricing Model (CAPM), (2) 20 the discounted cash flow (DCF) model, and (3) the bond-yield-plus-risk-premium 21 approach. These methods should not be regarded as mutually exclusive - no one 22 dominates the others, and all are subject to error when used in practice. Therefore, when 23 faced with the task of estimating a company' cost of equity, we generally use all three
1 E. F. Brigham and L. C. Gapenski, Financial Management Theory and Practice, p. 256 (4th ed., Dryden Press, Chicago, 1985)
16 Delmarva Power & Light Direct Testimony of Roger A. Morin
2 1 methods... 2 3 Another prominent finance scholar, Professor Stewart Myers, in his best selling
4 corporate finance textbook, points out:
5 The constant growth rDCFj formula and the capital asset pricing model are two diferent 6 ways of getting a handle on the same problem. 3 7 8 In an earlier article, Professor Myers explains:
9 Use more than one model when you can. Because estimating the opportunity cost of 10 capital is difcult, only a fool throws away useful information. That means you should 11 not use anyone model or measure mechanically and exclusively. Beta is helpful as one 12 tool in a kit, to be used in parallel with DCF models or other techniques for interpreting 4 13 capital market data. 14 15 23.Q: Does the broad usal!e of the DCF methodolol!y in past re2ulatory proceedinl!s
16 indicate that it is superior to other methods?
17 A: No, it does not. Uncritical acceptance of the standard DCF equation vests the
18 model with a degree of reliability that is simply not justified. One of the leading experts
19 on regulation, Dr. Charles F. Phillips discusses the dangers of relying solely on the DCF
20 model:
21 "rUj se of the DCF model for regulatory purposes involves both theoretical and practical 22 difculties. The theoretical issues include the assumption of a constant retention ratio 23 (i. e. a fixed payout ratio) and the assumption that dividends wil continue to grow at a 24 rate 'g' in perpetuity. Neither of these assumptions has any validity, particularly in 25 recent years. Further, the investors' capitalization rate and the cost of equity capital to a 26 utilty for application to book value (i.e. an original cost rate base) are identical only 27 when market price is equal to book value. Indeed, DCF advocates assume that if the 28 market price of a utility's common stock exceeds its book value, the allowable rate of 29 return on common equity is too high and should be lowered; and vice versa. Many 30 question the assumption that market price should equal book value, believing that the 31 earnings of utilities should be suffciently high to achieve market-to-book ratios which 32 are consistent with those prevailng for stocks of unregulated companies. "
2 E. F. Brigham and L. C. Gapenski, Financial Management Theory and Practice, p. 348 (8th ed., Dryden Press, Chicago, 2005) 3 R. A. Brealey and S. è. Myers, Principles of Co roo rate Finance, p. 182 (3fd ed., McGraw Hill, New York, 1988) 4 S. C. Myers, "On the Use of Modem Portfolio Theory in Public Utility Rate Cases: Comment," Financial Management, p. 67 (Autumn 1978)
17 Delmarva Power & Light Direct Testimony of Roger A. Morin
1 ...!Tjhere remains the circularity problem: Since regulation establishes a level of 2 authorized earnings which, in turn, implicitly influences dividends per share, estimation 3 of the growth rate from such data is an inherently circular process. For all of these 4 reasons, the DCF model suggests a degree of precision which is in fact not present and 5 leaves wide room for controversy about the level of k ! cost of equity j. 5
6 Dr. Charles F. Phillips also discusses the dangers of relying solely on the CAPM
7 model because of the stringency of certain of its underlying assumptions, as is the case
8 for any model in the social sciences.
9 Sole reliance on anyone model, whether it is DCF, CAPM, or Risk Premium,
10 simply ignores the capital market evidence and investors' use of the other theoretical
11 frameworks. The DCF model is only one of many tools to be employed in conjunction
12 with other methods to estimate the cost of equity. It is not a superior methodology that
13 should supplant other financial theory and market evidence. The same is true of the
14 CAPM.
15 24.Q: Does the DCF model understate the cost of equity?
16 A: Yes, it does. Application of the DCF model produces estimates of common
17 equity cost that are consistent with investors' expected return only when stock price and
18 book value are reasonably similar, that is, when the Market-to-Book (M/B) ratio is close
19 to unity. As shown below, application of the standard DCF model to utility stocks
20 understates the investor's expected return when the M/B ratio of a given stock exceeds
21 unity. This item is particularly relevant in the current capital market environment where
22 utility stocks are trading at M/B ratios well above unity and have been for two decades.
5 C. F. Philips, The Regulation of Public Utilities Theory and Practice (Public Utilities Reports, Inc., 1988) pp. 376-77 (Footnotes omitted)
18 Delmarva Power & Light Direct Testimony of Roger A. Morin
1 The converse is also true, that is, the DCF model overstates the investor's return when the
2 stock's M/B ratio is less than unity. The reason for the distortion is that the DCF market
3 return is applied to a book value rate base by the regulator, that is, a utility's earnings are
4 limited to earnings on a book value rate base.
5 25.Q: Can YOU ilustrate the effect of the market-to-book ratio on the DCF model by
6 means of a simple example?
7 A: Yes. The simple numerical illustration shown in the table below demonstrates the
8 result of applying a market value cost rate to book value rate base under three different
9 M/B scenarios. The three columns correspond to three M/B situations: the stock trades
10 below, equal to, and above book value, respectively. The last situation (shaded portion of
11 the table) is noteworthy and representative of the current capital market environment.
2 The DCF cost rate of 10%, made up of a 5% dividend yield and a 5% growth rate, is
13 applied to the book value rate base of $50 to produce $5.00 of earnings. Of the $5.00 of
14 earnings, the full $5.00 are required for dividends to produce a dividend yield of 5% on a
15 stock price of $100.00, and no dollars are available for growth. The investor's return is
16 therefore only 5% versus his required return of 10%. A DCF cost rate of 10%, which
17 implies $10.00 of earnings, translates to only $5.00 of earnings on book value, a 5%
18 return.
19 The situation is reversed in the first column when the stock trades below book
20 value. The $5.00 of earnings is more than enough to satisfy the investor's dividend
21 requirements of $1.25, leaving $3.75 for growth, for a total return of 20%. This item
22 occurs when the DCF cost rate is applied to a book value rate base well above the market
123 pnce.
19 Delmara Power & Light Direct Testimony of Roger A. Morin
Therefore, the DCF cost rate understates the investor's required return when stock
2 prices are well above book, as is the case presently.
3 EFFECT OF MARKET-TO-BOOK RATIO ON MARKET RETURN 4 5 Situation 1 Situation 2 Situation 3 1 Initial purchase price $25.00 $50.00 $ 1 00.00 2 Initial book value $50.00 $50.00 $50.00 3 Initial M/B 0.50 1.00 2.00 4 DCF Return 10% = 5% + 5% 10.00% 10.00% 10.00% 5 Dollar Return $5.00 $5.00 $5.00 6 Dollar Dividends 5% Yield $1.25 $2.50 $5.00 7 Dollar Growth 5% Growth $3.75 $2.50 $0.00 8 Market Return 20.00% 10.00% 5.00%
6 26.Q. Does the annual version of the DCF model understate the cost of equity?
7 A: Yes, it does. Another reason why the DCF methodology understates the cost of
8 equity is that the annual DCF model usually employed in regulatory settings assumes that
9 dividend payments are made annually at the end of the year, while most utilities in fact
10 pay dividends on a quarterly basis. Failure to recognize the quarterly nature of dividend
11 payments understates the cost of equity capital by about 30 basis points. By analogy, a
12 bank rate on deposits which does not take into consideration the timing of the interest
13 payments understates the true yield of your investment if you receive the interest
14 payments more than once a year. Since the stock price employed in the DCF model
15 already reflects the quarterly stream of dividends to be received, consistency therefore
16 requires explicit recognition of the quarterly nature of dividend payments. One only has
17 to think of what would happen to a company's stock price if the company was to
18 suddenly announce that it is, from now on, paying dividends once a year at the end of the
20 Delmarva Power & Light Direct Testimony of Roger A. Morin
1 year instead of four times a year each quarter. Clearly, the stock price would decline by
2 an amount reflecting the lost time value of money.
3 27.Q: Do rel!ulators rely primarily on the DCF model?
4 A: No, I believe that they do not. A majority of regulatory commissions do not, as a
5 matter of practice, rely solely on the DCF model results in setting the allowed rate of
6 return on common equity. According to the results posted in a survey conducted by the
7 National Association of Regulatory Utility Commissioners ("NARUC"), regulators
8 utilize a variety of methods and rely on all the evidence submitted.
9 28.Q: Do rel!ulators share your reservations on the reliabilty of the DCF model?
10 A: Yes, I believe they do. While a majority of regulatory commissions do not, as a
11 matter of practice, rely solely on the DCF model results in setting the allowed rate of
2 return on common equity, some regulatory commissions have explicitly recognized the
13 need to avoid exclusive reliance upon the DCF model and have acknowledged the need to
14 adjust the DCF result when M/B ratios exceed one6.
15 My sentiments on the DCF model were echoed in a decision by the Indiana Utility
16 Regulatory Commission (IUC). The IUC recognized its concerns with the DCF
17 model and that the model understates the cost of equity. In Cause No. 39871 Final Order,
18 the IUC states on page 24:
19 "....the DCF model, heavily relied upon by the Public, understates the cost of 20 common equity. The Commission has recognized this fact before. In Indiana 21 Mich. Power Co. (IURC 8/24/90), Cause No. 38728, 116 PUR4th 1, 17-18, we 22 found:
6 See the Indiana Utility Regulatory Commssion decision in Indiana Mich. Power Co. (IURC 8/24/90), Cause No. 38728, 116 PUR4th 1, 17-18. See also the Iowa Utilities Board decision in U.S. West Communications, Inc. Docket No. RPR-93-9, 152 PUR4th 446,459 (Iowa 1994). See also the Hawaii Public Utilities Commssion decision in Hawaiian Electric Company, Inc., 134 PUR4th 418, 479 (1992). More recently, see the Pennsylvania Public Utility Commssion decision in Pennsylvania-American Water Company, Docket R-00016339, Slip Opinion at htt://www.puc.state.pa.us/PcDocs/304982.doc.
21 Delmarva Power & Light Direct Testimony of Roger A. Morin
1 2 The unadjusted DCF result is almost always well below what any informed 3 financial analyst would regard as defensible, and therefore requires an upward 4 adjustment based largely on the expert witness's judgment. " 5 6 The Commission also expressed its concern with a witness relying solely on one
7 methodology:
8 "...... the Commission has had concerns in our past orders with a witness relying 9 solely on one methodology in reaching an opinion on a proper return on equity 10 figure." (page 25)
11 Even more convincing is the fact that MIB ratios have exceeded unity for over
12 two decades; this fact is clear evidence that regulators have in fact not relied on the DCF
13 model exclusively. Had regulators relied exclusively on the DCF model, utility stocks
14 would have traded at or near book value. Regulators have "corrected" for this M/B
5 problem by considering alternative methods for estimating capital cost.
16 29.Q: Is the usal!e of the DCF model prevalent in corporate practices?
17 A: No, not really. The CAPM continues to be widely used by analysts, investors, and
18 corporations. Bruner, Eades, Harrs, and Higgins (1998) in a comprehensive survey7 of
19 current practices for estimating the cost of capital found that 81 % of companies used the
20 CAPM to estimate the cost of equity, 4% used a modified CAPM, and 15% were uncertain.
21 In another comprehensive survey conducted by Graham and Harvey (2001), the managers
22 sureyed reported using more than one methodology to estimate the cost of equity, and 73%
23 used the CAPM.8 Since its introduction by Professor William F. Sharpe in 1964, the
7Bruer, R. F., Eades, K. M., Harris, R. S., and Higgins, R. C., "Best Practices in Estimating the Cost of Capital: Survey and Synthesis," Financial Practice and Education, Vol. 8, Number i, Spring/Summer 1998, page 18. 8Graham, 1. R. and Harvey, C. R., "The Theory and Practice of Corporate Finance: Evidence from the
Field," Journal of Financial Economics, Vol. 61, 2001, pp. 187-243.
22 Delmarva Power & Light Direct Testimony of Roger A. Morin
1 CAPM has gained immense popularity as the practitioner's method of choice when
2 estimating cost of capital under conditions of risk. 9 The intuitive simplicity of its basic
3 concept (that investors must get compensated for the risk they assume), and the relatively
4 easy application of the CAPM are the main reasons behind its popularity.
5 30.Q: Do the assumptions underlyinl! the DCF model require that the model be treated
6 with caution?
7 A: Yes, particularly in today's rapidly changing natural gas utility industry. Even
8 ignoring the fundamental thesis that several methods and/or variants of such methods
9 should be used in measuring equity costs, the DCF methodology, as those familiar with
10 the industry and the accepted norms for estimating the cost of equity are aware, is
11 problematic for use in estimating cost of equity at this time.
2 Several fundamental structural changes have transformed the energy utility
13 industry since the standard DCF model and its assumptions were developed. For
14 example, deregulation, accounting rule changes, changes in customer attitudes regarding
15 utility services, the evolution of alternative energy sources, highly volatile fuel prices,
16 and mergers-acquisitions have all influenced stock prices in ways that have deviated
17 substantially from the assumptions of the DCF modeL. These changes suggest that some
18 of the fundamental assumptions underlying the standard DCF model, particularly that of
19 constant growth and constant relative market valuation, for example price/earnings (P/E)
20 ratios and market-to-book (M/B) ratios, are problematic at this point in time for utility
21 stocks, and that, therefore, alternate methodologies to estimate the cost of common equity
22 should be accorded at least as much weight as the DCF method.
9 See practitioner sureys by Graham & Harvey (200 1) and Bruner, et. aL. (1988)
23 Delmarva Power & Light Direct Testimony of Roger A. Morin
31.Q: Is the constant relative market valuation assumption inherent in the DCF model
2 always reasonable?
3 A: No, not always. Caution must be exercised when implementing the standard DCF
4 model in a mechanistic fashion, for it may fail to recognize changes in relative market
5 valuations over time. The traditional DCF model is not equipped to deal with surges in
6 M/B and price-earnings PIE ratios. The standard DCF model assumes a constant market
7 valuation multiple, that is, a constant PIE ratio and a constant M/B ratio. Stated another
8 way, the model assumes that investors expect the ratio of market price to dividends (or
9 earnings) in any given year to be the same as the current ratio of market price to dividend
10 (or earnings), and that the stock price will grow at the same rate as the book value. This
11 item is a necessary result of the infinite growth assumption. This assumption is
2 unrealistic under current conditions as the graph below clearly demonstrates. The DCF
13 model is not equipped to deal with sudden surges in M/B and PIE ratios, as was
14 experienced by utility stocks in recent years.
Natural Gas Utlity Industry PIE Ratios 1990-2006 20
19
18 :8 co 17 0: UJ 16 a: 15
14
13 1990 1992 1994 1996 1998 2000 2002 2004 2006 1991 1993 1005 1007 1009 200 1 ~03 2005 15
16
24 Delmarva Power & Light Direct Testimony of Roger A. Morin
32.Q: What is your recommendation l!iven such market conditions?
2 A: In short, caution and judgment are required in interpreting the results of the
3 standard DCF model because of (1) the effect of changes in risk and growth on natural
4 gas utility utilities, (2) the fragile applicability of the DCF model to natural gas utility
5 stocks in the current capital market environment, and (3) the practical difficulties
6 associated with the growth component of the standard DCF modeL. Hence, there is a
7 clear need to go beyond the standard DCF results and take into account the results
8 produced by alternate methodologies in arriving at a common equity recommendation.
9 33. Q: Do the assumptions underlyinl! the CAPM require that the model be treated with 10 caution?
11 A: Yes, as was the case with the DCF model, the assumptions underlying any model
2 in the social sciences, including the CAPM, are stringent. Moreover, the empirical
13 validity of the CAPM has been the subject of intense research in recent years. Although
14 the CAPM provides useful evidence, it must be complemented by other methodologies as
15 welL.
16 34.Q: Are the assumptions underlyinl! the CAPM any more or less confininl! than those
17 underlyinl! the DCF model?
18 A: I believe that the assumptions underlying the CAPM are far less stringent than
19 those underlying the DCF theory. This becomes apparent if we view the CAPM as a
20 special case of the Arbitrage Pricing Model (APM), where the market portfolio is the only
21 factor affecting securty prices. The assumptions underlying the APM are far less stringent
22 than the assumptions required for the DCF model to obtain. The APM derives from only
23 two major reasonable assumptions: that security returns are linear fuctions of several
25 Delmarva Power & Light Direct Testimony of Roger A. Morin
economic factors, and that no profitable arbitrage opportunities exist since investors are able
2 to eliminate such opportunities through risk-free arbitrage transactions. The other assump-
3 tions required by the APM are that investors are greedy and risk averse, that they can
4 diversify company-specific risks by holding large portfolios, and that enough investors
5 possess similar expectations to trigger the arbitrage process.
6 As a tool in the regulatory arena, the CAPM is a rigorous conceptual framework,
7 and is logical insofar as it is not subject to circularity problems, since its inputs are objective,
8 market-based quantities, largely immune to regulatory decisions. The data requirements of
9 the model are not prohibitive. The CAPM is one of several tools in the arsenal oftechniques
10 to determine the cost of equity capital. Caution, appropriate training in finance and
11 econometrcs, and judgment are required for its successful execution, as is the case with the
2 DCF and Risk Premium methodologies.
13 35.Q: Dr. Morin. please provide an overview of your risk premium analyses.
14 A: In order to quantify the risk premium for a natural gas distribution utility such as
15 DP&L, I have performed five risk premium studies. The first two studies deal with
16 aggregate stock market risk premium evidence using two versions of the CAPM
17 methodology and the other three studies deal directly with the energy utility industry.
18
19 A. CAPM ESTIMATES
20 36.Q: Please describe your application of the CAPM risk premium approach.
21 A: My first two risk premium estimates are based on the CAPM and on an empirical
22 approximation to the CAPM (ECAPM). The CAPM is a fundamental paradigm of
123 finance. Simply put, the fundamental idea underlying the CAPM is that risk-averse
26 Delmarva Power & Light Direct Testimony of Roger A. Morin
1 investors demand higher returns for assuming additional risk, and higher-risk securities
2 are priced to yield higher expected returns than lower-risk securities. The CAPM
3 quantifies the additional return, or risk premium, required for bearing incremental risk. It
4 provides a formal risk-return relationship anchored on the basic idea that only market risk
5 matters, as measured by beta. According to the CAPM, securities are priced such that
6 their:
7 EXPECTED RETUR = RISK-FREE RATE + RISK PREMIU
8 Denoting the risk-free rate by RF and the return on the market as a whole by RM,
9 the CAPM is:
10 K = RF + ß(RM - RF)
11 This is the seminal CAPM expression, which states that the return required by
2 investors is made up of a risk-free component, RF, plus a risk premium determined by ß
13 (RM - RF). To derive the CAPM risk premium estimate, three quantities are required: the
14 risk-free rate (RF), beta (ß), and the market risk premium, (RM - RF). For the risk-free
15 rate, I used 5.25% based on the level of current and forecast long-term interest rates. .For
16 beta, I used 0.86 and for the market risk premium ("MRP"), I used 7.2%. These inputs
17 to the CAPM are explained below.
18 37.Q: What risk-free rate did you use in your CAPM and risk premium analyses?
19 A: To implement the CAPM and Risk Premium methods, an estimate of the risk-free
20 return is required as a benchmark. As a proxy for the risk-free rate, I have relied on the
21 current and forecast level of 30-year Treasury bond yields.
22 The appropriate proxy for the risk-free rate in the CAPM is the return on the
23 longest term Treasury bond possible. This is because common stocks are very long-term
27 Delmarva Power & Light Direct Testimony of Roger A. Morin
instruments more akin to very long-term bonds rather than to short-term or intermediate-
2 term Treasury notes. In a risk premium model, the ideal estimate for the risk-free rate
3 has a term to maturity equal to the security being analyzed. Since common stock is a
4 very long-term investment because the cash flows to investors in the form of dividends
5 last indefinitely, the yield on the longest-term possible governent bonds, that is the
6 yield on 30-year Treasury bonds, is the best measure of the risk-free rate for use in the
7 CAPM. The expected common stock return is based on very long-term cash flows,
8 regardless of an individual's holding time period. Moreover, utility asset investments
9 generally have very long-term useful lives and should correspondingly be matched with
10 very long-term maturity financing instruments.
11 While long-term Treasury bonds are potentially subject to interest rate risk, this is
2 only true if the bonds are sold prior to maturity. A substantial fraction of bond market
13 participants, usually institutional investors with long-term liabilities (pension funds,
14 insurance companies), in fact hold bonds until they mature, and therefore are not subject
15 to interest rate risk. Moreover, institutional bondholders neutralize the impact of interest
16 rate changes by matching the maturity of a bond portfolio with the investment planning
17 period, or by engaging in hedging transactions in the financial futures markets. The
18 merits and mechanics of such immunization strategies are well documented by both
19 academicians and practitioners.
20 Another reason for utilizing the longest maturity Treasury bond possible is that
21 common equity has an infinite life span, and the inflation expectations embodied in its
22 market-required rate of return wil therefore be equal to the inflation rate anticipated to
prevail over the very long-term. The same expectation should be embodied in the risk
28 Delmarva Power & Light Direct Testimony of Roger A. Morin
free rate used in applying the CAPM modeL. It stands to reason that the yields on 30-
2 year Treasury bonds will more closely incorporate within their yield the inflation
3 expectations that influence the pnces of common stocks than do short-term or
4 intermediate-term u.s. Treasury notes.
5 Among U.S. Treasury securities, 30-year Treasury bonds have the longest term to
6 maturity and the yield on such securities should be used as proxies for the risk-free rate in
7 applying the CAPM, provided there are no anomalous conditions existing in the 30-year
8 Treasury market. In the absence of such conditions, I have relied on the yield on 30-year
9 Treasury bonds in implementing the CAPM and risk premium methods.
38.Q: Dr. Morin. why did YOU reject short-term. interest rates as proxies for the risk-free
rate in implementinl! the CAPM?
o A: Short-term rates are volatile, fluctuate widely, and are subject to more random
11 disturbances than are long-term rates. Short-term rates are largely administered rates.
12 For example, Treasury bils are used by the Federal Reserve as a policy vehicle to
13 stimulate the economy and to control the money supply, and are used by foreign
14 governents, companies, and individuals as a temporary safe-house for money.
15 As a practical matter, it makes no sense to match the return on common stock to
16 the yield on 90-day Treasury Bills. This is because short-term rates, such as the yield on
17 90-day Treasury Bils, fluctuate widely, leading to volatile and unreliable equity return
18 estimates. Moreover, yields on 90-day Treasury Bils typically do not match the equity
19 investor's planning horizon. Equity investors generally have an investment horizon far in
20 excess of 90 days.
As a conceptual matter, short-term Treasury bil yields reflect the impact of
29 Delmarva Power & Light Direct Testimony of Roger A. Morin
1 factors different from those influencing the yields on long-term securities such as
2 common stock. For example, the premium for expected inflation embedded into 90-day
3 Treasury Bills is likely to be far different than the inflationary premium embedded into
4 long-term securities yields. On grounds of stability and consistency, the yields on long-
5 term Treasury bonds match more closely with common stock returns.
6 39.Q: What is your estimate of the risk-free rate in applyinl! the CAPM?
7 A: The level of U.S. Treasury 30-year long-term bond yields prevailing in August
8 2006 as reported in the Value Line Investment Analyzer ("VLIA") August 2006 edition
9 was 5.1 %. I also consulted a variety of interest rate forecasts, including Blue Chip
10 financial Forecasts, Consensus Forecasts of the U.S. Economy published by Consensus
11 Economics, and Value Line's most recent quarterly economic forecasts. All of these
2 forecasts indicate a long-term Treasury bond yield of 5.4% over the next few years. In
13 light of the indicated range of 5.1 % - 5.4%, I used 5.25% as a reasonable estimate of the
14 risk-free rate component of the CAPM.
15 40.Q: How did you select the beta for your CAPM analysis?
16 A: A major thrst of modern financial theory as embodied in the CAPM is that
17 perfectly diversified investors can eliminate the company-specific component of risk, and
18 that only market risk remains. The latter is technically known as "beta", or "systematic
19 risk". The beta coefficient measures the change in a security's return relative to that of
20 the market. The beta coeffcient states the extent and direction of movement in the rate
21 of return on a stock relative to the movement in the rate of return on the market as a
22 whole. The beta coeffcient indicates the change in the rate of return on a stock
\23 associated with a one percentage point change in the rate of return on the market, and,
30 Delmarva Power & Light Direct Testimony of Roger A. Morin
thus, measures the degree to which a particular stock shares the risk of the market as a
2 whole. Modern financial theory has established that beta incorporates several economic
3 characteristics of a corporation which are reflected in investors' return requirements.
4 Technically, the beta ofa stock is a measure of the covariance of the return on the
5 stock with the return on the market as a whole. Accordingly, it measures dispersion in a
6 stock's return which cannot be reduced through diversification. In abstract theory for a
7 large diversified portfolio, dispersion in the rate of return on the entire portfolio is the
8 weighted sum of the beta coefficients of its constituent stocks.
9 DP&L is not publicly traded and, therefore, proxies must be used for DP&L. As a
10 first proxy for the Company's beta, I have examined the betas of a sample of publicly-
11 traded natural gas distribution utilities contained in the VLIA software. In order to
2 minimize the well-known thin trading bias in measurng beta, I only considered those
13 companies whose market capitalization exceeded $500 million.
14 As a second proxy for DP&L's beta, I examined the beta of investment-grade
15 combination gas and electric utilities covered by AUS Utility Reports. This group is
16 examined in more detail later in my testimony, in connection with the DCF estimates of
17 DP&L's cost of common equity. The average beta for the natural gas group is 0.86, as
18 shown on page 1 of Schedule RA-2. As shown on page 2 of Schedule RA-2, the
19 average beta for the combination gas and electric group is 0.87, which is virtually identical
20 to the estimate based on the natural gas group. Based on these results, a beta of 0.86 is a
21 reasonable proxy for DP&L's natural gas delivery operations. For additional perspective,
22 I note that the beta of DP&L's holding company, PHI, is 0.90 and the average beta of the
\23 companies that make up Moody's Natural Gas Utilities is 0.88.
31 Delmarva Power & Light Direct Testimony of Roger A. Morin
41. Q: What MRP estimate did you use in your CAPM analysis?
2 A: For the MRP, I used 7.2%. This estimate was based on the results of both
3 forward-looking and historical studies of long-term risk premiums. First, the Ibbotson
4 Associates study, Stocks, Bonds, Bils, and Inflation, 2006 Yearbook. compiling
5 historical returns from 1926 to 200S, shows that a broad market sample of common
6 stocks outperformed long-term U. S. Treasury bonds by 6.S%. The historical MRP over
7 the income component of long-term Treasury bonds rather than over the total return is
8 7.1 %. Ibbotson Associates recommend the use of the latter as a more reliable estimate of
9 the historical MRP, and I concur with this viewpoint. The historical MRP should be
10 computed using the income component of bond returns because the intent, even using
11 historical data, is to identify an expected MRP. The more accurate way to estimate the
2 MRP from historic data is to use the income return, not total returns on governent
13 bonds, as explained at page 66 of Ibbotson Associates, Stocks, Bonds, Bills, and
14 Inflation: Valuation Edition, 200S Yearbook. This notion is due to the income
15 component of total bond return (i. e. the coupon rate) is a far better estimate of expected
16 return than the total return (i.e. the coupon rate + capital gain), as realized capital
17 gainsllosses are largely unanticipated by bond investors. The long-horizon (1926-200S)
18 MRP (based on income returns, as required) is specifically calculated to be 7.1 % rather
19 than 6.S%.
20 Second, a DCF analysis applied to the aggregate equity market using Value
21 Line's aggregate stock market index and growth forecasts indicates a prospective MRP of
22 7.3%, almost the same as the historical estimate. The average of the historical (7.1 %)
and prospective estimates (7.3%), which is 7.2%, provides a reasonable estimate of the
32 Delmarva Power & Light Direct Testimony of Roger A. Morin
MRP.
2 42.Q: On what maturity bond does the Ibbotson historical risk premium data rely on?
3 A: Because 30-year bonds were not always traded or even available throughout the
4 entire 1926-200S long period covered in the Ibbotson Associate Study of historical
5 returns, the latter study relied on bond return data based on 20-year Treasury bonds. To
6 the extent that the normal yield curve is virtually flat above maturities of 20 years over
7 most of the period covered in the Ibbotson study, the difference in yield is not materiaL.
8 In fact, the difference in yield between 30-year and 20-year bonds is actually negative.
9 The average difference in yield over the 1977-2006 period is 13 basis points, that is, the
10 yield on 20-year bonds is slightly higher than the yield on 30-year bonds.
11 43. Q: Why did you use lonl! time periods in arrivinl! at your historical MRP estimate?
2 A: Because realized returns can be substantially different from prospective returns
13 anticipated by investors when measured over short time periods, it is important to employ
14 returns realized over long time periods rather than returns realized over more recent time
15 periods when estimating the MRP with historical returns. Therefore, a risk premium
16 study should consider the longest possible period for which data are available. Short-run
17 periods during which investors earned a lower risk premium than they expected are offset
18 by short-run periods during which investors earned a higher risk premium than they
19 expected. Only over long time periods wil investor return expectations and realizations
20 converge.
21 I have therefore ignored realized risk premiums measured over short time periods,
22 since they are heavily dependent on short-term market movements. Instead, I relied on
results over periods of enough length to smooth out short-term aberrations, and to
33 Delmarva Power & Light
Direct Testimony of Roger A. Morin
encompass several business and interest rate cycles. The use of the entire study period in
2 estimating the appropriate MRP minimizes subjective judgment and encompasses many
3 diverse regimes of inflation, interest rate cycles, and economic cycles.
4 To the extent that the estimated historical equity risk premium follows what is
5 known in statistics as a random walk, the best estimate of the future risk premium is the
6 historical mean. Since I found no evidence that the MRP in common stocks has changed
7 over time, that is, no significant serial correlation in the Ibbotson study, it is reasonable to
8 assume that these quantities will remain stable in the future.
9 44.Q: Please describe your prospective approach in derivinl! the MRP in the CAPM 10 analysis.
11 A: For my prospective estimate of the MRP, I applied a DCF analysis to the
aggregate equity market using Value Line's VLIA softare. The dividend yield on the
13 dividend-paying stocks that make up the Value Line Composite index made up of some
14 1800 stocks is currently 1.20% (VLIA 08/2006 edition), and the average projected
15 dividend growth rate is 11.02%. Adding the dividend yield to the growth component
16 produces an expected return on the aggregate equity market of 12.22%. Following the
17 tenets of the DCF model, the spot dividend yield must be converted into an expected
18 dividend yield by multiplying it by one plus the growth rate. This brings the expected
19 return on the aggregate equity market to 12.35%. Recognition of the quarterly timing of
20 dividend payments rather than the annual timing of dividends assumed in the annual DCF
21 model brings the MRP estimate to approximately 12.55%. Subtracting the risk-free rate
22 of 5.25% from the latter, the implied risk premium is 7.3% over long-term U.S. Treasury
23 bonds. The average of the historical (7.1 %) and prospective MRP (7.3%) estimates is
34 Delmarva Power & Light
Direct Testimony of Roger A. Morin
7.2%.
2 As a check on my MRP estimate, I examined a recent 2003 comprehensive article
3 published in Financial Management, Harrs, Marston, Mishra, and O'Brien ("HMMO")
4 that provides estimates of the ex ante expected returns for S&P SOO companies over the
5 period 1983-199810. HMMO measure the expected rate of return (cost of equity) of each
6 dividend-paying stock in the S&P 500 for each month from January 1983 to August 1998
7 by using the constant growth DCF modeL. The prevailing risk-free rate for each year was
8 then subtracted from the expected rate of return for the overall market to arrve at the
9 MRP for that year. The table below, drawn from HMMO Table 2, displays the average
10 prospective risk premium estimate for each year from 1983 to 1998. The average MRP
11 estimate for the overall period is 7.2%, which is very close to my estimate of7.3%.
2 Year DCF MRP
13 1983 6.6% 14 1984 5.3% 15 1985 5.7% 16 1986 7.4% 17 1987 6.1% 18 1988 6.4% 19 1989 6.6% 20 1990 7.1% 21 1991 7.5% 22 1992 7.8% 23 1993 8.2% 24 1994 7.3% 25 1995 7.7% 26 1996 7.8% 27 1997 8.2% 28 1998 9.2% 29 30 MEAN 7.2%
31
10 Harris, R. S., Marston, F. c., Mishra, D. R., and O'Brien, T. J., "Ex Ante Cost of Equity Estimates ofS&P 500 Firm: The Choice Between Global and Domestic CAPM," Financial Management, Autumn 2003, pp. 51-66.
35 Delmarva Power & Light Direct Testimony of Roger A. Morin
45.Q: What is your risk premium estimate of DP&L'S cost of equity usinl! the CAPM
2 approach?
3 A: Inserting those input values in the CAPM equation, namely a risk-free rate of
4 5.25%, a beta of 0.86, and a MRP of 7.2%, the CAPM estimate of the cost of common
5 equity for DP&L is: 5.25% + 0.86 x 7.2% = 11.4%. This estimate becomes 11.7% with
6 flotation costs. The need for a flotation cost allowance is discussed later in my
7 testimony.
8 46.Q: What is your risk premium estimate "sinl! the empirical version of the CAPM?
9 A: There have been countless empirical tests of the CAPM in the finance literature in
10 order to determine to what extent security returns and betas are related in the maner
11 predicted by the CAPM. This literature is summarized in Chapter 13 of my 1994 book,
12 Regulatory Finance, and Chapter 6 of my latest book, The New Regulatory Finance, both
13 published by Public Utilities Report Inc. The results of the tests support the idea that
14 beta is related to security returns, that the risk-return tradeoff is positive, and that the
15 relationship is linear. The contradictory finding is that the risk-return tradeoff is not as
16 steeply sloped as the predicted CAPM. That is, empirical research has long shown that
17 low-beta securities ear returns somewhat higher than the CAPM would predict, and
18 high-beta securities ear less than predicted. A CAPM-based estimate of cost of capital
19 underestimates the return required from low-beta securities and overstates the return
20 required from high-beta securities, based on the empirical evidence. This is one of the
21 most well-known results in finance, and it is displayed graphically below.
36 Delmarva Power & Light Direct Testimony of Roger A. Morin
CAPM: Predicted vs Observed Returns
Return
o
Rf Lo w beta assets High beta assets
o 1.0 Beta
2 A number of variations on the original CAPM theory have been proposed to
3 explain this finding. The ECAPM makes use of these empirical findings. The
4 ECAPM estimates the cost of capital with the equation:
5 K = RF + á + ß x ( M R P - á)
6 where á is the "alpha" of the risk-return line, a constant, MRP is the market risk
7 premium (RM - RF), and the other symbols are defined as usuaL. Inserting the long-
8 term risk-free rate as a proxy for the risk-free rate, an alpha in the range of 1 % - 2%,
9 and reasonable values of beta and the MRP in the above equation produces results that
10 are indistinguishable from the following more tractable ECAPM expression:
11 K = RF + 0.25 (RM - RF) + 0.75 ß(RM - RF)
12 An alpha range of 1 % - 2% is somewhat lower than that estimated empirically.
13 The use of a lower value for alpha leads to a lower estimate of the cost of capital for
4 low-beta stocks such as regulated utilities. This is because the use of a long-term risk-
15 free rate rather than a short-term risk-free rate already incorporates some of the desired
37 Delmarva Power & Light Direct Testimony of Roger A. Morin
1 effect of using the ECAPM. That is, the long-term risk-free rate version of the CAPM
2 has a higher intercept and a flatter slope than the short-term risk-free version which has
3 been tested. This is also because the use of adjusted betas rather than the use of raw
4 betas also incorporates some of the desired effect of using the ECAPM. Thus, it is
5 reasonable to apply a conservative alpha adjustment.
6 47.Q: Is the use of the ECAPM consistent with the use of adjusted betas?
7 A: Yes, it is. Some have argued that the use of the ECAPM is inconsistent with the
8 use of adjusted betas, such as those supplied by Value Line and Bloomberg. This is
9 because the reason for using the ECAPM is to allow for the tendency of betas to regress
10 toward the mean value of 1.00 over time, and, since Value Line betas are already adjusted
11 for such trend, an ECAPM analysis results in double-counting. This argument is
erroneous. Fundamentally, the ECAPM is not an adjustment, increase or decrease, in
13 beta. This is obvious from the fact that the observed return on high beta securities is
14 actually lower than that produced by the CAPM estimate. The ECAPM is a formal
15 recognition that the observed risk-return tradeoff is flatter than predicted by the CAPM
16 based on myrad empirical evidence. The ECAPM and the use of adjusted betas
17 comprised two separate features of asset pricing. Even if a company's beta is estimated
18 accurately, the CAPM stil understates the return for low-beta stocks. Even if the
19 ECAPM is used, the return for low-beta securities is understated if the betas are
20 understated. Referrng back to the previous graph, the ECAPM is a return (vertical axis)
21 adjustment and not a beta (horizontal axis) adjustment. Both adjustments are necessary.
22 Moreover, the use of adjusted betas compensates for interest rate sensitivity of utility
:23 stocks not captured by unadjusted betas.
38 Delmarva Power & Light Direct Testimony of Roger A. Morin
Appendix A contains a full discussion of the ECAPM, including its theoretical
2 and empirical underpinnings. In short, the following equation provides a viable
3 approximation to the observed relationship between risk and return, and provides the
4 following cost of equity capital estimate:
5 K = RF + 0.25 (RM - RF) + 0.75 ß (RM - RF)
6 Inserting 5.25% for the risk-free rate RF, a MRP of 7.2% for (RM - RF) and a beta
7 of 0.86 in the above equation, the return on common equity is 11.7% without flotation
8 costs and 12.0% with flotation costs.
9
10 B. HISTORICAL RISK PREMIUM
11 48. Q: Please describe your historical risk premium analysis of the natural 2as utilty
industry.
13 A: An historical risk premium for the natural gas utility industry was estimated with
14 an annual time series analysis applied to the natural gas utility industry as a whole, using
15 Moody's Natural Gas Distribution Index as an industry proxy. The analysis is depicted
16 on Schedule RA-3. The risk premium was estimated by computing the actual return on
17 equity capital for Moody's Index for each year from 1955 to 2001 using the actual stock
18 prices and dividends of the index, and then subtracting the long-term governent bond
19 return for that year. Data for this particular index was unavailable for periods prior to
20 1955 and data beyond 2001 were not available following the acquisition of Moody's by
21 Mergent.
22 As shown on Page 1 of Schedule RA-3, the average risk premium over the
123 period was 5.70% over long-term Treasury bonds. Given the risk-free rate of 5.25%, the
39 Delmarva Power & Light Direct Testimony of Roger A. Morin
implied cost of equity from this particular method is 5.25% + 5.7% = 10.95% without
2 flotation costs and 11.3% with flotation costs.
3 49.Q: Please describe your historical risk premium analysis of the electric utilty industry.
4 A: As a check on the historical risk premium estimate obtained from the natural gas
5 utility industry, I examined the historical risk premium inherent in the electric utility
6 industry. The advantage of this method is that historical data are available over a much
7 longer historical period for the electric utility industry than was the case for the natural
8 gas industry, thereby enhancing the statistical reliability of the estimate. Moreover, it is
9 reasonable to postulate that DP&L's natural gas business possesses an investment risk
10 profie similar to that of the electric utility business. Over most of the historical period
11 covered by this study for which data are readily available, namely 1927-2001, the electric
2 utility business provides a reasonable proxy for the natural gas distribution business
13 because it possessed economic characteristics similar to those of natural gas distribution
14 utilities, enjoyed the same umbrella of protection as a regulated monopoly utility, and
15 enjoyed virtually identical allowed rates of retur over that period, attesting to the risk
16 comparability.
17 Therefore, a historical risk premium for the electric utility industry was estimated
18 with an annual time series analysis applied to the electric utility industry as a whole,
19 using Moody's Electric Utility Index as an industry proxy. The analysis is depicted on
20 pages 2 and 3 of Schedule RA-3. The risk premium was estimated by computing the
21 actual return on equity capital for Moody's Index for each year using the actual stock
22 prices and dividends of the index, and then subtracting the long-term Treasury bond
return for that year. The average risk premium over the period was 5.6% over long-term
40 Delmarva Power & Light Direct Testimony of Roger A. Morin
Treasury bonds. Given that the risk-free rate is 5.25%, the implied cost of equity for the
2 average electric utility from this particular method is 5.25% + 5.6% = 10.85% without
3 flotation costs and 11.2% with flotation costs. This result is virtually identical to the
4 natural gas industry estimate.
5 50.Q: How does the inclusion of recent risk premIum data alter these results?
6 A: Both the historical risk premium analyses for the natural gas and electric utility
7 industries stop in 2001 because the annual Moody's Public Utility Manual from which
8 the data were drawn was discontinued following the acquisition of Moody's by Mergent
9 in 2002. In view of the rising risk premium allowed by regulators documented in the
10 next section of my testimony, it would not be unreasonable to expect that the current
11 utility risk premium exceeds the historical average. I did examine some more recent
12 historical bond return and equity return data based on the S&P Utility Index instead of
13 Moody's Electric Utility Index. The addition of 2002-2005 data actually raises the
14 historical risk premium slightly. This result is not surprising in view of the rising equity
15 market in the 2003-2005 period.
16 51.Q: Dr. Morin. are risk premium studies widely used?
17 A: Yes, they are. Risk Premium analyses are widely used by analysts, investors, and
18 expert witnesses. Most college-level corporate finance and/or investment management
19 texts including Investments by Bodie, Kane, and Marcus, McGraw-Hill Irin, 2002,
20 which is a recommended textbook for CF A (Chartered Financial Analyst) certification
21 and examination, contain detailed conceptual and empirical discussion of the risk
22 premium approach. The latter is typically recommended as one of the three leading
methods of estimating the cost of capitaL. Professor Brigham's best-selling corporate
41 Delmarva Power & Light Direct Testimony of Roger A. Morin
finance textbook (Financial Management: Theory and Practice, 11 th ed., South- Western,
2 2005), recommends the use of risk premium studies, among others. Techniques of risk
3 premium analysis are widespread in investment community reports. Professional
4 certified financial analysts are certainly well versed in the use of this method.
5 52.Q: Are you concerned about the realism of the assumptions that underlie the historical
6 risk premium method?
7 A: No, I am not, for they are no more restrictive than the assumptions that underlie
8 the DCF model or the CAPM. While it is true that the method looks backward in time
9 and assumes that the risk premium is constant over time, these assumptions are not
10 necessarily restrictive. By employing returns realized over long time periods rather than
11 returns realized over more recent time periods, investor return expectations and
12 realizations converge. Realized returns can be substantially different from prospective
13 returns anticipated by investors, especially when measured over short time periods. By
14 ensuring that the risk premium study encompasses the longest possible period for which
15 data are available, short-run periods during which investors earned a lower risk premium
16 than they expected are offset by short-run periods during which investors eared a higher
17 risk premium than they expected. Only over long time periods wil investor return
18 expectations and realizations converge, or else, investors would never commit any funds.
19 c. ALLOWED RISK PREMIUMS
20 53.Q: Please describe your analysis of allowed risk premiums in the natural l!as utilty
21 industry.
A: To estimate the Company's cost of common equity, I also examined the historical
23 risk premiums implied in the returns on equity ("ROE") allowed by regulatory
42 Delmarva Power & Light Direct Testimony of Roger A. Morin
commissions for natural gas utilities over the last decade relative to the contemporaneous
2 level of the long-term Treasury bond yield. This variation of the risk premium approach
3 is reasonable because allowed risk premiums are presumably based on the results of
4 market-based methodologies (DCF, Risk Premium, CAPM, etc.) presented to regulators
5 in rate hearings and on the actions of objective unbiased investors in a competitive
6 marketplace. Historical allowed ROE data are readily available over long periods on a
7 quarterly basis from Regulatory Research Associates (RR) and easily verifiable from
8 RR publications and past commission decision archives. The average ROE spread over
9 long-term Treasury yields was 5.5% for the 1997-2006 time period, as shown by the
10 horizontal line in the graph below. The graph also shows the year-by-year allowed risk
11 premium. The steady escalating trend of the risk premium in response to lower interest
rates and rising competition is noteworthy.
Natural Gas Distribution Uties Alo\\d Risk Prenium 1997-2006
7.0
E 6.5 :: 'Ë J: 6.0 "" Risk Premiwn i: 5.5 -0 ~ Avg. Risk Premium "0 ~ 5.0 ~ :; 4.5
4.0 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 Year 13
14 A careful review of these ROE decisions relative to interest rate trends reveals a
15 narrowing of the risk premium in times of rising interest rates, and a widening of the
6 premium as interest rates fall. The following statistical relationship between the risk
43 Delmarva Power & Light Direct Testimony of Roger A. Morin
1 premium (RP) and interest rates (YIELD) emerges over the last decade:
2 RP = 8.7064 - 0.5892 YIELD R2 = 0.62 3 (t = 3.6) 4 5 I I as indicated by the high R2 and 6 The relationship is highly statistically significant
7 statistically significant t-value of the slope coeffcient. The graph below shows a clear
8 inverse relationship between the allowed risk premium and interest rates as revealed in
9 past ROE decisions.
Alowed Rik Premumvs Interest Ras Natural Gas Utilities 1997-2006
7.0
E '§ 6.0 ._'~¡-..~--...... ~~ . ....0*-.." . "" ~ 5.0 ..... ". . Actual ." . ...i~..-..... 0 Fitted Q) ~ .. 4.0 :;
3.0 4.0 4.5 5.0 5.5 6.0 6.5 7.0 Interest Rates 10 11 Inserting the current long-term Treasury bond yield of 5.25% in the above
12 equation suggests that a risk premium estimate of5.6% should be allowed for the average
13 risk natural gas utility, implying a cost of equity of 10.9% for the average risk utility.
14 No flotation cost adjustment is required here since the return figures are allowed book
15 returns on common equity capitaL.
16 54.Q: Dr. Morin. does the observed relationship between allowed utilty returns and
i i The coeffcient of determination R2, sometimes called the "goodness of fit measure" is a measure of the degree of explanatory power of a statistical relationship. It is simply the ratio of the explained portion to the total sum of squares. The higher R2 the higher is the degree of the overall fit of the estimated regression equation to the sample data. The t-statistic is a standard measure of the statistical significance of an independent variable in a regression relationship. A t-value above 2.0 is considered highly significant.
44 Delmarva Power & Light Direct Testimony of Roger A. Morin
interest rates hold over lonl!er periods as well?
2 A: Yes, it does indeed. The relationship is even more significant over longer periods
3 with a R2 of 0.83 and a t-value of 9.5. The graph below illustrates the inverse
4 relationship between the allowed risk premium and interest rates as revealed in some 550
5 past ROE decisions over the longest period over which such data are available from
6 RR, namely 1987-2006.
Allowed Risk Premium vs Interest Rates 1987-2006
7.0
E "- = 6.0 - .e .. "".'1-"Q -."- i:.. "'~ ~ ...... ,~ . '" 5.0 Actual æ . ~ Fitted -. ~~''-. .'.~ .. "'Q~'---l .. =t ".ft ~ 4.0 - '*'-.- :; '.,
3.0 4.0 5.0 6.0 7.0 8.0 9.0 10.0 Interest Rates 7
8 9 55.Q: Why did YOU rely on the last decade to conduct your allowed risk premium 10 analysis?
11 A: Because allowed returns already reflect investor expectations, that is, are forward-
12 looking in nature, the need for relying on long historical periods is minimized. The last
13 decade is a reasonable period of analysis in the case of allowed returns in view of the
14 stability of the inflation rate experienced over the last decade.
15 56.Q: Do investors take into account allowed returns in formulatinl! their expectations?
,16 A: Yes, they do. Investors do take into account returns granted by various regulators
45 Delmarva Power & Light Direct Testimony of Roger A. Morin
1 in formulating their risk and return expectations, as evidenced by the availability of
2 commercial publications disseminating such data, including Value Line and RR.
3 Allowed returns, while certainly not a precise indication of a particular company's cost of
4 equity capital, are nevertheless an important determinant of investor growth perceptions
5 and investor expected returns.
6 57.Q: Do allowed returns reflect investor expectations?
7 A: As far as allowed risk premiums are concerned, regulators presumably base their
8 allowed ROE decisions relative to the level of interest rates on a wide variety of evidence
9 concerning investor expected returns submitted by various parties. Because allowed
10 returns already reflect investor expectations, that is, are forward-looking in nature, the
11 need for relying on long historical periods is minimized. The last decade is a reasonable
12 period of analysis in the case of allowed returns in view of the stability of the inflation
13 rate experienced over the last decade.
14 58.Q: Dr. Morin. how do YOU explain this inverse relationship between allowed returns
15 and interest rates?
16 A: It is transparently clear from the above graph that allowed risk premiums vary
17 inversely with the levels of interest rates. Regulators have systematically increased the
18 authorized risk premium when interest rates declined, and decreased the authorized risk
19 premium when interest rates increased. In other words, commission-authorized returns
20 tend to moderate the impact of interest rate movements on allowed returns.
21 This phenomenon has been well documented for a long time. Published studies by
22 Brigham, Shome, and Vinson (1985), Harrs (1986), Hars and Marston (1992), Maddox,
Pippert and Sullivan (1995), and others demonstrate that, beginning in 1980, risk premiums
46 Delmarva Power & Light Direct Testimony of Roger A. Morin
vared inversely with the level of interest rates, rising when rates fell and declining when
2 interest rates rose. i 2 13
3 The reason for this inverse relationship is that when interest rates nse,
4 bondholders, whose interest rates are fixed, often suffer a decrease in the market value of
5 their bonds, experiencing a capital loss. This item is referred to as interest rate risk.
6 Stockholders, on the other hand, are more concerned with the firm's earning power. In
7 order to avoid interest rate risk in an environment of rising interest rates, investors tend to
8 become more willing to undertake equity investments which, although subject to some
9 fear of loss of earning power, are less sensitive to the fear of interest rate risk. The
10 resulting increase in the supply of funds available for such equity investments causes a
11 downward pressure on the market price for equity. So, generally it is observed that if
2 bondholders' fear of interest rate risk exceeds shareholders' fear of loss of earning power,
13 the risk differential will narrow and hence the risk premium wil shrnk. This item is
14 paricularly true in high inflation environments. Interest rates rise as a result of
15 accelerating inflation, and the interest rate risk of bonds intensifies more than the
16 earnings risk of common stocks, which are partially hedged from the ravages of inflation.
17 This phenomenon has been termed as a "lock-in" premium. Conversely in low interest
18 rate environments when bondholders' interest rate fears subside and shareholders' loss of
12 Brigham, E.F., Shome, D.K., and Vinson, S. R. "The Risk Premium Approach to Measuring a Utility's Cost of Equity." Financial Management, Spring 1985, 33-45. ("BSV") Harris, R.S. "Using Analysts' Growth Forecasts to Estimate Shareholder Required Rates of Retu." Financial Management, Spring 1986,58-67. Harris, R.S. and Marston, F.C. "Estimating Shareholder Risk Premia Using Analysts' Growth Forecasts." Financial Management, Summer 1992, 63-70. ("HM") Maddox, F.M., Pippert, D. T., and Sullivan, R.N. "An Empirical Study of Ex Ante Risk Premiums for the Electric Utility Industry" Financial Management, Autumn 1995, 89-95. ("MPS") 13 It is important not to confuse the risk premium on the overall equity market and the risk premium specific to the utility industry.
47 Delmarva Power & Light Direct Testimony of Roger A. Morin
earning power dominate, the risk differential will widen and hence the risk premium will
2 increase. This event has in fact occurred since 1998. In short, the empirical evidence
3 from the published academic literature demonstrates that the risk premium varies
4 inversely with the level of interest rates.
5 59.Q: Please summarize your risk premium estimates.
6 A: The table below summarizes the ROE estimates obtained from the risk premium
7 studies. The average risk premium result is 11.5%
8 Risk Premium Method % ROE 9 10 CAPM 11. 7% 11 Empirical CAPM 12.0% 12 Risk Premium Natural Gas 11.3% 13 Allowed Risk Premium 10.9% 14 15 AVERAGE 11.5% 16 17 18 D. DCF ESTIMATES
19 60.Q: Please describe the DCF approach to estimatinl! the cost of equity capitaL.
20 A: According to DCF theory, the value of any security to an investor is the expected
21 discounted value of the future stream of dividends or other benefits. One widely used
22 method to measure these anticipated benefits in the case of a non-static company is to
23 examine the current dividend plus the increases in future dividend payments expected by
24 investors. This valuation process can be represented by the following formula, which is
25 the standard DCF model:
26 Ke = D¡/P 0 + g
48 Delmarva Power & Light Direct Testimony of Roger A. Morin
where: Ke investors' expected return on equity
2 D¡ expected dividend at the end of the coming year
3 Po current stock price
4 g expected growth rate of dividends, earnings, stock price, book 5 value
6 The standard DCF formula states that under certain assumptions, which are
7 described in the next paragraph, the equity investor's expected return, Ke, can be viewed
8 as the sum of an expected dividend yield, D¡/P 0, plus the expected growth rate of future
9 dividends and stock price, g. The returns anticipated at a given market price are not
10 directly observable and must be estimated from statistical market information. The idea
11 of the market value approach is to infer 'Ke' from the observed share price, the observed
12 dividend, and an estimate of investors' expected future growth.
13 The assumptions underlying this valuation formulation are well known, and are
14 discussed in detail in Chapter 4 of my reference book, Regulatory Finance, and Chapter 8
15 of my latest textbook, New Regulatory Finance.. The standard DCF model requires the
16 following main assumptions: a constant average growth trend for both dividends and
17 earnings, a stable dividend payout policy, a discount rate in excess of the expected
18 growth rate, and a constant price-earnings multiple, which implies that growth in price is
19 synonymous with growth in earnings and dividends. The standard DCF model also
20 assumes that dividends are paid at the end of each year when, in fact, dividend payments
21 are normally made on a quarterly basis.
22 61.Q: How did you estimate DP&L'S cost of equity with the DCF model?
23 A: I applied the DCF model to two proxies for DP&L's natural gas operations: a group
of investment-grade widely-traded dividend-paying natural gas distribution utilities and a
49 Delmarva Power & Light Direct Testimony of Roger A. Morin
group of investment-grade dividend-paying combination gas and electric utilities.
2 In order to apply the DCF model, two components are required: the expected
3 dividend yield (D/Po) and the expected long-term growth (g). The expected dividend D¡
4 in the annual DCF model can be obtained by multiplying the current indicated annual
5 dividend rate by the growth factor (1 + g).
6 From a conceptual viewpoint, the stock pnce to employ in calculating the
7 dividend yield is the current price of the security at the time of estimating the cost of
8 equity. The reason is that current stock price provides a better indication of expected
9 future prices than any other price in an efficient market. An effcient market implies that
10 prices adjust rapidly to the arrval of new information. Therefore, the current price
11 reflects the fundamental economic value of a security. A considerable body of empirical
2 evidence indicates that capital markets are effcient with respect to a broad set of
13 information. This evidence implies that observed current prices represent the
14 fundamental value of a security, and that a cost of capital estimate should be based on
15 current prices.
16 In implementing the DCF model, I have used the current dividend yields reported
17 in the latest edition of Value Line's VLIA softare. Basing dividend yields on average
18 results from a large group of companies reduces the concern that idiosyncrasies of
19 individual company stock prices wil result in an unrepresentative dividend yield.
20 62.Q: How did you estimate the l!rowth component of the DCF model?
21 A: The principal difficulty in calculating the required return by the DCF approach is
22 in ascertaining the growth rate that investors currently expect. Since no explicit estimate
'23 of expected growth is observable, proxies must be employed.
50 Delmarva Power & Light Direct Testimony of Roger A. Morin
As proxies for expected growth, I examined growth estimates developed by
2 professional analysts employed by large investment brokerage institutions. Projected
3 long-term growth rates actually used by institutional investors to determine the
4 desirability of investing in different securities influence investors' growth anticipations.
5 These forecasts are made by large reputable organizations, and the data are readily
6 available to investors and are representative of the consensus view of investors. Because
7 of the dominance of institutional investors in investment management and security
8 selection, and their influence on individual investment decisions, analysts' growth
9 forecasts influence investor growth expectations and provide a sound basis for estimating
10 the cost of equity with the DCF modeL. Growth rate forecasts of analysts are available
11 from published investment newsletters and from systematic compilations of analysts'
12 forecasts, such as those tabulated by Zacks Investment Research Inc. ("Zacks"). I used
13 analysts' long-term growth forecasts contained in Zacks as proxies for investors' growth
14 expectations in applying the DCF modeL. I also used Value Line's growth forecast as an
15 additional proxy.
16 63.Q: Why did you reject the use of historical l!rowth rates in applyiol! the DCF model to
17 utilties?
18 A: I have rejected historical growth rates as proxies for expected growth in the DCF
19 calculation because historical growth patterns are already incorporated in analysts' 20 growth forecasts that should be used in the DCF model, and are therefore somewhat 21 redundant.
22 64.Q: Did you consider any other method of estimatinl! expected l!rowth in the DCF \23 model?
51 Delmarva Power & Light Direct Testimony of Roger A. Morin
A: Yes, I did. I considered using the so-called "sustainable growth" method, also
2 referred to as the "retention growth" method. According to this method, future growth is
3 estimated by multiplying the fraction of earnings expected to be retained by the company,
4 'b', by the expected return on book equity, 'ROE'. That is,
5 g = b x ROE
6 where: g = expected growth rate in earnings/dividends
7 b = expected retention ratio
8 ROE = expected return on book equity
9 However, I do not generally subscribe to the growth results produced by this
10 particular method for several reasons. First, the sustainable method of predicting growth
11 is only accurate under the assumptions that the return on book equity (ROE) is constant
12 over time and that no new common stock is issued by the company, or if so, it is sold at
13 book value. Second, and more importantly, the sustainable growth method contains a
14 logic trap: the method requires an estimate of ROE to be implemented. But if the ROE
15 input required by the model differs from the recommended return on equity, a
16 fundamental contradiction in logic follows. Third, the empirical finance literature
17 demonstrates that the sustainable growth method of determining growth is not as
18 significantly correlated to measures of value, such as stock prices and price/earnings
19 ratios, as analysts' growth forecastsl4. I therefore placed no reliance on this method.
20 65.Q: Did YOU consider dividend l!rowth in applyinl! the DCF model?
21 A: No, not at this time. This reason is that it is widely expected that utilities will
14 See Vander Weide and Carleton, "Investor Growth Expectations: Analysts vs. History," (The Journal of
Portfolio Management, Spring 1988); Timme & Eiseman, "On the Use of Consensus Forecasts of Growth in the Constant Growth Model: The Case of Electric Utilties," (Financial Management, Winter 1989).
52 Delmarva Power & Light Direct Testimony of Roger A. Morin
continue to lower their dividend payout ratio over the next several years. In other words,
2 earnings and dividends are not expected to grow at the same rate in the future. To
3 illustrate, according to the latest edition of Value Line, the expected dividend growth of
4 3.5% for my natural gas utility group is far less than the expected earnings growth of
5 5.7% over the next few years.
6 Whenever the dividend payout ratio is expected to change, the intermediate
7 growth rate in dividends canot equal the long-term growth rate, because
8 dividend/earnings growth must adjust to the changing payout ratio. The assumptions of
9 constant perpetual growth and constant payout ratio are clearly not met. Thus, the 10 implementation of the standard DCF model is of questionable relevance in this
11 circumstance.
12 Dividend growth rates are unlikely to provide a meaningful guide to investors'
13 growth expectations for utilities in general. This result is because utilities' dividend 14 policies have become increasing conservative as business risks in the industry have
15 intensified steadily. Dividend growth has remained largely stagnant in past years as
16 utilities are increasingly conserving financial resources in order to hedge against rising
17 business risks. As a result, investors' attention has shifted from dividends to earnings.
18 Therefore, earnings growth provides a more meaningful guide to investors' long-term
19 growth expectations. Indeed, it is growth in earnings that will support future dividends 20 and share prices.
21 66.Q: Is there any empirical evidence documentinl! the importance of earninl!s in
22 evaluatinl! investors' expectations in the investment community?
53 Delmarva Power & Light Direct Testimony of Roger A. Morin
A: Yes, there is an abundance of evidence attesting to the importance of earnings in
2 assessing investors' expectations. First, the sheer volume of earnings forecasts available
3 from the investment community relative to the scarcity of dividend forecasts attests to
4 their importance. To illustrate, Value Line, Zacks Investment, First Call Thompson, and
5 Multex provide comprehensive compilations of investors' earnings forecasts, to name
6 some. The fact that these investment information providers focus on growth in earnings
7 rather than growth in dividends indicates that the investment community regards earnings
8 growth as a superior indicator of future long-term growth. Second, surveys of analytical
9 techniques actually used by analysts reveal the dominance of earnings and conclude that
10 earnings are considered far more important than dividends. Third, Value Line's principal
11 investment rating assigned to individual stocks, Timeliness Rank, is based primarily on
12 earnings, which account for 65% of the ranking.
13 67.Q: What DCF results did YOU obtain for the naturall!as utilties l!roup?
14 A: As a proxy for DP&L, I have examined the expected returns of dividend-paying
15 natural gas distribution utilities contained in Value Line's natural gas distribution
16 universe with a market value in excess of $500 milion. The group is shown in Schedule
17 RA-4. Keyspan Corp was excluded from the group on account of ongoing acquisition
18 negotiations with National Grid.
19 As shown on Column 4 of Schedule RA-4, the average long-term growth
20 forecast obtained from the Zacks corporate earings database is 5.3% for the natural gas
21 distribution grouplS. Combining this growth rate with the average expected dividend
22 yield of 3.9% shown in Column 5 produces an estimate of equity costs of 9.2% for the
15 No growth estimate was available for Laclede Gas. Value Line's growth forecast was used instead.
54 Delmarva Power & Light Direct Testimony of Roger A. Morin
1 gas distribution group. Recognition of flotation costs brings the cost of equity estimate to
2 9.4%, shown in Column 6.
3 Repeating the exact same procedure, only this time using Value Line's long-term
4 earnings growth forecast of5.7% instead of the Zacks consensus growth forecast, the cost
5 of equity for gas distribution group is 9.6%, unadjusted for flotation costs. Adding an
6 allowance for flotation costs brings the cost of equity estimate to 9.8%. This analysis is
7 displayed on Schedule RA-5.
8 68.Q: Please describe your second proxy l!roup for the company's natural l!as distribution 9 business?
10 A: As a second proxy for the Company's natural gas distribution business, I
11 examined a group of investment-grade combination gas and electric utilities. The latter
12 possess economic characteristics similar to those of natural gas distribution utilities.
13 They are both involved in the distribution of energy services products at regulated rates in
14 a cyclical and weather-sensitive market. They both employ a capital-intensive network
15 with similar physical characteristics. They are both subject to rate of return regulation.
16 Therefore, my second group of companies as a proxy for the Company's natural
17 gas business consists of investment-grade combination gas and electric utilities covered 18 in the AUS Utility Reports, July 2006. Companies below investment-grade, that is,
19 companies with a bond rating below Baa3, were eliminated as well as those companies
20 without Value Line coverage. The final sample is shown on Page 1 of Schedule RA-6. 21 69.Q: What DCF results did yOU obtain for the combination l!as and electric utilties l!roup 22 usinl! the value line l!rowth projections?
A: For purposes of conducting the DCF analysis, as shown on Page 1 of Schedule
55 Delmarva Power & Light Direct Testimony of Roger A. Morin
1 RA-6, two companies were eliminated from the DCF analysis: Public Service
2 Enterprise Group which is presently involved in merger negotiations, and TECO with an
3 unsustainable growth rate of 19%. As shown on Column 2 of page 2 of Schedule RA-
4 6, the average long-term growth forecast obtained from Value Line is 5.6% for this
5 group. Combining this growth rate with the average expected dividend yield of 4.0%
6 shown in Column 3 produces an estimate of equity costs of 9.6% for the group,
7 unadjusted for flotation costs. Adding an allowance for flotation costs to the results of
8 Column 4 brings the cost of equity estimate to 9.9%, shown in Column 5.
9 70.Q: What DCF results did you obtain for the combination l!as and electric utilties l!roup
10 usinl! the analysts' consensus l!rowth forecast?
11 A: From the original sample of 21 companies shown on page 1 of Schedule RA-6,
12 CH Energy, MGE Energy, and UniSource Energy were eliminated as no analysts' growth
13 forecasts were available from Zacks, and Public Service Enterprise Group was also
14 discarded on account of ongoing merger negotiations. For the remaining 18 companies,
15 using the consensus analysts' earnings growth forecast published by Zacks of 6.5%
16 instead of the Value Line forecast, the cost of equity for the group is 10.6%. Allowance
17 for flotation costs brings the cost of equity estimate to 10.9%. This analysis is shown in 18 Schedule RA-7.
19 71.Q: Please summarize your DCF estimates.
20 A: The table below summarizes the DCF estimates. The average DCF result is
21 10.2%.
22
56 Delmara Power & Light Direct Testimony of Roger A. Morin
1 DCF STUDY ROE 2 3 Natural Gas Distribution Zacks Growth 9.4% 4 Natural Gas Distribution Value Line Growth 9.8% 5 Combination Gas & Elec. Utilities Zacks Growth 10.9% 6 Combination Gas & Elec. Utilities Value Line Growth 9.9% 7 8 AVERAGE 10.2%
9 72.Q: Do these DCF results understate the cost of equity for DP&L?
10 A: Yes, they do. As discussed at length earlier, application of the standard DCF
11 model to utility stocks understates the investor's expected return when the M/B ratio of a
12 given stock exceeds 1.0, as is the case presently.
13 73.Q: Dr. Morin. please now turn to the need for a flotation cost allowance.
14 A: All the market-based estimates reported above include an adjustment for flotation
15 costs. The simple fact of the matter is that common equity capital is not free. Flotation
16 costs associated with stock issues are exactly like the flotation costs associated with
17 bonds and preferred stocks. Flotation costs are incurred; they are not expensed at the
18 time of issue and, therefore, must be recovered via a rate of return adjustment. This
19 treatment is done routinely for bond and preferred stock issues by most regulatory
20 commissions, including FERC. Clearly, the common equity capital accumulated by the
21 Company is not cost-free. The flotation cost allowance to the cost of common equity
22 capital is discussed and applied in most corporate finance textbooks; it is unreasonable to
23 ignore the need for such an adjustment.
24 Flotation costs are very similar to the closing costs on a home mortgage. In the
25 case of issues of new equity, flotation costs represent the discounts that must be provided
to place the new securities. Flotation costs have a direct and an indirect component. The
57 Delmarva Power & Light Direct Testimony of Roger A. Morin
direct component is the compensation to the security underwriter for his
2 marketing/consulting services, for the risks involved in distributing the issue, and for any
3 operating expenses associated with the issue (printing, legal, prospectus, etc.). The
4 indirect component represents the downward pressure on the stock price as a result of the
5 increased supply of stock from the new issue. The latter component is frequently referred
6 to as "market pressure. "
7 Investors must be compensated for flotation costs on an ongoing basis to the
8 extent that such costs have not been expensed in the past, and therefore the adjustment
9 must continue for the entire time that these initial funds are retained in the firm.
10 Appendix B to my testimony discusses flotation costs in detail, and shows: (1) why it is
11 necessary to apply an allowance of 5% to the dividend yield component of equity cost by
12 dividing that yield by 0.95 (100% - 5%) to obtain the fair return on equity capital; (2)
13 why the flotation adjustment is permanently required to avoid confiscation even if no
14 further stock issues are contemplated; and (3) that flotation costs are only recovered if the
15 rate of return is applied to total equity, including retained earnings, in all future years.
16 By analogy, in the case of a bond issue, flotation costs are not expensed but are
17 amortized over the life of the bond, and the annual amortization charge is embedded in
18 the cost of service. The flotation adjustment is also analogous to the process of
19 depreciation, which allows the recovery of funds invested in utility plant. The recovery
20 of bond flotation expense continues year after year, irrespective of whether the Company
21 issues new debt capital in the future, until recovery is complete, in the same way that the
22 recovery of past investments in plant and equipment through depreciation allowances
continues in the future even if no new construction is contemplated. In the case of
58 Delmarva Power & Light Direct Testimony of Roger A. Morin
common stock that has no finite life, flotation costs are not amortized. Thus, the recovery
2 of flotation cost requires an upward adjustment to the allowed return on equity.
3 A simple example will ilustrate the concept. A stock is sold for $100, and
4 investors require a 10% return, that is, $10 of earnings. But if flotation costs are 5%, the
5 Company nets $95 from the issue, and its common equity account is credited by $95. In
6 order to generate the same $10 of earnings to the shareholders, from a reduced equity
7 base, it is clear that a return in excess of 10% must be allowed on this reduced equity
8 base, here 10.52%.
9 According to the empirical finance literature discussed in Appendix B, total
10 flotation costs amount to 4% for the direct component and 1 % for the market pressure
11 component, for a total of 5% of gross proceeds. This in turn amounts to approximately
12 30 basis points, depending on the magnitude of the dividend yield component. To
13 ilustrate, dividing the average expected dividend yield of approximately 5.0% for utility
14 stocks by 0.95 yields 5.3%, which is 30 basis points higher.
15 Sometimes, the argument is made that flotation costs are real and should be
16 recognized in calculating the fair return on equity, but only at the time when the expenses
17 are incurred. In other words, the flotation cost allowance should not continue
18 indefinitely, but should be made in the year in which the sale of securities occurs, with no
19 need for continuing compensation in future years. This argument is valid only if the
20 Company has already been compensated for these costs. If not, the argument is without
21 merit. My own recommendation is that investors be compensated for flotation costs on
22 an on-going basis rather than through expensing and that the flotation cost adjustment
continue for the entire time that these initial funds are retained in the firm.
59 Delmarva Power & Light Direct Testimony of Roger A. Morin
There are several sources of equity capital available to a firm including: common
2 equity issues, conversions of convertible preferred stock, dividend reinvestment plan,
3 employees' savings plan, warrants, and stock dividend programs. Each item carres its
4 own set of administrative costs and flotation cost components, including discounts,
5 commissions, corporate expenses, offering spread, and market pressure. The flotation
6 cost allowance is a composite factor that reflects the historical mix of sources of equity.
7 The allowance factor is a build-up of historical flotation cost adjustments associated and
8 traceable to each component of equity at its source. It is impractical and prohibitively
9 costly to start from the inception of a company and determine the source of all present
10 equity. A practical solution is to identify general categories and assign one factor to each
11 category. My recommended flotation cost allowance is a weighted average cost factor
2 designed to capture the average cost of various equity vintages and types of equity capital
13 raised by the Company.
14 74.Q: Is a flotation cost adjustment reQuired for an operatinl! subsidiary like DP&L that
15 does not trade publicly?
16 A: Yes, it is. It is sometimes alleged that a flotation cost allowance is inappropriate
17 if the utility is a subsidiary whose equity capital is obtained from its parent, in this case,
18 PHI. This objection is unfounded since the parent-subsidiary relationship does not
19 eliminate the costs of a new issue, but merely transfers them to the parent. It would be
20 unfair and discriminatory to subject parent shareholders to dilution while individual
21 shareholders are absolved from such dilution. Fair treatment must consider that, if the
22 utility-subsidiary had gone to the capital markets directly, flotation costs would have
been incurred.
60 Delmarva Power & Light Direct Testimony of Roger A. Morin
III. SUMMARY OF COST OF EQUITY RECOMMENDATION
2 75.Q: Please summarize your results and recommendation.
3 A: To arrve at my final recommendation, I performed four risk premium analyses.
4 For the first two risk premium studies, I applied the CAPM and an empirical
5 approximation of the CAPM using current market data. The other two risk premium
6 analyses were performed on historical and allowed risk premium data from natural gas
7 distribution industry aggregate data. I also performed DCF analyses on two surrogates
8 for DP&L: a group representative of the natural gas distribution utility industry, and a
9 group of investment-grade combination gas and electric utilities.
10 The average result from the three principal methodologies is as follows:
11
12 CAPM 11. 9%
13 Risk Premium 11.1 %
14 DCF 10.0%
15 AVERAGE 11.0%
16 The overall average result is 11.0% for the average natural gas distribution utility.
17 Note that all three methods, including DCF are equally weighted, and that the DCF
18 results are based on four different tests.
19 76.Q: Did YOU adjust these results to account for the fact that DP&L is riskier than the
20 averal!e natural l!as distribution utilty?
21 A: Yes, I have. The cost of equity estimates derived from the various comparable
22 groups reflect the risk of the average natural gas distribution utility. To the extent that
these estimates are drawn from a group of less risky and larger companies, the expected
61 Delmarva Power & Light Direct Testimony of Roger A. Morin
equity return applicable to the riskier DP&L is downward-biased. DP&L's particular
2 investment risks are discussed below. I estimate the bias to be at least 25 basis points. I
3 have therefore increased my ROE estimate of 11.0% for the average risk natural gas
4 distribution utility to 11.25% in order to account for DP&L's higher relative risks.
5 77.Q: What. if any. risk factors do YOU consider important in defininl! the appropriate risk
6 premium for Delmarva Power's natural l!as business in comparison to other local
7 distribution companies?
8 A: My examination of the Company included discussions of the business
9 environment with Company management. These discussions surfaced four aspects that I
10 consider significant sources of risk compared to other companies in the gas utility
11 industry and in my comparison group. Those factors are:
12 1. A mature service terrtory, with growth limited by jurisdictional boundaries and
13 geography;
14 2. Competition for heating market share has produced a coalition of propane and
15 fuel oil dealers who have been successful over the past two decades in erecting
16 regulatory hurdles to constrain Company access to customers, especially those
17 residents of the franchise terrtory already using propane or fuel oiL.
18 78.Q: How does a mature territory impact stockholder risk?
19 A: One of the fundamental expectations of stockholders is growth of a company that
20 generates a contribution to return on equity. A company that is mature is by definition
21 not growing as quickly as another company in the same industry that continues to see
22 significant growth opportunity. This lack of growth opportunity impacts the potential
\23 growth in dividends per share, and is normally considered a negative indicator of the
62 Delmarva Power & Light Direct Testimony of Roger A. Morin
attractiveness of any equity. In Delmarva's case, the gas terrtory is bounded by state
2 borders and territorial boundaries, remaining open land for development is limited, and
3 residential development activities are migrating out of Delmarva's terrtory to the south
4 of New Castle County.
5 79.Q: How does competition in the heatinl! market impact the risk profie of Delmarva's 6 natural l!as utilty operations?
7 A: Natural gas local distribution companies typically compete with a variety of
8 energy sources for the heating market, whether they be fuel oil or propane distributed by
9 local dealers, wood available for purchase or cutting on the customer's property, solar
10 installations on the customer's residence or business, or resistance electric, electric heat
11 pump, or geothermal heat pump installations supported by the local electric utility. In
12 many markets, the gas utility is allowed to advertise and is allowed to offer promotional
13 incentives to prospective customers. The general objective is to maximize sales through
14 the plant investment to spread fixed costs over as large a sales base as can practically be
15 achieved, thus lowering rates to natural gas customers. As I understand the Delaware
16 situation, Delmarva has a relatively restrictive and time consuming revenue test for
17 existing residences in place as a result of the intervention of a coalition of oil and propane
18 dealers during a base rate case in the 1990's, and less restrictive revenue tests for new
19 commercial and residential customers. The imposition of these revenue tests certainly
20 benefits Delmara's competition. In a time when sales have declined, restrictions on
21 adding sales tend to delay recovery of lost sales and provide pressure to raise rates. The
22 fact that restrictions exist on adding sales to make up for lost sales, absent a rate case that
yields rates that fully recover the costs of service, means that the Company is at
63 Delmarva Power & Light Direct Testimony of Roger A. Morin
somewhat greater risk of being unable to achieve its allowed rate ofretum.
2 80.Q: Dr. Morin. can YOU briefly describe the importance of a company's credit ratinl!s?
3 A: Certainly. In the capital markets, a credit rating is an independent rating agency's
4 opinion of the creditworthiness of a company - its ability to meet its obligations to its
5 debt holders. It is the single most important factor influencing risk assessments of fixed
6 income securities and bank credit terms. The higher the credit rating, the greater the
7 perceived likelihood that the debt investors will receive their interest and principal
8 payments as expected. As such, a company with a higher credit rating is a more
9 attractive investment. Conversely, a lower credit rating can impact the ability of an issuer
10 to access capital markets on a consistent basis, negatively impacting the cost and
11 availability of both debt and credit.
2 Lower credit ratings reflect increased investor risk; therefore, investors expect to
13 get paid more to provide funds to such an issuer. Many investors, such as pension funds
14 and other institutional investors, are prohibited from investing in debt instrments below
15 a certain rating. The lower the credit rating, the more stringent the terms will be, and the
16 more restrictive the covenants on new issues will be. So the credit rating affects not only
17 the cost of the debt, but also the amount and nature of capital that is available to the
18 company.
19 Credit ratings are also used by entities involved in commodity sales and
20 purchasing. Most entities require a certain minimum credit rating to grant credit when
21 sellng commodities to parties. If the party does not have an adequate credit rating, these
22 entities require them to "post margin" or make a deposit with the seller to ensure
payment. This event increases the buyer's borrowing costs. When markets are tight, it is
64 Delmarva Power & Light Direct Testimony of Roger A. Morin
possible that buyers with lower credit ratings may not have physical or financial access to
2 the commodities in question as the supply goes instead to companies with higher credit
3 ratings.
4 81.Q: Can you please comment on recent credit ratinl! actions attestinl! to the company's
5 increased risk?
6 A: Throughout the first half of 2006, DP&L was under increased credit rating
7 pressure from the bond rating agencies that rate DP&L's debt: Standard & Poor's (S&P),
8 Moody's, and Fitch. During that period, all three changed the outlook on DP&L's ratings
9 from "stable" to "negative".16
10 On Feb. 28, 2006, Standard & Poor's Ratings Services wared that "any definitive
11 legislative action or regulatory determination that would signifcantly reduce recovery of
12 higher power costs in rates could permanently harm credit quality, and could affect
13 ratings. "
14 On March 17,2006, S&P placed its 'BBB+' long-term corporate credit rating on
15 DP&L on CreditWatch with negative implications. The CreditWatch listing "reflects
16 concerns with the financial effect of potential regulatory decisions for utility subsidiaries
17 Delmarva Power & Light Co. (DPL) and Potomac Electric Power Co (Pepco) that may
18 hinder management's plan to improve financial measures that are currently weak for the
19 'BBB+ i rating. In addition, Standard & Poor's had expected a material improvement in
20 these financial measures over the intermediate term, and now that improvement may not
21 occur for various reasons."
22 On April i\ 2006, Fitch continued to maintain its Negative Outlook on DP&L.
65 Delmarva Power & Light Direct Testimony of Roger A. Morin
following the enactment of an electric utility law in Delaware that provides a three-year
2 rate mitigation. "Fitch expects modest but manageable pressure on Delmarva's financial
3 profile over the intermediate term. Potentially more worrisome, however, is the
4 heightened concern about the political/regulatory environment in Maryland and the
5 impact on Delmarva and PEPCo."
6 On March 2006, Moody's placed DP&L's bond rating on review for possible
7 downgrade. Moody's stated that the rating action reflected among other factors the
8 "regulatory risks associated with recent political, legislative, and regulatory
9 developments in Delaware and Maryland."
10 Following its review for possible downgrade initiated in March 2006, Moody's
11 downgraded the ratings ofDP&L's senior unsecured debt from Baal to Baa2 on July 11,
12 2006. Among the factors driving the downgrade, Moody's cited the following:
13 "The signifcant decline in the supportiveness of the regulatory environments for
14 electric utilities in Maryland and Delaware... "
15 "Expectations that rate relief wil be less constructive in the currently contentious
16 environment ...
17 "Legislative and regulatory developments in both Maryland and Delaware that
18 wil defer regulatory recovery of some of the substantially higher costs that
19 resulted from power supply auctions held in those states earlier this year. "
20 "Signs of a tougher regulatory response in Delaware... "
21 Finally, on August 7, 2006 S&P downgraded DP&L's credit ratings from BBB+
22 to BBB citing "an increasingly challenging regulatory environment" as a driving factor.
16 The Outlook associated with a credit rating provides the rating agency's opinion of the probable long-
66 Delmarva Power & Light Direct Testimony of Roger A. Morin
1 As a result of this action, DP&L has a lower than average credit rating for the electric
2 utility industry.
3 82.Q: What are the consequences of the downl!rade for the company and its customers?
4 A: DP&L's credit ratings are at the lower end, that is, less desirable, of those held by
5 other natural gas utilities. Not only is a reduced credit rating very diffcult to restore, it
6 also increases borrowing costs, reduces access to capital and availability of longer-terms,
7 and does not enable DP&L to absorb any negative volatility in its financial performance.
8 Moreover, a lower credit rating has a potential negative impact on DP&L's ability to
9 procure commodities, particularly fuel, at competitive cost.
10 The extra costs associated with the downgrade as the full effect will be gradual
11 and are as yet unkown. However, the downgrade wil have long-term cost implications
12 for DP&L and its customers as the Company re-finances existing debt, attempts to issue
13 new capital and enters into new contractual arrangements. As shown in Schedule RA-9,
14 DPL is planning to issue long-term debt later this year and it may reflect extra costs
15 associated with the downgrade.
16 Not only are capital costs higher as a result of the downgrade, there are also
17 several other important qualitative effects of lowering the quality of the Company's debt
18 securities. The yield advantage of a higher bond rating increases dramatically in adverse
19 capital market conditions. Bond flotation costs, which must be borne by customers,
20 increase also as bond ratings decline, particularly in years of diffcult financial markets.
21 Not only is lower bond quality associated with higher yields, but lower-rated utility bonds
22 also carry shorter maturities, especially in tight capital markets. The result is a maturity
term direction of the issuer's credit rating. The outlook can be "positive, "stable" or "negative".
67 Delmara Power & Light Direct Testimony of Roger A. Morin
mismatch between the firm's long-term capital assets and its liabilities. Moreover, lower
2 bond quality is associated with more years of call protection, particularly during diffcult
3 financial markets; since bonds are frequently called after a decrease in interest rates,
4 bonds which carry call protection for a greater number of years are more costly to utility
5 companies. Finally, as bond ratings decline, the probability that a company wil reduce
6 the dollar amount or shorten the maturity of its bond issues increases dramatically; this in
7 turn reduces the marketability of a bond issue, and hence increases its yield. The reverse
8 is true as welL.
9 A strong financial position ensures the Company will have access to the capital it
10 needs at competitive rates, which helps reduce costs to customers. On an on-going basis,
11 DP&L requires money from investors to re-finance existing loans as they mature. Future
12 expansion and environmental investments will require significant capital that, if not
13 readily accessible, could cause increased costs for Delaware customers. The continued
14 financial strength of the utility is an underlying requirement for the Company to be able
15 to provide cost-effective, reliable service to customers.
16 Clearly, DP&L's customers have a vested interest in a strong financial position
17 for the utility. The interests of customers and shareholders of DP&L are not mutually
18 exclusive. They both benefit from a financially sound utility.
19 83.Q: What do YOU conclude on DP&L'S relative investment risk?
20 A: In conclusion, in my judgment, DP&L's total investment risk is higher than the
21 industry at this time, on account of the paricular demand risk and regulatory risk it faces.
22 In order to account for these increased risks, I have increased my recommended return by
approximately 25 basis points, that is, from 11.0% for the average risk natural gas utility
68 Delmarva Power & Light Direct Testimony of Roger A. Morin
to 11.25% in order to recognize DP&L's higher relative risk. The 25 basis points
2 adjustment is based on utility bond yield spreads differentials between utility bonds rated
3 average and bonds rated low Baa.
4 The CAPM formula was also referenced to approximate the return (cost of equity)
5 differences implied by the differences in the betas between the average natural gas utility
6 company and DP&L. The basic form of the CAPM, as discussed earlier in my testimony,
7 states that the return differential is given by the differential in beta times the MRP, (RM _
8 RF). Because I consider DP&L's beta to be approximately 0.05 higher than the natural
9 gas industry utility average, the return differential implied by the difference of 0.05 in
10 beta is given by 0.05 times (RM - RF). Using an estimate of7.2% for (RM - RF), the return
11 adjustment is close to 40 basis points.
12 84.Q: How is the company proposinl! to address its above averal!e demand risk?
13 A: The Company is proposing a measure to reduce demand risk. As a result of
14 declining demand and conservation, DP&L's margins have and wil continue to decrease,
15 while at the same time the Company continues to invest in non-revenue producing
16 infrastructure. As a result, the Company's revenues wil decline and the Company will
17 be less likely to earn its authorized rate of return. In order to address the margin
18 instability caused by declines in customer usage from conservation and in order to align
19 its financial interests with that of its customers, the Company is proposing to recover lost
20 margins through a BSA. This mechanism will provide revenue stability for the
21 Company and remove the disincentive to promote energy conservation.
22 85.Q: Would the adoption of this mechanism impact the company's risk and its cost of
common equity?
69 Delmarva Power & Light Direct Testimony of Roger A. Morin
1 A: Yes, I believe it would. If the proposed BSA mechanism is approved, the
2 company's risk will be reduced, and the cost of common equity capital will likely decline
3 by some 25 basis points from 11.25% to 11.0%. This assessment is based on bond yield
4 differentials and beta risk differentials, as previously discussed.
5 86.Q: Dr. Morin. what is your final conclusion rel!ardinl! DP&L'S cost of common equity 6 capital?
7 A: Based on the results of all my analyses, the application of my professional
8 judgment, and the risk circumstances of DP&L, it is my opinion that a just and
9 reasonable return on the common equity capital of DP&L's natural gas distribution
10 operations in the state of Delaware at this time is 11.25%. If the proposed BSA
11 mechanism is approved, the company's risk will be reduced, and the cost of common
12 equity capital is likely to decline to 11.0%.
13 87.Q: Dr. Morin. what capital structure assumption underlies your recommended return
14 on DP&L'S common equity capital?
15A: My recommended return on common equity for DP&L is predicated on the
16 adoption of a test year capital structure consisting of 46.9% common equity capital,
17 which is lower than the average common equity ratio (49.7%) of the 14 natural gas
18 distribution companies shown on Page 1 or Schedule RA-8.
19 20 iv. COMPOSITE COST OF CAPITAL
21 88.Q: What capital structure do you adopt for purposes of calculatinl! a weil!hted averal!e 22 cost of capital?
23 A: As shown on Schedule RA-9, I have adopted DP&L's proforma capital
70 Delmarva Power & Light Direct Testimony of Roger A. Morin
structure as of June 30th, 2006, as supplied to me by the Company.
2 89.Q: What is the overall weil!hted averal!e cost of capital that results from incorporation
3 of 11.0% as cost of equity?
4 A: Taking capitalization proportions and embedded costs of debt as supplied to be by
5 the company at my request, and combining them with equity cost of 11.0%, the weighted
6 average total is 8.08%. This calculation appears in Schedule RA-9. Taking those same
7 capitalization proportions and embedded costs of debt with an equity cost of 11.25%
8 (which is the proposed cost if the BSA is not adopted), the weighted average is 8.20%
9 90.Q: Finally. Dr. Morin. if capital market conditions chanl!e sil!nifcantly between the
10 date of minl! your prepared testimony and the date your oral testimony is presented.
11 would this cause yOU to revise your estimated cost of equity?
2 A: Yes. Interest rates and security prices do change over time, and risk premiums
13 change also, although much more sluggishly. If substantial changes were to occur
14 between the filing date and the time my oral testimony is presented, I wil update my
15 testimony accordingly.
16 91.Q: Does this conclude your direct testimony?
17 A: Yes, it does.
18
71 Schedule RA - .: Page 1 of 20 RESUME OF ROGER Á. MORIN
NAME: Roger A. Morin
ADDRESS: 9 King Ave. Jekyll Island, GA 31527, USA
TELEPHONE: (912) 635-3233 business offce (912) 635-3233 business fax (404) 229-2857 cellular (404) 651-2674 offce-university
E-MAIL ADDRESS:profiorinêmsn.com
DATE OF BIRTH: 3/5/1945
PRESENT EMPLOYER: Georgia State University Robinson College of Business Atlanta, GA 30303
RANK: Professor of Finance
HONORS: Professor of Finance for Regulated Industry Director Center for the Study of Regulated Industry, College of Business, Georgia State University.
EDUCATIONAL HISTORY
- Bachelor of Electrical Engineering, McGil University, Montreal, Canada, 1967.
- Master of Business Administration, McGil University, Montreal, Canada, 1969.
- PhD in Finance & Econometrcs, Wharton School of Finance, University of Pennsylvania, 1976. Schedule RAM Page 2 of 20 EMPLOYMENT HISTORY
- Lecturer, Wharton School of Finance, Univ. ofPa., 1972-3
- Assistant Professor, University of Montreal School of Business, 1973-1976.
- Associate Professor, University of Montreal School of Business, 1976-1979.
- Professor of Finance, Georgia State University, 1979-2005
- Professor of Finance for Regulated Industry and Director, Center for the Study of Regulated Industry, College of Business, Georgia State University, 1985-2005
- Visiting Professor of Finance, Amos Tuck School of Business, Darmouth College, Hanover, N.H., 1986
OTHER BUSINESS ASSOCIATIONS
- Communications Engineer, Bell Canada, 1962-1967.
- Member of the Board of Directors, Financial Research Institute of Canada, 1974-1980.
- Co-founder and Director Canadian Finance Research Foundation, 1977.
- Vice-President of Research, Garaise-Thomson & Associates, Investment Management Consultants, 1980-1981.
- Executive Visions Inc., Board of Directors, Member
- Board of External Advisors, College of Business, Georgia State University, Member 1987-1991 Schedule RA Page 3 of 20 PROFESSIONAL CLIENTS
AGL Resources AT & T Communications
Alagasco - Energen
Alaska Anchorage Municipal Light & Power
Alberta Power Ltd.
Ameren
American Water Works Company
Ameritech Arkansas Western Gas
Baltimore Gas & Electric - Constellation Energy
B.c. Telephone
B C GAS Bell Canada
Bellcore
Bell South Corp.
Brucor (New Brunswick Telephone)
Burlington-Northern C & S Ban
Cajun Electric
Canadian Radio-Television & Telecomm. Commission
Canadian Utilities
Canadian Western Natural Gas
Centel Centra Gas Central Ilinois Light & Power Co. Central Telephone Schedule RA Page 4 of 20
PROFESSIONAL CLIENTS (CONT'D)
Central & South West Corp. Chattanoogee Gas Company
Cincinnatti Gas & Electric
Cinergy Corp.
Citizens Utilities
City Gas of Florida
CN-CP Telecommunications
Commonwealth Telephone Co.
Columbia Gas System
Consolidated Natural Gas
Constellation Energy
Deerpath Group
Edison International
Edmonton Power Company
Elizabethtown Gas Co.
Energen
Engraph Corporation
Entergy Corp.
Entergy Arkansas Inc.
Entergy Gulf States, Inc.
Entergy Louisiana, Inc.
EntergyNew Orleans, Inc.
First Energy Florida Water Association
Fortis
Garaise- Thomson & Assoc., Investment Consultants Schedule RA Page 5 of 20
PROFESSIONAL CLIENTS (CONT'D)
Gaz Metropolitain
General Public Utilities
Georgia Broadcasting Corp.
Georgia Power Company
GTE California - Verizon
GTE Northwest Inc. - Verizon
GTE Service Corp. - Verizon
GTE Southwest Incorporated - Verizon
Gulf Power Company
Havasu Water Inc.
Heater Utilities - Aqua - America
Hope Gas Inc.
Hydro-Quebec
ICG Utilities Ilinois Commerce Commission Island Telephone
Jersey Central Power & Light
Kansas Power & Light
KeySpan Energy
Manitoba Hydro
Martime Telephone
Metropolitan Edison Co.
Minister of Natural Resources Province of Quebec Minnesota Power & Light Mississippi Power Company
Missour Gas Energy Schedule RA Page 6 of 20
PROFESSIONAL CLIENTS (CONT'D)
Mountain Bell
Nevada Power Company
New Brunswick Power
Newfoundland Power Inc. - Fortis Inc.
New Tel Enterprises Ltd.
New York Telephone Co.
Norfolk-Southern
Northern Telephone Ltd.
Northwestern Bell
Northwestern Utilities Ltd.
Nova Scotia Power - Emera Inc.
Nova Scotia Utility and Review Board NU Corp. NYX Oklahoma G & E
Ontario Telephone Service Commission
Orange & Rockland
Pacific Northwest Bell
People's Gas System Inc.
People's Natural Gas
Pennsylvania Electric Co.
Price Waterhouse
PSI Energy Public Service Electric & Gas
Quebec Telephone Regie de l'Energie du Quebec Schedule RAM Page 7 of 20
PROFESSIONAL CLIENTS (CONT'D)
Rochester Telephone
San Diego Gas & Electric
SaskPower
Sierra Pacific Power Company
Sierra Pacific Resources
Southern Bell
Southern States Utilities
Southern Union Gas
South Central Bell
Sun City Water Company TECO Energy
The Southern Company
Touche Ross and Company
TransEnergie
Trans-Quebec & Maritimes Pipeline
TXU Corp
US WEST Communications
Union Heat Light & Power
Utah Power & Light
Vermont Gas Systems Inc. Schedule RA Page 8 of 20 MANAGEMENT DEVELOPMENT AND PROFESSIONAL EXECUTIVE EDUCATION
- Canadian Institute of Marketing, Corporate Finance, 1971-73 - Hydro-Quebec, "Capital Budgeting Under Uncertainty," 1974-75
- Institute of Certified Public Accountants, Mergers & Acquisitions, 1975-78
- Investment Dealers Association of Canada, 1977-78 - Financial Research Foundation, bi-anual seminar, 1975-79
- Advanced Management Research (AMR), faculty member, 1977-80 - Financial Analysts Federation, Educational chapter: "Financial Futures Contracts" seminar
- Exnet Inc. a.k.a. The Management Exchange Inc., faculty member, 1981-2004, National Seminars:
Risk and Return on Capital Projects Cost of Capital for Regulated Utilities Capital Allocation for Utilities Alternative Regulatory Frameworks Utilty Directors' Workshop Shareholder Value Creation for Utilities Real Options in Utility Capital Investments Fundamentals of Utility Finance in a Restructured Environment Contemporary Issues in Utilty Finance
- Georgia State University College of Business, Management Development Program, faculty member, 1981-1994
EXPERT TESTIMONY & UTILITY CONSULTING ARAS OF EXPERTISE
Rate of Return Capital Structure
Generic Cost of Capital
Costing Methodology Depreciation
Flow- Through vs Normalization
Revenue Requirements Methodology Schedule RA Page 9 of 20
Utility Capital Expenditures Analysis
Risk Analysis
Capital Allocation Divisional Cost of Capital, Unbundling
Incentive Regulation & Alternative Regulatory Plans
Shareholder Value Creation
Value-Based Management
REGULATORY BODIES
Federal Communications Commission
Federal Energy Regulatory Commission
Georgia Public Service Commission
South Carolina Public Service Commission
North Carolina Utilities Commission Pennsylvania Public Service Commission
Ontaro Telephone Service Commission
Quebec Telephone Service Commission
Newfoundland Board of Commissioners of Public Utilities Georgia Senate Committee on Regulated Industres Alberta Public Service Board
Tennessee Regulatory Authority
Oklahoma State Board of Equalization
Mississippi Public Service Commission
Minnesota Public Utilities Commission
Canadian Radio-Television & Telecommunications Comm.
New Brunswick Board of Public Commissioners Alaska Public Utility Commission Schedule RAM Page 10 of20
National Energy Board of Canada
Florida Public Service Commission
Montana Public Service Commission Arzona Corporation Commission
Quebec Natural Gas Board
Quebec Regie de 1 , Energie New York Public Service Commission
Washington Utilities & Transportation Commission
Manitoba Board of Public Utilities
New Jersey Board of Public Utilities Alabama Public Service Commission
Utah Public Service Commission
Nevada Public Service Commission
Louisiana Public Service Commission
Colorado Public Utilities Board West Virginia Public Service Commission
Ohio Public Utilities Commission
California Public Service Commission Hawaii Public Service Commission Ilinois Commerce Commission
British Columbia Board of Public Utilities
Indiana Utility Regulatory Commission
Minnesota Public Utilities Commission
Texas Public Utility Commission
Michigan Public Service Commission
Iowa Board of Public Utilities Missouri Public Service Commission Schedule RA Page 11 of20 Arkansas Public Service Commission
SERVICE AS EXPERT WITNESS
Southern Bell, So. Carolina PSC, Docket #81-201C
Southern Bell, So. Carolina PSC, Docket #82-294C
Southern Bell, North Carolina PSC, Docket #P-55-816 Metropolitan Edison, Pennsylvania PUC, Docket #R-822249
Pennsylvania Electric, Pennsylvania PUC,Docket#R-822250
Georgia Power, Georgia PSC, Docket # 3270-U, 1981
Georgia Power, Georgia PSC, Docket # 3397-U, 1983
Georgia Power, Georgia PSC, Docket # 3673-U, 1987
Georgia Power, F.E.R.C., Docket # ER 80-326, 80-327 Georgia Power, F.E.R.C., Docket # ER 81-730,80-731
Georgia Power, F.E.R.C., Docket # ER 85-730, 85-731
Bell Canada, CRTC 1987 Northern Telephone, Ontaro PSC
GTE-Quebec Telephone, Quebec PSC, Docket 84-052B
NewteL., Nfld. Brd of Public Commission PU 11-87
CN-CP Telecommunications, CRTC
Quebec Northern Telephone, Quebec PSC Edmonton Power Company, Alberta Public Service Board
Kansas Power & Light, F.E.R.C., Docket # ER 83-418 NYX, FCC generic cost of capital Docket #84-800 Bell South, FCC generic cost of capital Docket #84-800
American Water Works - Tennessee, Docket #7226
Burlington-Northern - Oklahoma State Board of Taxes Georgia Power, Georgia PSC, Docket # 3549-U Schedule RA Page 12 of20
GTE Service Corp., FCC Docket #84-200 Mississippi Power Co., Miss. PSC, Docket U-4761 Citizens Utilities, Arz. Corp. Comm., D # U2334-86020
Quebec Telephone, Quebec PSC, 1986, 1987, 1992 Newfoundland L & P, Nfld. Brd. Publ Comm. 1987, 1991
Northwestern Bell, Minnesota PSC, #P-4211CI-86-354
GTE Service Corp., FCC Docket #87-463
Anchorage Municipal Power & Light, Alaska PUC, 1988 New Brunswick Telephone, N.R PUC, 1988
Trans-Quebec Maritime, Natl Energy Brd. of Cd a, '88-92
Gulf Power Co., Florida PSC, Docket #88-1167-EI
Mountain States Bell, Montana PSC, #88-1.2 Mountain States Bell, Arzona CC, #E-1051-88-146
Georgia Power, Georgia PSC, Docket # 3840-U, 1989
Rochester Telephone, New York PSC, Docket # 89-C-022
Noverco - Gaz Metro, Quebec Natural Gas PSC, #R-3164-89
GTE Northwest, Washington UTC, #U-89-3031
Orange & Rockland, New York PSC, Case 89-E-175 Central Ilinois Light Company, ICC, Case 90-0127
Peoples Natural Gas, Pennsylvania PSC, Case
Gulf Power, Florida PSC, Case # 891345-EI ICG Utilities, Manitoba BPU, Case 1989
New Tel Enterprises, CRTC, Docket #90-15 Peoples Gas Systems, Florida PSC
Jersey Central Pwr & Light, N.J. PUB, Case ER 89110912J
Alabama Gas Co., Alabama PSC, Case 890001
Trans-Quebec Martime Pipeline, Coo. Nat'l Energy Board Schedule RA Page 13 of 20
Mountain Bell, Utah PSC,
Mountain Bell, Colorado PUB
South Central Bell, Louisiana PS Hope Gas, West Virginia PSC
Vermont Gas Systems, Vermont PSC
Alberta Power Ltd., Alberta PUB
Ohio Utilities Company, Ohio PSC
Georgia Power Company, Georgia PSC
Sun City Water Company
Havasu Water Inc.
Centra Gas (Manitoba) Co.
Central Telephone Co. Nevada AGT Ltd., CRTC 1992
BC GAS, BCPUB 1992
California Water Association, California PUC 1992
Martime Telephone 1993
BCE Enterprises, Bell Canada, 1993
Citizens Utilities Arzona gas division 1993
PSI Resources 1993-5
CILCORP gas division 1994
GTE Northwest Oregon 1993
Stentor Group 1994-5
Bell Canada 1994-1995
PSI Energy 1993, 1994, 1995, 1999
Cincinnati Gas & Electric 1994, 1996, 1999,2004 Southern States Utilities, 1995 CILCO 1995, 1999,2001 Schedule RA Page 14 of20
Commonwealth Telephone 1996
Edison International 1996, 1998
Citizens Utilities 1997
Stentor Companies 1997
Hydro-Quebec 1998
Entergy Gulf States Louisiana 1998, 1999,2001,2002,2003 Detroit Edison, 1999,2003
Entergy Gulf States, Texas, 2000, 2004
Hydro Quebec TransEnergie, 2001,2004
Sierra Pacific Company, 2000, 2001, 2002
Nevada Power Company, 2001
Mid American Energy, 2001, 2002
Entergy Louisiana Inc. 2001, 2002, 2004
Mississippi Power Company, 2001, 2002
Oklahoma Gas & Electric Company, 2002 -2003 Public Service Electric & Gas, 2001, 2002
NU Corp (Elizabethtown Gas Company), 2002
Jersey Central Power & Light, 2002
San Diego Gas & Electric, 2002
NB Power, 2002
Entergy New Orleans, 2002
Hydro-Quebec Distribution 2002
PSI Energy 2003
Fortis - Newfoundland Power & Light 2002
Emera - Nova Scotia Power 2004
Hydro-Quebec TransEnergie 2004 Hawaiian Electric 2004 Schedule RAM Page 15 of20
Missouri Gas Energy 2004
AGL Resources 2004
Arkansas Western Gas 2004
PROFESSIONAL AND LEARED SOCIETIES
- Engineering Institute of Canada, 1967-1972 - Canada Council Award, recipient 1971 and 1972
- Canadian Association Administrative Sciences, 1973-80
- American Association of Decision Sciences, 1974-1978 - American Finance Association, 1975-2002
- Financial Management Association, 1978-2002
ACTIVITIES IN PROFESSIONAL ASSOCIATIONS AND MEETINGS
- Chairman of meeting on "New Developments in Utility Cost of Capital", Southern Finance Association, Atlanta, Nov. 1982
- Chairman of meeting on "Public Utility Rate of Retur", Southeastern Public Utility Conference, Atlanta, Oct. 1982
- Chairman of meeting on "Current Issues in Regulatory Finance", Financial Management Association, Atlanta, Oct. 1983
- Chairman of meeting on "Utility Cost of Capital", Financial Management Association, Toronto, Canada, Oct. 1984.
- Committee on New Product Development, FMA, 1985
- Discussant, "Tobin's Q Ratio", paper presented at Financial Management Association, New York, N.Y., Oct. 1986 Schedule RA Page 16 of20 - Guest speaker, "Utility Capital Structure: New Developments", National Society of Rate of Return Analysts 18th Financial Foru, Wash., D.C. Oct. 1986
- Opening address, "Capital Expenditures Analysis: Methodology vs Mythology," Bellcore Economic Analysis Conference, Naples Fla., 1988.
PAPERS PRESENTED:
"An Empirical Study of Multi-Period Asset Pricing," anual meeting of Financial Management Assoc., Las Vegas Nevada, 1987.
"Utility Capital Expenditures Analysis: Net Present Value vs Revenue Requirements", anual meeting of Financial Management Assoc., Denver, Colorado, October 1985.
"Intervention Analysis and the Dynamics of Market Effciency", anual meeting of Financial Management Assoc., San Francisco, Oct. 1982
"Intertemporal Market-Line Theory: An Empirical Study," annual meeting of Eastern Finance Assoc., Newport, R.i. 1981
"Option Writing for Financial Institutions: A Cost-Benefit Analysis", 1979 annual meeting Financial Research Foundation "Free-lunch on the Toronto Stock Exchange", anual meeting of Financial Research Foundation of Canada, 1978.
"Simulation System Computer Software SIMFIN", HP International Business Computer Users Group, London, 1975.
"Inflation Accounting: Implications for Financial Analysis." Institute of Certified Public Accountants Symposium, 1979.
OFFICES IN PROFESSIONAL ASSOCIATIONS
- President, International Hewlett-Packard Business Computers Users Group, 1977
- Chairman Program Committee, International HP Business Computers Users Group, London, England, 1975 Schedule RA Page 17 of20 - Program Coordinator, Canadian Assoc. of Administrative Sciences, 1976
- Member, New Product Development Committee, Financial Management Association, 1985-1986
- Reviewer: Journal of Financial Research Financial Management
Financial Review
Journal of Finance
PUBLICATIONS
"Risk Aversion Revisited", Journal of Finance, Sept. 1983
"Hedging Regulatory Lag with Financial Futures," Journal of Finance, May 1983. (with G. Gay, R. Kolb)
"The Effect ofCWIP on Cost of Capital," Public Utilities Fortnightly, July 1986.
"The Effect of CWIP on Revenue Requirements" Public Utilities Fortnightly, August 1986.
"Intervention Analysis and the Dynamics of Market Efficiency," Time-Series Applications, New York: North Holland, 1983. (with K. El-Sheshai)
"Market-Line Theory and the Canadian Equity Market," Journal of Business Administration, Jan. 1982, M. Brennan, editor
"Efficiency of Canadian Equity Markets," International Management Review, Feb. 1978.
"Intertemporal Market-Line Theory: An Empirical Test," Financial Review, Proceedings of the Eastern Finance Association, 1981. Schedule RA Page 18 of20 BOOKS
Utilities' Cost of Capital, Public Utilities Reports Inc., Arlington, Va., 1984.
Regulatory Finance, Public Utilities Reports Inc., Arlington, Va., 1994.
Driving Shareholder Value, McGraw-Hil, Januar 2001.
The New Regulatory Finance, forthcoming 2005.
MONOGRAPHS
Determining Cost of Capital for Regulated Industries, Public Utilities Reports, Inc., and The Management Exchange Inc., 1982 - 1993. (with V.L. Andrews)
Alternative Regulatory Frameworks, Public Utilities Reports, Inc., and The Management Exchange Inc., 1993. (with V.L. Andrews)
Risk and Return in Capital Projects, The Management Exchange Inc., 1980. (with B. Deschamps)
Utility Capital Expenditure Analysis, The Management Exchange Inc., 1983.
Regulation of Cable Television: An Econometric Planng Model, Quebec Department of Communications, 1978.
"An Economic & Financial Profie ofthe Canadian Cablevision Industry," Canadian Radio-Television & Telecommunication Commission (CRTC), 1978.
Computer Users' Manual: Finance and Investment Programs, University of Montreal Press, 1974, revised 1978.
Fiber Optics Communications: Economic Characteristics, Quebec Department of Communications, 1978.
"Canadian Equity Market Inefficiencies", Capital Market Research Memorandum, Garaise & Thamson Investment Consultants, 1979. Schedule RA Page 19 of20 MISCELLANEOUS CONSULTING REPORTS
"Operational Risk Analysis: California Water Utilities," Calif. Water Association, 1993.
"Cost of Capital Methodologies for Independent Telephone Systems", Ontaro Telephone Service Commission, March 1989.
"The Effect ofCWIP on Cost of Capital and Revenue Requirements", Georgia Power Company, 1985.
"Costing Methodology and the Effect of Alternate Depreciation and Costing Methods on Revenue Requirements and Utility Finances", Gaz Metropolitan Inc., 1985.
"Simulated Capital Structure ofCN-CP Telecommunications: A Critique", CRTC, 1977.
"Telecommunications Cost Inquiry: Critique",CRTC,1977.
"Social Rate of Discount in the Public Sector", CRTC Policy Statement, 1974.
"Technical Problems in Capital Projects Analysis", CRTC Policy Statement, 1974.
RESEARCH GRANTS
"Econometric Planning Model of the Cablevision Industry", International Institute of Quantitative Economics, CRTC.
"Application of the Averch-Johnson Model to Telecommunications Utilities", Canadian Radio- Television Commission. (CR TC)
"Economics of the Fiber Optics Industry", Quebec Dept. of Communications.
"Intervention Analysis and the Dynamics of Market Efficiency", Georgia State Univ. College of Business, 1981.
"Firm Size and Beta Stability", Georgia State University College of Business, 1982.
"Risk Aversion and the Demand for Risky Assets", Georgia State University College of Business, 1981. Schedule RA Page 20 of 20
Chase Econometrics, Interactive Data Corp., Research Grant, $50,000 per anum, 1986- 1989.
UNIVERSITY SERVICE - University Senate, elected departmental senator 1987-1989, 1998-2002
- Faculty Affairs Committee, elected departmental representative
- Professional Continuing Education Committee member
- Director Master in Science (Finance) Program
- Course Coordinator, Corporate Finance, MBA program - Chairman, Corporate Finance Curculum Committee
- Executive Education: Departmental Coordinator 2000 Schedule RAM-2 Pg 1
NATURAL GAS DISTRIBUTION UTILITIES BETA ESTIMATES
Company Industry Beta
1 AGL Resources A TG GASDISTR 0.95 2 AmeriGas Partners APU GASDISTR 0.60 3 Atmos Energy ATO GASDISTR 0.75 4 KeySpan Corp. KSE GASDISTR 0.90 5 Laclede Group LG GASDISTR 0.85 6 New Jersey Resources NJR GASDISTR 0.80 7 NICOR Inc. GAS GASDISTR 1.20 8 Northwest Nat. Gas NWN GASDISTR 0.75 9 Peoples Energy PGL GASDISTR 0.90 10 Piedmont Natural Gas PNY GASDISTR 0.85 11 South Jersey Inds. SJI GASDISTR 0.70 12 Southern Union SUG GASDISTR 1.05 13 Southwest Gas SWX GASDISTR 0.85 14 UGI Corp. UGI GASDISTR 0.90 15 WGL Holdings Inc. WGL GASDISTR 0.80
AVERAGE 0.86
Source: Value Line Investment Analyzer 8/2006 Schedule RAM-2 Pg 2
COMBINATION GAS & ELECTRIC UTILITIES BETA ESTIMATES
Company Name Industry Beta
1 Alliant Energy UTILCENT 0.90 2 Ameren Corp. UTILCENT 0.75
3 CH Energy Group UTI LEAST 0.85 4 Canso!. Edison UTILEAST 0.70 5 OTE Energy UTILCENT 0.75
6 Energy East Corp. UTI LEAST 0.90 7 Entergy Corp. UTILCENT 0.85 8 Exelon Corp. UTILEAST 0.85 9 MGE Energy UTILCENT 0.70
10 Northeast Utilities UTI LEAST 0.85
11 NSTAR UTI LEAST 0.80
12 Pepco Holdings UTI LEAST 0.90 13 PG&E Corp. UTILWEST 1.15 14 PNM Resources UTILWEST 1.00
15 PPL Corp. UTI LEAST 1.05
16 Public Servo Enterprise UTI LEAST 0.95 17 Puget Energy Inc. UTILWEST 0.80
18 TECO Energy UTI LEAST 1.05 19 UniSource Energy UTILWEST 0.75 20 Wisconsin Energy UTILCENT 0.80 21 Xcel Energy Inc. UTILWEST 0.90
AVERAGE 0.87
Source: VLlA 08/2006 Schedule RAM-3 Pg 1
MOODY'S ELECTRIC UTILITY COMMON STOCKS OVER LONG-TERM TREASURY BONDS ANNUAL LONG-TERM RISK PREMIUM ANALYSIS
Moody's Long-Term 20 year Electric Governmen Maturity Bond Utilty Capital Stock Equity Bond Bond Total Stock Gain/(Loss) Total Risk Year Yieid Value Gain/Loss Interest Return index Dividend % Growth Yield Return Premium -1 -2 -3 -4 -5 -6 -7 -8 -9 -10 -11
1931 4.07% 1,000.00 43.23 1932 3.15% 1,135.75 135.75 40.70 17.64% 39.42 2.22 -8.81% 5.14% -3.68% -21.32% 1933 3.36% 969.60 -30.40 31.50 0.11% 28.73 1.75 -27.12% 4.44% -22.68% -22.79% 1934 2.93% 1,064.73 64.73 33.60 9.83% 21.06 1.42 -26.70% 4.94% -21.75% -31.59% 1935 2.76% 1,025.99 25.99 29.30 5.53% 36.06 1.33 71.23% 6.32% 77.54% 72.01% 1936 2.55% 1,032.74 32.74 27.60 6.03% 41.60 1.78 15.36% 4.94% 20.30% 14.27% 1937 2.73% 972.40 -27.60 25.50 -0.21% 24.24 1.68 -41.73% 4.04% -37.69% -37.48% 1938 2.52% 1,032.83 32.83 27.30 6.01% 27.55 1.45 13.66% 5.98% 19.64% 13.62% 1939 2.26% 1,041.65 41.65 25.20 6.68% 28.85 1.51 4.72% 5.48% 10.20% 3.51% 1940 1.94% 1,052.84 52.84 22.60 7.54% 22.22 1.57 -22.98% 5.44% -17.54% -25.08% 1941 2.04% 983.64 -16.36 19.40 0.30% 13.45 1.27 -39.47% 5.72% -33.75% -34.06% 1942 2.46% 933.97 -66.03 20.40 -4.56% 14.29 1.28 6.25% 9.52% 15.76% 20.33% 1943 2.48% 996.86 -3.14 24.60 2.15% 21.01 1.46 47.03% 10.22% 57.24% 55.10% 1944 2.46% 1,003.14 3.14 24.80 2.79% 21.09 1.35 0.38% 6.43% 6.81% 4.01% 1945 1.99% 1,07723 77.23 24.60 10.18% 31.14 1.37 47.65% 6.50% 54.15% 43.97% 1946 2.12% 978.90 -21.10 19.90 -0.12% 32.71 1.48 5.04% 4.75% 9.79% 9.91% 1947 2.43% 951.13 -48.87 21.20 -2.77% 25.60 1.58 -21.74% 4.83% -16.91% -14.14% 1948 2.37% 1,009.51 9.51 24.30 3.38% 26.20 1.63 2.34% 6.37% 8.71% 5.33% 1949 2.09% 1,045.58 45.58 23.70 6.93% 30.57 1.68 16.68% 6.41% 23.09% 16.16% 1950 2.24% 975.93 -24.07 20.90 -0.32% 30.81 1.85 0.79% 6.05% 6.84% 7.15% 1951 2.69% 930.75 -69.25 22.40 -4.69% 33.85 1.90 9.87% 6.17% 16.03% 20.72% 1952 2.79% 984.75 -15.25 26.90 1.17% 37.85 1.92 11.82% 5.67% 17.49% 16.32% 1953 2.74% 1,007.66 7.66 27.90 3.56% 39.61 2.09 4.65% 5.52% 10.17% 6.62% 1954 2.72% 1 ,003.07 3.07 27.40 3.05% 47.56 2.14 20.07% 5.40% 25.47% 22.43% 1955 2.95% 965.44 -34.56 27.20 -0.74% 49.35 2.27 3.76% 4.77% 8.54% 9.27% 1956 3.45% 928.19 -71.81 29.50 -4.23% 48.96 2.37 -0.79% 4.80% 4.01% 8.24% 1957 3.23% 1,032.23 32.23 34.50 6.67% 50.30 2.46 2.74% 5.02% 7.76% 1.09% 1958 3.82% 918.01 -81.99 32.30 -4.97% 66.37 2.57 31.95% 5.11% 37.06% 42.03% 1959 4.47% 914.65 -85.35 38.20 -4.71% 65.77 2.64 -0.90% 3.98% 3.07% 7.79% 1960 3.80% 1,093.27 93.27 44.70 13.80% 76.82 2.74 16.80% 4.17% 20.97% 7.17% 1961 4.15% 952.75 -47.25 38.00 -0.92% 99.32 2.86 29.29% 3.72% 33.01% 33.94% 1962 3.95% 1,027.48 27.48 41.50 6.90% 96.49 3.07 -2.85% 3.09% 0.24% -6.66% 1963 4.17% 970.35 -29.65 39.50 0.99% 102.31 3.33 6.03% 3.45% 9.48% 8.50% 1964 4.23% 991.96 -8.04 41.70 3.37% 115.54 3.68 12.93% 3.60% 16.53% 13.16% 1965 4.50% 964.64 -35.36 42.30 0.69% 114.86 4.02 -0.59% 3.48% 2.89% 2.20% 1966 4.55% 993.48 -6.52 45.00 3.85% 105.99 4.18 -7.72% 3.64% -4.08% -7.93% 1967 5.56% 879.01 -120.99 45.50 -7.55% 98.19 4.44 -7.36% 4.19% -3.17% 4.38% 1968 5.98% 951.38 -48.62 55.60 0.70% 104.04 4.58 5.96% 4.66% 10.62% 9.92% 1969 6.87% 904.00 -96.00 59.80 -3.62% 84.62 4.63 -18.67% 4.45% -14.22% -10.60% 1970 6.48% 1,043.38 43.38 68.70 11.21% 88.59 4.73 4.69% 5.59% 10.28% -0.93% 1971 5.97% 1,059.09 59.09 64.80 12.39% 85.56 4.81 -3.42% 5.43% 2.01% -10.38% 1972 5.99% 997.69 -2.31 59.70 5.74% 83.61 4.92 -2.28% 5.75% 3.47% -2.27% 1973 7.26% 867.09 -132.91 59.90 -7.30% 60.87 5.04 -27.20% 6.03% -21.17% -13.87% 1974 7.60% 965.33 -34.67 72.60 3.79% 41.17 4.83 -32.36% 7.93% -24.43% -28.22% 1975 8.05% 955.63 -44.37 76.00 3.16% 55.66 4.99 35.20% 12.12% 47.32% 44.15% 1976 7.21% 1,088.25 88.25 80.50 16.87% 66.29 5.25 19.10% 9.43% 28.53% 11.66% 1977 8.03% 919.03 -80.97 72.10 -0.89% 68.19 5.68 2.87% 8.57% 11.43% 12.32% 1978 8.98% 912.4 7 -87.53 80.30 -0.72% 59.75 5.98 -12.38% 8.77% -3.61% -2.88% 1979 10.12% 902.99 -97.01 89.80 -0.72% 56.41 6.34 -5.59% 10.61% 5.02% 5.74% 1980 11.99% 859.23 -140.77 101.20 -3.96% 54.42 6.67 -3.53% 11.82% 8.30% 12.25% Schedule RAM-3 Pg 2
MOODY'S ELECTRIC UTILITY COMMON STOCKS OVER LONG-TERM TREASURY BONDS ANNUAL LONG-TERM RISK PREMIUM ANALYSIS
Moody's Long-Term 20 yea r Electric Govemmen Maturity Bond Utility Capital Stock Equity Bond Bond Total Stock Gain/(Loss) Total Risk Year Yield Value Gain/Loss Interest Return Index Dividend % Growth Yield Return Premium -1 -2 -3 -4 -5 -6 -7 -8 -9 -10 -11
1981 13.34% 906.45 -93.55 119.90 2.63% 57.20 7.16 5.11% 13.16% 18.27% 15.63% 1982 10.95% 1,192.38 192.38 133.40 32.58% 70.26 7.64 22.83% 13.36% 36.19% 3.61% 1983 11.97% 923.12 -76.88 109.50 3.26% 72.03 8.00 2.52% 11.39% 13.91% 10.64% 1984 11.70% 1,020.70 20.70 119.70 14.04% 80.16 8.37 11.29% 11.62% 22.91% 8.87% 1985 9.56% 1,189.27 189.27 117.00 30.63% 94.98 8.71 18.49% 10.87% 29.35% -1.27% 1986 7.89% 1,166.63 166.63 95.60 26.22% 113.66 8.97 19.67% 9.44% 29.11% 2.89% 1987 9.20% 881.17 -118.83 78.90 -3.99% 94.24 9.12 -17.09% 8.02% -9.06% -5.07% 1988 9.18% 1,001.82 1.82 92.00 9.38% 100.94 8.71 7.11% 9.24% 16.35% 6.97% 1989 8.16% 1,099.75 99.75 91.80 19.16% 122.52 8.85 21.38% 8.77% 30.15% 10.99% 1990 8.44% 973.17 -26.83 81.60 5.48% 117.77 8.76 -3.88% 7.15% 3.27% -2.20% 1991 7.30% 1,118.94 118.94 84.40 20.33% 144.02 9.02 22.29% 7.66% 29.95% 9.61% 1992 7.26% 1,004.19 4.19 73.00 7.72% 141.06 8.82 -2.06% 6.12% 4.07% -3.65% 1993 6.54% 1,079.70 79.70 72.60 15.23% 146.70 9.04 4.00% 6.41% 10.41% -4.82% 1994 7.99% 856.40 -143.60 65.40 -7.82% 115.50 9.01 -21.27% 6.14% -15.13% -7.31% 1995 6.03% 1,225.98 225.98 79.90 30.59% 142.90 9.06 23.72% 7.84% 31.57% 0.98% 1996 6.73% 923.67 -76.33 60.30 -1.60% 136.00 9.06 -4.83% 6.34% 1.51% 3.11% 1997 6.02% 1,081.92 81.92 67.30 14.92% 155.73 9.06 14.51% 6.66% 21.17% 6.25% 1998 5.42% 1,072.71 72.71 60.20 13.29% 181.44 8.01 16.51% 5.14% 21.65% 8.36% 1999 6.82% 848.41 -151.59 54.20 -9.74% 137.30 8.71 -24.33% 4.80% -19.53% -9.79% 2000 5.58% 1,148.30 148.30 68.20 21.65% 227.09 8.71 65.40% 6.34% 71.74% 50.09% 2001 5.75% 979.95 -20.05 55.80 3.57% 214.08 8.56 -5.73% 3.77% -1.96% -5.54%
Mean 5.62%
Source: Mergents (Moody's) Public Utility Manual 2002 December stock prices and dividends Dec. Bond yields from Ibbotson Associates 2002 Yearbook Table B-9 Long-Term Government Bonds Yields
December stock price, dividends from Moody's Public Utilty Manual Schedule RAM-4 Pg 1
NATURAL GAS UTILITIES DCF ANAL YSIS: ANAL YSTS' GROWTH FORECASTS
Company Ticker Industry % Current Analysts Expected Cost of ROE Symbol Divid Growth Divid Equity Yield Forecast Yield (1 ) (2) (3) (4) (5) (6) (7)
1 AGL Resources ATG GASDISTR 4.1 4.4 4.2 8.6 8.9 2 Atmos Energy ATO GASDISTR 4.5 5.5 4.8 10.3 10.5 3 Laclede Group LG GASDISTR 4.4 6.0 4.7 10.7 10.9 4 New Jersey Resource NJR GASDISTR 3.0 6.0 3.2 9.2 9.4 5 NICOR Inc. GAS GASDISTR 4.4 2.5 4.5 7.0 7.2 6 Northwest Nat. Gas NWN GASDISTR 3.7 4.7 3.9 8.6 8.8 7 Peoples Energy PGL GASDISTR 5.3 4.0 5.5 9.5 9.8 8 Piedmont Natural Ga~ PNY GASDISTR 3.8 5.7 4.0 9.7 9.9 9 South Jersey Inds. SJI GASDISTR 3.2 5.7 3.4 9.1 9.3 10 Southern Union SUG GASDISTR 1.5 7.7 1.6 9.3 9.3 11 Southwest Gas SWX GASDISTR 2.5 6.0 2.7 8.7 8.8 12 UGI Corp. UGI GASDISTR 2.9 7.3 3.1 10.4 10.6 13 WGL Holdings Inc. WGL GASDISTR 4.6 4.0 4.8 8.8 9.0
AVERAGE 3.7 5.3 3.9 9.2 9.4
Notes: Column 1, 2, 3: Value Line Investment Analyzer, 8/2006 Column 4: Zacks long-term earnings growth forecast, 8/2006 Column 5 = Column 3 times (1 + Column 4/100) Column 6 = Column 5 + Column 4 Column 7 = (Column 5/0.95) + Column 4 Schedule RAM-5 Pg 1
NATURAL GAS UTILITIES DCF ANALYSIS: VALUE LINE GROWTH FORECASTS
Company Ticker Industry % Current Value Line Expected Cost of ROE Symbol Divid Proj Divid Equity Yield Growth Yield (1) (2) (3) (4) (5) (6) (7)
1 AGL Resources ATG GASDISTR 4.1 4.0 4.2 8.2 8.4 2 Atmos Energy ATO GASDISTR 4.5 7.0 4.8 11.8 12.1 3 Laclede Group LG GASDISTR 4.4 6.0 4.7 10.7 10.9 4 New Jersey Resource~ NJR GASDISTR 3.0 4.5 3.2 7.7 7.8 5 NICOR Inc. GAS GASDISTR 4.4 4.0 4.6 8.6 8.8 6 Northwest Nat. Gas NWN GASDISTR 3.7 7.0 4.0 11.0 11.2 7 Peoples Energy PGL GASDISTR 5.3 1.5 5.3 6.8 7.1 8 Piedmont Natural Gas PNY GASDISTR 3.8 6.0 4.0 10.0 10.3 9 South Jersey Inds. SJI GASDISTR 3.2 7.0 3.4 10.4 10.6 10 Southern Union SUG GASDISTR 1.5 10.5 1.6 12.1 12.2 11 Southwest Gas SWX GASDISTR 2.5 9.5 2.7 12.2 12.4 12 UGI Corp. UGI GASDISTR 2.9 5.5 3.0 8.5 8.7 13 WGL Holdings Inc. WGL GASDISTR 4.6 2.0 4.7 6.7 6.9
AVERAGE 3.7 5.7 3.9 9.6 9.8
Notes: Column 1, 2, 3,4: Value Line Investment Analyzer, 8/2006 Column 5 = Column 3 times (1 + Column 4/100) Column 6 = Column 5 + Column 4 Schedule RAM-6 Pg 1
INVESTMENT-GRADE COMBINATION GAS & ELECTRIC UTILITIES DCF ANALYSIS: VALUE LINE GROWTH PROJECTIONS
Company % Current Proj EPS Divid Growth Yield (1 ) (2)
1 Allant Energy 3.3 4.5 2 Ameren Corp. 5.1 1.5 3 CH Energy Group 4.4 3.0 4 Con so!. Edison 5.0 3.0 5 DTE Energy 5.0 4.5 6 Energy East Corp. 4.9 4.0 7 Entergy Corp. 2.8 5.0 8 Exelon Corp. 3.0 7.0 9 MGE Energy 4.4 6.5 10 Northeast Utilities 3.3 9.0 11 NSTAR 3.9 6.0 12 Pepco Holdings 4.3 7.5 13 PG&E Corp. 3.4 5.5 14 PNM Resources 3.2 5.5 15 PPL 3.3 9.5 16 17 Puget Ener 4.4 18 19 UniSource Energy 2.6 7.0 20 Wisconsin Energy 2.3 6.5 21 Xcel Energy Inc. 4.4 6.0
AVERAGE 3.9 6.1
Notes: Column 1, 2: Value Line Investment Survey for Windows, 8/2006 Column 3 = Column 1 times (1 + Column 2/100) Column 4 = Column 3 + Column 2 Column 5 = (Column 3 /0.95) + Column 2 Schedule RAM-6 Pg 2
INVESTMENT-GRADE COMBINATION GAS & ELECTRIC UTILITIES DCF ANALYSIS: VALUE LINE GROWTH PROJECTIONS
Company % Current Proj EPS % Expected Cost of ROE Divid Growth Divid Equity Yield Yield (1 ) (2) (3) (4) (5)
1 Allant Energy 3.3 4.5 3.4 7.9 8.1 2 Ameren Corp. 5.1 1.5 5.1 6.6 6.9 3 CH Energy Group 4.4 3.0 4.6 7.6 7.8 4 Conso!. Edison 5.0 3.0 5.2 8.2 8.4 5 DTE Energy 5.0 4.5 5.2 9.7 9.9 6 Energy East Corp. 4.9 4.0 5.1 9.1 9.3 7 Entergy Corp. 2.8 5.0 2.9 7.9 8.1 8 Exelon Corp. 3.0 7.0 3.2 10.2 10.4 9 MGE Energy 4.4 6.5 4.7 11.2 11.5 10 Northeast Utilities 3.3 9.0 3.6 12.6 12.8 11 NSTAR 3.9 6.0 4.1 10.1 10.3 12 Pepco Holdings 4.3 7.5 4.6 12.1 12.4 13 PG&E Corp. 3.4 5.5 3.6 9.1 9.2 14 PNM Resources 3.2 5.5 3.4 8.9 9.1 15 PPL Corp. 3.3 9.5 3.6 13.1 13.2 16 Puget Energy Inc. 4.4 5.0 4.7 9.7 9.9 17 UniSource Energy 2.6 7.0 2.8 9.8 10.0 18 Wisconsin Energy 2.3 6.5 2.4 8.9 9.0 19 Xcel Energy Inc. 4.4 6.0 4.7 10.7 10.9
AVERAGE 3.8 5.6 4.0 9.6 9.9
Notes: Column 1,2: Value Line Investment Survey for Windows, 8/2006 Column 3 = Column 1 times (1 + Column 2/100) Column 4 = Column 3 + Column 2 Column 5 = (Column 3 /0.95) + Column 2 Schedule RAM-7 Pg 1
INVESTMENT-GRADE COMBINATION GAS & ELECTRIC UTILITIES DCF ANALYSIS: ANALYSTS' GROWTH FORECASTS
Company % Current Analysts' Divid Growth Yield Forecast (1 ) (2)
1 Allant Energy 3.3 4.0 2 Ameren Corp. 5.1 6.0 3 CH Energy Group 4.4 4 Conso!. Edison 5.0 3.9 5 DTE Energy 5.0 5.5 6 Energy East Corp. 4.9 4.5 7 Entergy Corp. 2.8 7.5 8 Exelon Corp. 3.0 9.2 9 MGE Energy 4.4 10 Northeast Utilities 3.3 8.7 11 NSTAR 3.9 6.0 12 Pepco Holdings 4.3 4.7 13 PG&E Corp. 3.4 7.7 14 PNM Resources 3.2 8.3 15 PPL Corp. 3.3 8.3 16 Public Servo Enterprise 3.4 9.0 17 Puget Energy Inc. 4.4 7.0 18 TECD Energy 5.0 5.7 19 UniSource Energy 2.6 20 Wisconsin Energy 2.3 7.0 21 Xcel Energy Inc. 4.4 4.6
Notes: Column 1: Value Line Investment Survey for Windows, 8/2006 Column 2: Zacks long-term earnings growth forecast, 8/2006
No growth forecast available for CH Energy, MGE Energy, UniSource Schedule RAM-7 Pg 2
INVESTMENT -GRADE COMBINATION GAS & ELECTRIC UTILITIES DCF ANAL YSIS: ANAL YSTS' GROWTH FORECASTS
Company % Current Analysts' % Expected Cost of ROE Divid Growth Divid Equity Yield Forecast Yield (1 ) (2) (3) (4) (5)
1 Alliant Energy 3.3 4.0 3.4 7.4 7.6 2 Ameren Corp. 5.1 6.0 5.4 11.4 11.6 3 Conso!. Edison 5.0 3.9 5.2 9.1 9.3 4 OTE Energy 5.0 5.5 5.2 10.7 11.0 5 Energy East Corp. 4.9 4.5 5.1 9.6 9.8 6 Entergy Corp. 2.8 7.5 3.0 10.5 10.7 7 Exelon Corp. 3.0 9.2 3.3 12.5 12.7 8 Northeast Utilities 3.3 8.7 3.6 12.3 12.5 9 NST AR 3.9 6.0 4.1 10.1 10.3 10 Pepco Holdings 4.3 4.7 4.5 9.2 9.4 11 PG&E Corp. 3.4 7.7 3.6 11.3 11.5 12 PNM Resources 3.2 8.3 3.5 11.8 11.9 13 PPL Corp. 3.3 8.3 3.5 11.8 12.0 14 Public Servo Enterpris 3.4 9.0 3.7 12.7 12.9 15 Puget Energy Inc. 4.4 7.0 4.8 11.8 12.0 16 TECO Energy 5.0 5.7 5.3 10.9 11.2 17 Wisconsin Energy 2.3 7.0 2.4 9.4 9.5 18 Xcel Energy Inc. 4.4 4.6 4.6 9.2 9.4
AVERAGE 3.9 6.5 4.1 10.6 10.9
Notes: Column 1: Value Line Investment Survey for Windows, 8/2006 Column 2: Zacks long-term earnings growth forecast, 8/2006 Column 3 = Column 1 times (1 + Column 2/100) Column 4 = Column 3 + Column 2 Column 5 = (Column 3/0.95) + Column 2
No growth forecast available for CH Energy, MGE Energy, UniSource Energy Schedule RAM-8 Pg 1
NATURAL GAS DISTRIBUTION UTILITIES COMMON EQUITY RATIOS
Company Ticker Industry % Common Equity 1 AGL Resources A TG GASDISTR 48.1 2 Atmos Energy A TO GASDISTR 42.3 4 Laclede Group LG GASDISTR 51.8 5 New Jersey Resourc NJR GASDISTR 58.0 6 NICOR Inc. GAS GASDISTR 62.5 7 Northwest Nat. Gas NWN GASDISTR 53.0 8 Peoples Energy PGL GASDISTR 47.2 9 Piedmont Natural Gc PNY GASDISTR 58.6 10 South Jersey Inds. SJI GASDISTR 55.1 11 Southern Union SUG GASDISTR 41.6 12 Southwest Gas SWX GASDISTR 36.2 13 UGI Corp. UGI GASDISTR 41.7 14 WGL Holdings Inc. WGL GASDISTR 58.6 AVERAGE 49.7
Source: Value Line Investment Analyzer 8/2006. Schedule RAM-9 Pg 1
Delmarva Power and Light Company Overall Rate of Return - Delaware
Proforma June 30, 2006 Capital Overall Structure Cost Rate of Type of Capital Ratios Rate Return
Long-Term Debt 53.10% 5.49% 2.92% Preferred Stock 0.00% 0.00% 0.00% Common Equity 46.90% 11.00% 5.16% Total 100.00% 8.08% Schedule f'".,¿9 Pg 2
Delmarva Power & Light Capitalization and Capital Structure Ratios Actual at March 30, 2006; Actual & Proforma at June 30, 2006
Actual at March 31. 2006 Actual at June 30. 2006 Proforma at June 30 2006
Amount Percent Amount Percent Tvpe of Capital Amount Percent Outstandino to Total Outstandino to Total Outstandino to Total (000) (000) Long-Term Debt (000) Bonds $ - $ - Tax-Exempt Debt $ $ 313,170 $ 313,170 Medium-Term Notes $ 313,170 $ 321,500 $ 321,500 Total Long-Term Debt $ 100,000 $ 421,500 $ 634,670 49.07% $ 634,670 48.75% $ 734,670 53.10%
Preferred Stock $ 18,170 1 .40% $ 18,170 1 .40% $ (18,170) $ (0) 0.00% Trust Preferred Stock $ 0.00% $ - 0.00% $ 0.00% Common Equity Common Stock and Paid In Capital $ 235,447 $ 235,447 235,447 Retained Earnings $ $ 405,202 $ 413,488 Total Common Equity $ 413,488 $ 640,649 49.53% $ 648,935 49.85% $ 648,935 46.90%
Total Capital $ 1,293,489 100.00% $ 1,301,775 100.00% $ 1,383,605 100.00%
Proforma Notes: Source of Proceeds: L T-Debt (6.25% coupon, issuance date - 11/1/06, maturity date - 11/1/16) $ 100,000 Use of Proceeds: Pref Stk (all series retired) 18,170 Working Capital $ 81,830 Total $ $ 100,000 Schedule RAM-9 Pg 3
Delmarva Power and Light Company Calculation of the Embedded Cost of Long-Term Debt Actual at March 31. 2006
Principal Percent Effective Weighted Date of Amount to Cost Cost Series Maturity Outstanding (1) Total Rate (2) Rate
Bonds:
Tax Exempt Fixed Rate Bonds: 3.15% 08/01/08 18,200,000 2.87% 3.80% 0.11% 5.50% 07/01/25 15,000,000 2.36% 5.62% 0.13% 5.65% 07/01/28 16,240,000 2.56% 5.77% 0.15% 5.20% 02/01/19 31,000,000 4.88% 5.61% 0.27% 4.90% 05/01/26 34,500,000 5.44% 5.24% 0.28% Tax Exempt Variable Rate Bonds: 3.17% 10/01/17 8,000,000 1.26% 4.10% 0.05% 3.17% 10/01/17 18,000,000 2.84% 3.96% 0.11% 3.27% 10/01/28 15,500,000 2.44% 3.93% 0.10% 3.30% 07/01/24 22,330,000 3.52% 4.15% 0.15% 3.35% 07/01/24 11,000,000 1.73% 4.13% 0.07% 3.17% 10/01/29 30,000,000 4.73% 3.95% 0.19% 3.14% 07/01/30 11,150,000 1.76% 3.71% 0.07% 3.30% 07/01/30 27,750,000 4.37% 3.89% 0.17% 3.20% 05/01/31 20,000,000 3.15% 3.85% 0.12% 3.11% 05/01/31 4,500,000 0.71% 3.83% 0.03% 3.11% 05/01/32 15,000,000 2.36% 4.01% 0.09% 3.18% 08/01/38 15,000,000 2.36% 3.96% 0.09% Medium Term Notes: 5.00% 11/15/14 100,000,000 15.76% 5.12% 0.81% 5.00% 06/01/15 100,000,000 15.76% 5.11% 0.81% 8.13% 05/01/07 50,000,000 7.88% 8.24% 0.65% 7.11% 02/01/07 1,000,000 0.16% 7.20% 0.01% 7.06% 02/01/07 500,000 0.08% 7.15% 0.01% 7.08% 02/01/07 10,000,000 1.58% 7.17% 0.11% 7.58% 02/01/17 2,000,000 0.32% 7.65% 0.02% 7.56% 02/01/17 12,000,000 1.89% 7.63% 0.14% 7.61% 12/02/19 12,000,000 1.89% 7.68% 0.15% 7.72% 02/01/27 10,000,000 1.58% 7.78% 0.12% 6.75% 10/01/06 20,000,000 3.15% 6.84% 0.22% 6.81% 01/09/18 4,000,000 0.63% 6.88% 0.04%
Total Long -Term Debt $ 634,670,000 100.00% 5.27%
Notes: (1) Includes current portion of long-term debt. (2) As calculated on page 2 of this schedule.
Source of Information: Company provided data Schedule RAM-9 Pg 3.1 Schedule RAM-9 Pg 4
Delmarva Power and Light Company Calculation of the Effective Cost of Long-Term Debt by Series - For Actuals March 31, 2006 and June 30, 2006
Principal Discount Net Date of Date of Term in Amount and Net Proceeds Effective Series Issue Maturity Years Issued Expense Proceeds Ratio Cost Rate (1)
Bonds: (2)
Tax Exempt Fixed Rate Bonds: 3.15% 08/07/03 08/01/08 5 18,200,000 1,360,653 17,669,103 97.08% 3.80% 5.50% 07/01/00 07/01/25 25 15,000,000 243,088 14,756,912 98.38% 5.62% 5.65% 07/01/00 07/01/28 28 16,240,000 264,874 15,975,126 98.37% 5.77% 5.20% 05/30/02 02/01/19 17 31,000,000 1,365,870 29,634,130 95.59% 5.61% 4.90% 05/01/01 05/01/26 25 34,500,000 1,644,693 32,855,307 95.23% 5.24% Tax Exempt Variable Rate Bonds: 3.13% 10/01/87 10/01/17 30 8,000,000 315,360 7,684,640 96.06% 3.34% 3.13% 09/02/88 10/01/17 29 18,000,000 270,107 17,729,893 98.50% 3.21% 3.15% 10/14/93 10/01/28 35 15,500,000 275,796 15,224,204 98.22% 3.24% 3.17% 07/28/99 07/01/24 25 22,330,000 669,900 21,660,100 97.00% 3.35% 3.22% 07/28/99 07/01/24 25 11,000,000 220,000 10,780,000 98.00% 3.34% 3.13% 10/12/94 10/01/29 35 30,000,000 440,787 29,559,213 98.53% 3.20% 2.90% 07/07/00 07/01/30 30 11,150,000 320,416 10,829,584 97.13% 3.05% 3.03% 07/07/00 07/01/30 30 27,750,000 798,330 26,951,670 97.12% 3.18% 3.01% 05/10/01 05/01/31 30 20,000,000 994,560 19,005.40 95.03% 3.27% 2.88% 05/10/01 05/01/31 30 4,500,000 247,072 4,252,928 94.51% 3.16% 3.04% 05/30/02 05/01/32 30 15,000,000 828,148 14,171,852 94.48% 3.33% 3.01% 08/07/03 08/01/38 35 15,000,000 1,115,443 13,884,557 92.56% 3.37% Medium Term & Unsecured Notes: 5.00% 11/19/04 11/15/14 10 100,000,000 928,224 99,071,776 99.07% 5.12% 5.00% 06/01/05 06/01/15 10 100,000,000 853,194 99,146,806 99.15% 5.11% 8.13% 04/22/92 05/01/07 15 49,698,500 475,374 49,223,126 99.04% 8.24% 7.11% 02/07/97 02/01/07 10 1,000,000 6,250 993,750 99.38% 7.20% 7.06% 02/18/97 02/01/07 10 10,500,000 65,625 10,434,375 99.38% 7.15% 7.08% 02/07/97 02/01/07 10 10,000,000 62,500 9,937,500 99.38% 7.17% 7.58% 02/10/97 02/01/17 20 2,000,000 15,000 1,985,000 99.25% 7.65% 7.56% 02/18/97 02/01/17 20 15,000,000 112,500 14,887,500 99.25% 7.63% 7.61% 02/12/97 12/02/19 23 12,000,000 90,000 11,910,000 99.25% 7.68% 7.72% 02/07/97 02/01/27 30 30,000,000 225,000 29,775,000 99.25% 7.78% 6.75% 11/19/97 10/01/06 9 20,000,000 120,000 19,880,000 99.40% 6.84% 6.81% 01/09/98 01/09/18 20 33,000,000 247,500 32,752,500 99.25% 6.88%
Notes: (1) The effective cost for each issue is the yield to maturity using as inputs the term of issue, coupon rate, and net proceeds ratio. (2) Excluding $10.501 million used for COPCO purchase.
Source of Information: Company provided data
Schedule RAM-9 Pg 5
Delmarva Power & Liaht Company Calculation of the Embedded Cost of Preferred Stock Actuals at March 31 ,2006 and June 30, 2006
Principal Percent Effective Weighted Date of Amount to Cost Cost Series Maturity Outstanding Total Rate (1 ) Rate
Preferred Stock 4.00% $ 1,980,900 10.90% 4.10% 0.45% 3.70% 3,986,600 21.94% 3.78% 0.83% 4.28% 2,846,000 15.66% 4.37% 0.68% 4.56% 1,957,100 10.77% 4.68% 0.50% 4.20% 2,540,400 13.98% 4.28% 0.60% 5.00% 4,858,800 26.74% 5.11% 1.37%
Total Preferred Stock $ 18,169,800 100.00% 4.43%
Notes: (1) As calculated on page 2 of this schedule.
Source of Information: Company provided data Schedule RAM-9 Pg 6
Delmarva Power & Liiiht ComDanv Calculation of the Effective Cost of Preferred Stock by Series - For Actuals March 31, 2006
Principal Discount Net Date of Date of Term in Amount and Net Proceeds Effective Series Issue Maturity Years Issued Expense Proceeds Ratio Cost Rate (1) Preferred Stock 4.00% 10/29/43 $2,076,833 $ 48,267 $ 2,028,566 97.68% 4.10% 3.70% 04/01/47 4,097,029 86,264 4,010,765 97.89% 3.78% 4.28% 07/01/49 2,913,593 59,785 2,853,807 97.95% 4.37% 4.56% 03/04/52 2,028,338 49,811 1,978,527 97.54% 4.68% 4.20% 12/20/55 2,586,584 47,553 2,539,031 98.16% 4.28% 5.00% 12/8/56 4,949,346 110,580 4,838,766 97.77% 5.11%
Source of Information: Company provided data Schedule RAM-9 Pg 6.1
Delmarva Power & Lii:ht Company Calculation of the Effective Cost of Preferred Stock by Series - For Actuals June 30, 2006
Principal Discount Net Date of Date of Term in Amount and Net Proceeds Effective Series Issue Maturity Years Issued Expense Proceeds Ratio Cost Rate (1)
Preferred Stock 4.00% 10/29/43 $2,076,833 $ 48,267 $ 2,028,566 97.68% 4.10% 3.70% 04/01/47 4,097,029 86,264 4,010.765 97.89% 3.78% 4.28% 07101/49 2,913,593 59,785 2,853,807 97.95% 4.37% 4.56% 03/04/52 2,028,338 49,811 1,978,527 97.54% 4.68% 4.20% 12/20/55 2,586,584 47,553 2,539,031 98.16% 4.28% 5.00% 12/18/56 4,949,346 110,580 4,838,766 97.77% 5.11%
Source of Information: Company provided data Appendix B Page 1 of9
APPENDIX B
FLOTATION COST ALLOWANCE
To obtain the final cost of equity financing from the investors' expected rate of return, it is necessary to make allowance for underpricing, which is the sum of market pressure, costs of flotation, and underwriting fees associated with new issues. Allowance for market pressure should be made because large blocks of new stock may cause significant pressure on market prices even in stable markets. Allowance must also be made for company costs of flotation (including such items as printing, legal and accounting expenses) and for underwriting fees.
1. MAGNITUDE OF FLOTATION COSTS
According to empirical studies, underwriting costs and expenses average at least 4% of gross proceeds for utility stock offerings in the U.S. (See Logue & Jarrow: "Negotiations vs. Competitive
Bidding in the Sale of Securities by Public Utilities", Financial Management, Fall 1978.) A study of 641 common stock issues by 95 electric utilities identified a flotation cost allowance of 5.0%. (See Borum & Malley: "Total Flotation Cost for Electric Company Equity Issues", Public Utilities Fortnightly, Feb. 20, 1986.)
Empirical studies suggest an allowance of 1 % for market pressure in U.S. studies. Logue and J arrow found that the absolute magnitude of the relative price decline due to market pressure was less than 1.5%. Bowyer and Yawitz examined 278 public utility stock issues and found an average market pressure of 0.72%. (See Bowyer & Yawitz, "The Effect of New Equity Issues on Utility Stock Prices", Public Utilities Fortnightly, May 22, 1980.)
Eckbo & Masulis ("Rights vs. Underwritten Stock Offerings: An Empirical Analysis", University of British Columbia, Working Paper No. 1208, Sept., 1987) found an average flotation cost of 4.175% for utility common stock offerings. Moreover, flotation costs increased progressively for Appendix B Page 2 of9
smaller size issues. They also found that the relative price decline due to market pressure in the days surrounding the announcement amounted to slightly more than 1.5%. In a classic and monumental study published in the prestigious Journal of Financial Economics by a prominent scholar, a market pressure effect of 3.14% for industrial stock issues and 0.75% for utility common stock issues was found (see Smith, C.W., "Investment Banking and the Capital Acquisition Process," Journal of Financial Economics 15, 1986). Other studies of market pressure are reported in Logue ("On the Pricing of
Unseasoned Equity Offerings, Journal of Financial and Quantitative Analysis, Jan. 1973), Pettway ("The
Effects of New Equity Sales Upon Utility Share Prices," Public Utilities Fortnightly, May 10 1984), and Reilly and Hatfield ("Investor Experience with New Stock Issues," Financial Analysts' Journal, Sept.- Oct. 1969). In the Pettway study, the market pressure effect for a sample of 368 public utility equity sales was in the range of 2% to 3%. Adding the direct and indirect effects of utility common stock issues, the indicated total flotation cost allowance is above 5.0%, corroborating the results of earlier studies.
As shown in the table below, a comprehensive empirical study by Lee, Lochhead, Ritter, and Zhao, "The Costs of Raising Capital," Journal of Financial Research, VoL. XIX, NO.1, Spring 1996, shows average direct flotation costs for equity offerings of 3.5% - 5% for stock issues between $60 and $500 milion. Allowing for market pressure costs raises the flotation cost allowance to well above 5%. Appendix B Page 3 of 9
FLOTATION COSTS: RAISING EXTERNAL CAPITAL (Percent of Total Capital Raised)
Amount Raised A verage Flotation Average Flotation in $ Millions Cost: Common Stock Cost: New Debt
$ 2 - 9. 99 13.28% 4.39% i 0 - i 9. 99 8.72 2.76 20 - 39. 99 6.93 2.42 40 - 59. 99 5.87 1.32 60 - 79. 99 5.18 2.34 80 - 99. 99 4.73 2.16 100 - 199.99 4.22 2.31 200 - 499. 99 3.47 2.19 500 and Up 3.15 1.64
Note: Flotation costs for IPOs are about 17 percent of the value of common stock issued if the amount raised is less than $10 milion and about 6 percent if more than $500 millon is raised. Flotation costs are somewhat lower for utilities than others.
Source: Lee, Inoo, Scott Lochhead, Jay Ritter, and Quanshui Zhao, "The Costs of Raising Capital," The Journal of Financial Research, Spring 1996.
Therefore, based on empirical studies, total flotation costs including market pressure amount to approximately 5% of gross proceeds. I have therefore assumed a 5% gross total flotation cost allowance in my cost of capital analyses.
2. APPLICATION OF THE FLOTATION COST ADJUSTMENT
The section below shows: 1) why it is necessary to apply an allowance of 5% to the dividend yield component of equity cost by dividing that yield by 0.95 (100% - 5%) to obtain the fair return on equity capital, and 2) why the flotation adjustment is permanently required to avoid confiscation even if Appendix B Page 4 of 9
no further stock issues are contemplated. Flotation costs are only recovered if the rate of return is applied to total equity, including retained earnings, in all future years.
Flotation costs are just as real as costs incurred to build utility plant. Fair regulatory treatment absolutely must permit the recovery of these costs. An analogy with bond issues is useful to understand the treatment of flotation costs in the case of common stocks.
In the case of a bond issue, flotation costs are not expensed but are rather amortized over the life of the bond, and the annual amortization charge is embedded in the cost of service. This is analogous to the process of depreciation, which allows the recovery of funds invested in utility plant. The recovery of bond flotation expense continues year after year, irrespective of whether the company issues new debt capital in the future, until recovery is complete. In the case of common stock that has no finite life, flotation costs are not amortized. Therefore, the recovery of flotation cost requires an upward adjustment to the allowed return on equity. Roger A. Morin, Regulatory Finance, Public Utilities Reports Inc., Arlington, Va., 1994, provides numerical illustrations that show that even if a utility does not contemplate any additional common stock issues, a flotation cost adjustment is stil permanently required. Examples there also demonstrate that the allowance applies to retained earnings as well as to the original capitaL.
From the standard DCF model, the investor's required return on equity capital is expressed as:
K = D/Po + g
If P ois regarded as the proceeds per share actually received by the company from which dividends and earnings will be generated, that is, Po equals 0 B , the book value per share, then the company's required return is:
r = D/Bo + g Denoting the percentage flotation costs 't, proceeds per share Bo are related to market0 price P as follows:
P-fP=Bo P(l - f) = B o Appendix B Page 5 of 9
Substituting the latter equation into the above expression for return on equity, we obtain:
r = D/P(1-f) + g
that is, the utility's required return adjusted for underpricing. For flotation costs of 5%, dividing the expected dividend yield by 0.95 will produce the adjusted cost of equity capitaL. For a dividend yield of
6% for example, the magnitude of the adjustment is 32 basis points: .061.95 = .0632. In deriving DCF estimates of fair return on equity, it is therefore necessary to apply a conservative after-tax allowance of 5% to the dividend yield component of equity cost.
Even if no further stock issues are contemplated, the flotation adjustment is still permanently required to keep shareholders whole. Flotation costs are only recovered ifthe rate of return is applied to total equity, including retained earnings, in all future years, even if no future financing is contemplated. This is demonstrated by the numerical example contained in pages 7-9 of this Appendix. Moreover, even if the stock price, hence the DCF estimate of equity return, fully reflected the lack of permanent allowance, the company always nets less than the market price. Only the net proceeds from an equity issue are used to add to the rate base on which the investor earns. A permanent allowance for flotation costs must be authorized in order to insure that in each year the investor earns the required return on the total amount of capital actually supplied.
The example shown on pages 7-9 shows the flotation cost adjustment process using illustrative, yet realistic, market data. The assumptions used in the computation are shown on page 7. The stock is selling in the market for $25, investors expect the firm to pay a dividend of $2.25 that will grow at a rate of 5% thereafter. The traditional DCF cost of equity is thus k = DIP + g = 2.25/25 + .05 = 14%. The firm sells one share stock, incurring a flotation cost of 5%. The traditional DCF cost of equity adjusted for flotation cost is thus ROE = D/P(1-f) + g = .09/.95 + .05 = 14.47%.
The initial book value (rate base) is the net proceeds from the stock issue, which are $23.75, that is, the market price less the 5% flotation costs. The example demonstrates that only if the company is allowed to earn 14.47% on rate base wil investors earn their cost of equity of 14%. On page 8, Column 1 shows the initial common stock account, Column 2 the cumulative retained earnings balance, starting at zero, and steadily increasing from the retention of earnings. Total equity in Column 3 is the sum of Appendix B Page 6 of9
common stock capital and retained earnings. The stock price in Column 4 is obtained from the seminal
DCF formula: D/(k - g). Earnings per share in Column 6 are simply the allowed return of 14.47% times the total common equity base. Dividends start at $2.25 and grow at 5% thereafter, which they must do if investors are to earn a 14% return. The dividend payout ratio remains constant, as per the assumption of the DCF modeL. All quantities, stock price, book value, earnings, and dividends grow at a 5% rate, as shown at the bottom of the relevant columns. Only if the company is allowed to earn 14.47% on equity do investors earn 14%. For example, if the company is allowed only 14%, the stock price drops from $26.25 to $26.13 in the second year, inflicting a loss on shareholders. This is shown on page 9. The growth rate drops from 5% to 4.53%. Thus, investors only earn 9% + 4.53% = 13.53% on their investment. It is noteworthy that the adjustment is always required each and every year, whether or not new stock issues are sold in the future, and that the allowed return on equity must be earned on total equity, including retained earnings, for investors to earn the cost of equity. Appendix B Page 7 of 9
ASSUMPTIONS:
ISSUE PRICE = $25.00 FLOTATION COST = 5.00% DIVIDEND YIELD = 9.00% GROWTH = 5.00%
EQUITY RETURN = 14.000/0 (DIP + g) ALLOWED RETURN ON EQUITY = 14.47°/Ó (D/P(1- f) + g) Appendix B Page 8 of 9
MARKT / COMMON RETAINED TOTAL STOCK BOOK STOCK EARNINGS EQUITY PRICE RATIO EPS DPS PAYOUT Yr (1) (2) (3) (4) (5) (6) (7) (8) ------1 $23.75 $0.000 $23.750 $25.000 1.0526 $3.438 $2.250 65.45% 2 $23.75 $1.188 $24.938 $26.250 1.0526 $3.609 $2.363 65.45% 3 $23.75 $2.434 $26.184 $27.563 1.0526 $3.790 $2.481 65.45% 4 $23.75 $3.744 $27.494 $28.941 1.0526 $3.979 $2.605 65.45% 5 $23.75 $5.118 $28.868 $30.388 1.0526 $4.178 $2.735 65.45% 6 $23.75 $6.562 $30.312 $31.907 1.0526 $4.387 $2.872 65.45% 7 $23.75 $8.077 $31.827 $33.502 1.0526 $4.607 $3.015 65.45% 8 $23.75 $9.669 $33.419 $35.178 1.0526 $4.837 $3.166 65.45% 9 $23.75 $11.340 $35.090 $36.936 1.0526 $5.079 $3.324 65.45% 10 $23.75 $13.094 $36.844 $38.783 1.0526 $5.333 $3.490 65.45%
5.00%1 5.00%1 I 5.00% I 5.00% I Appendix B Page 9 of 9
MARKT/ COMMON RETAINED TOT AL STOCK BOOK STOCK EARNINGS EQUITY PRICE RATIO EPS DPS PAYOUT Yr (1) (2) (3) (4) (5) (6) (7) (8) ------1 $23.75 $0.000 $23.750 $25.000 1.0526 $3.325 $2.250 67.67% 2 $23.75 $1.075 $24.825 $26.132 1.0526 $3.476 $2.352 67.67% 3 $23.75 $2.199 $25.949 $27.314 1.0526 $3.633 $2.458 67.67% 4 $23.75 $3.373 $27.123 $28.551 1.0526 $3.797 $2.570 67.67% 5 $23.75 $4.601 $28.351 $29.843 1.0526 $3.969 $2.686 67.67% 6 $23.75 $5.884 $29.634 $31.194 1.0526 $4.149 $2.807 67.67% 7 $23.75 $7.225 $30.975 $32.606 1.0526 $4.337 $2.935 67.67% 8 $23.75 $8.627 $32.377 $34.082 1.0526 $4.533 $3.067 67.67% 9 $23.75 $10.093 $33.843 $35.624 1.0526 $4.738 $3.206 67.67% 10 $23.75 $11.625 $35.375 $37.237 1.0526 $4.952 $3.351 67.67%
4.53%1 4.53%1 I 4.53%1 4.53%1 1 DELMARVA POWER & LIGHT COMPANY 2 TESTIMONY OF JOHN CHAMBERLIN, PH.D.
3 BEFORE THE DELAWARE PUBLIC SERVICE COMMISSION 4 CONCERNING AN INCREASE IN GAS BASE RATES 5 DOCKET NO. 06- 6
7 1. Q: Please state your name. by whom YOU are employed. and your business 8 address.
9 A: My name is John Chamberlin. I am employed by Quantec, LLC. My
10 address is 28 Main Street, Suite A, Reedsburg, Wisconsin, 53959.
11 2. Q: What position do you hold with Ouantec. LLC?
12 A: I hold the position of Executive Vice President.
13 3. Q: Please describe your education and business experience.
14 A: I received a Ph.D. in economics from Washington State University in
15 1976. Prior to my present position with Quantec, I have been employed as Vice
16 President for Xenergy, Inc., Vice President for Strategy and Planing at PG&E
17 Energy Services, and was Executive Vice President at the consulting firm I co-
18 founded, Barakat and Chamberlin. Earlier in my career, I was a Senior Project
19 Manager at the Electric Power Research Institute, and an Analyst at Westinghouse
20 Hanford.
21 4. Q: Are yOU familar with utilty rate rel!ulation?
22 A: Yes. I have extensive experience in all aspects of utility rate design and
23 analysis. I have performed numerous cost of service analyses, designed both
24 traditional and innovative rates, written extensively on the design of utility rates,
25 developed and implemented utility rate design workshops and short courses, and
1 1 spoken numerous times at industry conferences on utility rate issues. In addition,
2 I have testified on utility rate issues in a wide variety of state and local regulatory
3 proceedings. A biography describing my professional experience is provided in
4 Schedule JHC-1.
5 5. Q: Have YOU previously testified in rel!ulatory proceedinl!s?
6 A: Yes. I have testified in numerous state regulatory proceedings on a variety
7 of matters ranging from avoided cost, energy efficiency, rates and cost of service,
8 and industry restructuring. I have also testified before a number of civil
9 jurisdictions, municipal utility regulatory bodies, and state legislatures.
10 6. Q: What is the purpose of your testimony in this proceedinl!?
11 A: Delmarva Power & Light Company ("Delmarva" or "Company") is
12 proposing an alternative rate structure to reflect changes in the natural gas
13 distribution market. Specifically, declining natural gas use per customer may
14 precipitate frequent rate revisions in order to provide the Company an opportunity
15 to fully recover its fixed costs and ear its authorized return. I will testify that the
16 Company's proposal is reasonable, appropriate and likely to stabilize revenues
17 over time resulting in benefits to both their customers and the Company.
18 7. Q: Please summarize the Company's proposaL.
19 A: The Company is proposing a monthly adjustment to its distribution
20 charges that it calls a Bil Stabilization Adjustment (BSA). The BSA is intended
21 to adjust the Company's revenues to match the expected weather normalized
22 revenues from the Company's most recent base rate proceeding. The adjustment
23 will account for changes in usage per customer and for changes in the number of
2 1 customers. Actual revenues collected will be compared to the revenues expected
2 from the most recent base rate proceeding, adjusted for changes in the number of
3 customers, to determine the amount of under or over collection. This amount will
4 then be converted to a rate per CCF and added or subtracted from the second
5 subsequent month's billings, subject to the +/-10% adjustment cap described by
6 Mr. J anocha.
7 8. Q: Why is a new approach to rate desil!n needed?
8 A: Natural gas rates are designed to recover both fixed and variable costs.
9 Historically, however, natural gas rates have been set to recover a substantial
10 portion of the utility's costs through a volumetric charge. This was done largely to
11 encourage consumption in order to reduce the per-unit fixed costs. The separation
12 of the pipeline and distribution functions precipitated by FERC Order 636 in 1992
13 dramatically changed the industry's cost structure.
14 9. Q: Are there l!eneral principles widelv in use to aid in the desil!n of utilty rates?
15 A: Yes. In their seminal text "Principles of Public Utility Rates" the authors,
16 James C. Bonbright et aI, state:
17 In very general terms, optimal rates: should provide clear, efficient
18 effective, informative, and cost effective market signals about the present
19 and future cost of service to buyers and sellers, which requires that prices
20 track costs.
3 1 10. Q: How does this principle apply to a natural l!as distribution utilty?
2 A: For a distrbution company the majority of the costs are fixed in the short
3 term. These costs include the recovery of the physical plant investments and
4 operating and maintenance costs. Costs associated with the natural gas itself are
5 passed through to the customer based on the actual costs incurred by the
6 distribution company. Traditional ratemaking includes both fixed and volumetric
7 rates. The monthly customer charge is intended to reflect that there are fixed costs
8 associated with simply having a customer on the system -- metering and customer
9 accounting are examples. Many of the core distribution costs (from the customer
10 to the city gate) are also fixed, and do not vary with volume - at least in the short
11 term. However, this customer charge is not typically set at a level to recover all
12 of the fixed costs. Consequently, a significant portion of the fixed costs are still
13 recovered through the volumetric portion of the rate. That creates a basic
14 mismatch between the underlying costs and the rates intended to recover those
15 costs. Increases or decreases in natural gas purchased wil cause the utility to
16 over-collect or under-collect its fixed costs. The Delmara proposal is intended to
17 remedy that.
18 11. Q: What causes variations in the volume of natural l!as purchased? 19 A: There are several primary causes: increases in natural gas appliance
20 efficiencies, changes in building standards and practices, warmer or cooler 21 temperatures and demand response to increased prices (price elasticity). An
22 expanded energy effciency program will also contribute significantly to this 23 problem.
4 1 12. Q. Do YOU expect these causes to continue into the future?
2 A: Yes. For example, the average national cost of natural gas at the city gate
3 was less than $1 per thousand cubic feet until the mid seventies. During the early
4 80's natural gas rose to a high of about $2.50 per thousand cubic feet before
5 settling down to approximately $2.00 per thousand cubic feet. Natural gas
6 remained at approximately $2.00 per thousand cubic feet until the late 1990's.
7 Since 2000, however, natural gas has increased substantially. From 2002 to 2005
8 natural gas prices rose from around $3.00 per thousand cubic feet to over $6.00
9 per thousand cubic feet. As is generally true in the industry and as Dr. Farney
10 shows for Delmarva's gas customers, it is clear that these significant price
11 increases will reduce average customer use. However, the fixed costs of the gas
12 distrbution system haven't changed. Thus, a reduction in use wil lead to an
13 under-recovery of the fixed costs, which in turn will create increased pressure for
14 future rate increases. Schedule JHC-2 ilustrates the decline in average usage per
15 residential customer in the U.S. and the average city gate price for the period 1987
16 to 2004. Of course, an increase in use will lead to an over-recovery of the fixed
17 costs. The BSA is designed to address these over- and under-recoveries.
18 13. Q: What alternative forms of rel!ulation have other natural l!as utilties used?
19 A: The problem described above is not unique to Delmara; many other
20 utilities across the country are in a similar position, and have developed a variety
21 of approaches to address the over- and under-recovery issue. Schedule JHC-3
22 describes the varety of means that have been implemented recently to address the
23 problem. I would classify the approaches as:
5 1 · Weather Normalization Clauses - riders that correct for weather related
2 changes in usage
3 · Revenue Decoupling Tariffs - riders that correct for any differences in the
4 usage levels built into base rates
5 · Retur Stabilization Mechanisms - expedited rate proceedings or riders
6 that correct for both differences in usage and differences in cost
7 · Fixed Variable Rate Design - changes in base rates that shift all fixed
8 costs into fixed rate elements
9 · Increased Customer Charge - shift additional fixed costs to the customer 10 charge 11 While each of the approaches to address this issue have strengths and 12 weaknesses, I believe Delmarva's proposal is paricularly appropriate. In
13 principle, rate structure changes that collect all of the fixed costs in a fixed charge
14 would best meet the Bonbright standard for alignent of costs and rates. That
15 approach would, however, significantly increase rates for small usage customers.
16 Stabilizing the retur also addresses the problem, but removes the incentive for a
17 utility to manage costs. I believe the revenue decoupling approach proposed by 18 Delmara represents an appropriate balance between the objectives of cost 19 alignent, gradualism and efficiency.
20 14. Q: Has the National Association of Rel!ulatory Commissioners (NARUC) 21 addressed this issue? 22 A: Yes. NARUC has issued two resolutions specifically addressing the need
23 for alternative forms of regulation for natural gas utilities. In its "Resolution on
6 1 Gas and Electric Energy Efficiency" adopted by the NARUC Board of Directors
2 on July 14, 2004 NARUC encouraged State commissions to "address regulatory
3 incentives to address ineffcient use of gas and electrcity". In the same resolution
4 they encouraged State commissions to review and consider the recommendations
5 in the "Joint Statement of the American Gas Association, the Natural Resources
6 Defense Council, and the American Council for an Energy Efficient Economy".
7 In its "Resolution Supporting the National Action Plan on Energy Efficiency"
8 adopted by the NARUC Board of Directors on August 2,2006, NARUC endorses
9 "the principal objectives and recommendations of the National Action Plan on
10 Energy Efficiency, and commends to its member commissions a State-specific,
11 and where appropriate, regional review of the elements and potential applicability
12 of energy effciency policy recommendations outlined in the Plan, in an effort to
13 identify potential improvements in energy effciency policy nationwide." The
14 resolution cites five key elements of the Plan: 1) Recognize energy efficiency as a
15 high priority energy resource; 2) Make a strong, long-term commitment to cost-
16 effective energy efficiency as a resource; 3) Broadly communicate the benefits of
17 and opportunities for energy efficiency; 4) Promote suffcient, timely, and stable
18 program funding to deliver energy effciency where cost-effective; and 5) Modify
19 policies to align utility incentives with the delivery of cost-effective energy
20 efficiency and modify ratemaking practices to promote energy effciency
21 investments.
7 1 15: Q: Does the "Joint Statement of the American Gas Association and the Natural
2 Resources Defense Council" list the benefits of alternative rel!ulatory 3 approaches? 4 A: Yes. The statement lists several benefits:
5 · Customers could save money by using less natural gas
6 · Reduced overall use would help push down short-term prices at times when
7 markets are under stress, reducing costs for all customers (whether or not they
8 participate in utility energy efficiency programs)
9 · Utilities would be better able to recover their costs and have a fair opportunity
10 to ear their allowed returns
11 · State policies to encourage economic development would be enhanced by
12 increased energy effciency and lower business energy costs
13 · State regulatory commissions would be able to support larger state policy
14 objectives
15 16. Q: Have mechanisms similar to Delmarva's proposal been independently
16 evaluated?
17 A: Yes. In 2005 Chrstensen Associates evaluated the decoupling mechanism
18 of NW Natural for the Oregon Public Utility Commission. They found that NW
19 Natural's mechanism:
20 · Did not shift risk to the customers
21 · Did not create negative incentives towards customer service
22 · Reduced the company's disincentive towards energy efficiency
23 · Improved the company's ability to recover its fixed costs
8 1 Delmarva's revenue normalization approach is consistent with the NW Natural
2 mechanism. I would expect the approach to have similar impacts.
3 17. Q: What do you conclude about the appropriateness of Delmarva's proposal?
4 A: I conclude that Delmarva's proposal is consistent with approaches that
5 have been implemented successfully by natural gas distribution companies in
6 jurisdictions across the U.S. I expect that Delmarva's proposal will have the
7 following impacts:
8 1) Customer bills wil be more stable
9 2) Revenues will be better aligned with costs
10 3) Disincentives toward energy effciency will be reduced.
11 4) The Company will be better able to recover its fixed costs
12 18. Q: Does this conclude your Testimony?
13 A: Yes.
9 Schedule JHC-1
John H. Chamberlin, Ph.D. Quantec, LLC. 28 E. Main St. Reedsburg, WI 53959 (608) 524-4844 johnc~quantecllc.com
EXPERIENCE Executive Vice President Quantec, LLC (2003 to present) Leads several practice areas including utility pricing and rate design, portfolio planning, regulatory strategy and retail market analysis.
Vice President, Strategic Services XENERGY Consulting Inc. (2000 to 2003)
Responsible for the development and implementation of tools and process to improve the profitability of product and service offerings, for the development of strategic services related to resource acquisition and management, and risk assessment and risk management services.
Vice President, Strategy and Planning PG&E Energy Services (1998-2000)
Dèveloped and managed all planing-related processes, including long-range planning, budgeting, acquisition, market entry, product development, commodity assessment, risk management and assessment, and market planing.
Vice President, Business Products and Services (1997)
Responsible for the development and management of all non-commodity products and services, including those related to power quality, information services, energy management, load management, and mass market.
Executive Vice President Barakat and Chamberlin, Inc. (1985-1997)
Director of the firm's strategic planning work for utilities. Performed numerous utility cost of service (both embedded and marginal), pricing, rate design and regulatory support assignents. Has been instrumental in developing competitive business plans for utilities throughout the United States and Canada. Expertise includes resource planing, business planning, innovative products and pricing, market assessments and planning, interfuel competition, promotional practices, and performance-based incentive mechanisms. Many engagements focused upon emerging issues in the areas of regulatory restructuring, competitive assessment, and new
John H. Chamberlin Schedule JHC-1
product development. Has worked with more than 70 utilities to develop effective and profitable energy effciency programs. Has prepared and presented testimony in approximately 100 regulatory and civil proceedings in the United States and Canada and has helped design and implement ratemaking frameworks in numerous jurisdictions. Has also prepared and presented expert witness testimony in support of business litigation.
Senior Project Manager Electric Power Research Institute (1982-1985)
Developed, managed, and coordinated projects related to demand-side planing, rate design, load forecasting, and customer behavior and response. Major projects included the development of a short-term forecasting softare package, the management of a large load-control experiment, and the development of a method for integrating rate design and load-management incentives. Also initiated a project designed to improve planning and analysis techniques for providing service options to utility customers.
Project Manager ICF, Incorporated (1979-1982)
Work centered on issues related to costs, rates, and load management for electric utilities. Major projects included the development ofthe first comprehensive textbooks concerning the calculation of marginal costs and marginal-cost-based rates. Developed the PURA time-of-day and load-management guidelines and conducted several cost-benefit studies of load management. Developed and conducted a series of workshops on costing and ratemaking for utility and commission personneL.
Instructor San Jose State University Cybernetic Systems Program (1979-1980)
Taught graduate courses in statistics and dynamic modeling.
Project Manager Electric Power Research Institute (1977-1979)
Developed and managed projects related to modeling, rate design, and forecasting the supply of electricity. A major project was the development of a generation expansion planing model and associated databases.
Economist Hanford Engineering Development Laboratory (1975-1977)
Involved in all aspects of modeling and forecasting electricity supply, demand, and power systems costs. Developed and applied load forecasting, production costing, expansion planning, and financial analysis models. Also performed cost-benefit analyses of advanced nuclear systems.
John H. Chamberlin Schedule JHC-1
EDUCATION
Ph.D., Economics, Washington State University, 1976 M.A., Economics, Washington State University, 1975 B.A., Economics, California State University, 1972
PUBLICATIONS AND COURSES
Author of 4 books, numerous published articles, and a wide variety of invited talks at industry conferences and workshops.
Developed and taught approximately 20 courses and workshops on ratemaking, utility planing, cost of service, forecasting, and related topics.
John H. Chamberlin uQ) ëi it ~ Q) Q) 1i "' OJ ëii Q) è a: ê3
+ +
l:)li Jad $ N I" (0 io ~ C" C' i 0 U ~ :: 0 .. C' Q) C" - 0 .§ C' Q) s: C' ~(. 0 0 r. :¡ C' Co .. E 0 ;j C' II 0 s: 0 0 C' (, ai II ai ns ai C) ai00 ¡¡~ ai ;j .. I" -ns ai Z ..ai ns (0 ;j ai s: ..ai s: io ci ai ¡¡ :¡ ~ s: ai Q) ai " C" ïii ai Q) ai ct aiC' ~ ..ai :: .. ai ..ai ai0 ..ai ai 00 ..ai 00 00 ..ai I" 00 ..ai 0 0 0 0 0 0 C' 0 00 (0 0 .. .. 0 0 0"" 0C' 0 0 0 0 0 0 Jawolsno ie!luap!sall Jad I:)W Schedule JHC-3
Revenue Stabilzation Description Utilties Implementing Strategy Strate2Y Weather Normalization Adjusts monthly bills through a change in rate, In use nationwide by dozens of utilities in 30 states change in volume or through a surcharge such including these in nearby jurisdictions: City of
that the monthly bill equals that approved by Richmond V A, Consolidated Edison Co of NY, the state regulators for normal weather Elizabethtown Gas (NJ), Keyspan (N), National conditions. Fuel Gas (N), New Jersey Natural Gas, Niagara Mohawk Power (NY), Philadelphia Gas Works (P A) Piedmont Natural Gas (NC, SC, TN) and Virginia Natural Gas Revenue Decoupling Fixed cost revenue requirement is determined Southwest Gas (CA), Baltimore Gas and Electric, on a per-customer basis, often with a weather Washington Gas (MD), Piedmont Natural Gas (NC), and productivity adjustments. Deviations from NW Natural (OR). Several additional natural gas approved revenue collections on a per-customer utilities have applications pending. basis are accumulated in a true-up account, which is recovered through an adjustment to the rate in subsequent months. Return Stabilization Formulary plans that replace traditional rate Alabama Gas, Mobile Gas, Atmos (LA, MS), cases. They provide a streamlined way to CenterPoint (LA, MS, OK), Entergy (LA), Piedmont monitor the utility's earnings and adjust rates to (SC) maintain the earned return within an authorized band. Fixed Variable Rates / Modification to traditional fixed/variable rates. Atlanta Gas, Laclede (MO), Xcel (N), ONEOK Increased Customer Typically, the demand or customer charge is (OK) Charge more closely aligned with total fixed costs. Demand charge may be seasonally adjusted. Direct Testimony of Paul M. Normand PSC Docket No. 06- Page 1
Delmarva Power & Light Company
Before the Delaware Public Service Commission Docket No. 06-
PREPARED DIRECT TESTIMONY OF Paul M. Normand
Gas Cost of Service fI MANAGEMENT APPLICATIONS CONSULTING, INC. 1103 Rocky Drive, Suite 201 Reading, PA 19609-1157
(610) 670-9199 fax (610) 670-9190 "afta.,.., ...... _ ,."".. Direct Testimony of Paul M. Normand PSC Docket No. 06- Page 2
PREPARED DIRECT TESTIMONY OF PAUL M. NORMAND ON BEHALF OF DELMARVA POWER & LIGHT COMPANY
TABLE OF CONTENTS
INTRODUCTION ...... 4 SCOPE OF TESTIMONY ...... 4 WEATHER NORMALIZATION ...... 5 ACCOUNTING COST OF SERVICE STUDy...... 7 Allocated Cost of Service Study...... 7 Description of Cost Model...... 8 Cost of Service Model Allocation Methodology...... 10 Rate Base Allocation...... 11 Revenues...... 15 Operating Expense Allocation...... 16 Accounting Class Cost Study Results...... 18 Use of the Cost of Service Results...... 19
~ Direct Testimony of Paul M. Normand PSC Docket No. 06- Page 3
PREPARED DIRECT TESTIMONY OF PAUL M. NORMAND ON BEHALF OF DELMARVA POWER & LIGHT COMPANY
LIST OF SCHEDULES
Schedule Description
PMN-1 Qualifications of Paul M. Normand
PMN-2 Accounting Class Cost of Service Summary Results at Actual ROR
PMN-3 Accounting Class Cost of Service Summary Results at Claimed ROR
PMN-4 Accounting Class Cost of Service - Unbundled Summary Results
PMN-5 Accounting Class Cost of Service Detailed Results
PMN-6 W orkpapers
PMN-7 Description of Allocation Factors
~ Direct Testimony of Paul M. Normand PSC Docket No. 06- Page 4 INTRODUCTION
1. Q: Please state your name. address and position. A: My name is Paul M. Normand. I am a management consultant and president with
the firm of Management Applications Consulting, Inc., 1103 Rocky Drive, Suite 201,
Reading, P A 19609.
2. Q: Please state your Qualifications. A: My qualifications are shown on Schedule PMN-1.
SCOPE OF TESTIMONY
3. Q: Mr. Normand. what is your responsibilty in connection with this fiinl!? A: I am responsible for developing the accounting cost of service study and for
providing the achieved rate of return results at existing weather normalized revenue
levels by customer class for Delmarva Power & Light's gas business ("Delmarva" or "the
Company"). In addition, my results are recalculated to the Company's overall claimed
rate of return on a uniform basis for each class of service. This can provide an input to
assist the Company in rate design and establishing class revenue targets.
4. Q: Please outlne the orl!anization of your testimony and schedules.
A: My testimony will first discuss the adjustments to the cost data used as input for
my cost studies. I will then discuss the Accounting Cost of Service Study in this fiing.
Finally, I will briefly describe the possible use ofthe accounting cost of service study
results in determining class revenue increase targets and monthly customer charges.
Schedule PMN-1 describes my qualifications and experience. Schedules PMN-2 and
PMN-3 contain the accounting cost of service study summary results at the actual and ~ Direct Testimony of Paul M. Normand PSC Docket No. 06- Page 5 claimed rates of return for each rate class. In addition to the traditional cost of service study results, Schedule PMN-4 also includes summary results by major cost categories
for customer, demand, and commodity. Schedule PMN-5 presents the detailed output of
the accounting class of cost of service study and all the supporting allocation factors used
to develop the study. Schedule PMN-6 presents critical workpapers relating to the
development of certain major allocations of costs in the study. Finally, Schedule PMN-7
presents a detailed description of the allocation factors used in the cost of service study
discussed herein.
WEATHER NORMALIZATION
5. Q: What is the purpose of a weather normalization adjustment? A: For the purposes of cost of service studies and rate making, the test period must
represent typical or normal circumstances. Delmarva Power & Light Company adjusted
the test period to reflect the effects of weather on the Company's ccf sales. One of the
most important adjustments is the Company's sales which are weather sensitive. Small
variations in weather can have a material impact on the sales and revenues, especially for
a gas utility. The Company's weather normalization adjustment is targeted to identify the
change in sales and revenue that would have been anticipated if the actual weather in the
test period had been normaL. The use of these adjustments in the allocation process provides a much more robust cost of service result which can be readily used as the
foundation and a major input in establishing revenue targets and certain aspects of rate
design. The weather adjustment and design day estimates have been discussed in Dr.
Farey's testimony.
6. Q: How did YOU account for non-tirm sales revenues? A: The non-firm sales revenues and margins for interrptible sales, transportation,
and standby customers were included as part of the Company's gas rate clause to each iI Direct Testimony of Paul M. Normand PSC Docket No. 06- Page 6
firm sales service customer class as required by the Commission. These revenues and
margins were therefore excluded from the final cost of service results establishing class
ROR and uniform ROR revenue targets. A portion of these non- firm revenues have been
included as part of the cost of service analyses as shown on page 9, lines 6 through 9 of
Schedule PMN-5.
7. Q: What test period did YOU use in your cost of service study? A: The cost of service study presented in my testimony and exhibits was based on a
historical test period 12 months ended 3/31/06. My starting point was the Company's per
book numbers. These results were then adjusted with respect to customer sales and
revenues for weather normalization. The revenues and O&M expenses relating to
recoverable gas costs have also been removed from the cost of service analysis and
results of my schedules. The only remaining revenues and costs are, therefore, base
related as approved by the Commission, as shown in Mr. Yon Steuben's
Schedule WMV -1.
8. Q: Are the results from your cost of service study reliable when usinl! a historical period? A: Generally speaking, a historical period that is within one year of the filing period
can be considered as reflecting reasonable class results. For gas utilities, the most
overrding aspect is primarily the adjustment for weather which was considered and made
a par of the cost and allocation process of the cost of service results presented herein.
The cost of service results are therefore appropriate and reasonable in forming a
foundation for class rate design and revenue targets as presented in Mr. Janocha's
testimony.
ID Direct Testimony of Paul M. Normand PSC Docket No. 06- Page 7
ACCOUNTING COST OF SERVICE STUDY
Allocated Cost of Service Study
9. Q: Would YOU briefly detine an Allocated Cost of Service Study. A: The cost to serve the customers of any utility company consists generally of
allowable investments, operating expenses and a return. For a historical test period, these
costs are a matter of record and the overall cost to serve the collective customers of the utility may be readily established. On the other hand, the unique cost to serve customers
of the various service classifications is much less apparent. Costs can vary significantly
between customer classes depending upon the nature of their demands upon the system
and the facilities required to serve them. The purpose of an Allocated Cost of Service
Study is to directly assign based on Company records or allocate each relevant and
identifiable component of cost on an appropriate basis in order to determine the proper
cost to serve the respective classes under study. The analysis results in a matrix
displaying the detailed costs of serving each customer class and by cost category.
10. Q: Please describe the procedure that yOU used in preparinl! your Allocated Cost of
Service Study?
A: Through the application of a computerized microcomputer cost model developed
by Management Applications Consulting specifically for Delmarva Power & Light
Company' gas operations, it was possible to treat each element of Rate Base, Revenues and Operating Expenses in detail and to directly assign or allocate each cost item to
specific customer classes. The complete detailed process is reflected in Schedule PMN-5
and reflects Delmarva Power & Light Company's gas cost to serve for the historical test
period ended March 31, 2006. Specific adjustments to this historical test period are fI Direct Testimony of Paul M. Normand PSC Docket No. 06- Page 8
presented and discussed in the Company's testimonies of Dr. Farney and Mr.
V onSteuben.
11. Q: Please summarize your cost of service studies.
A: The first study, Schedule PMN-2 shows the summary results of the more detailed conventional cost of service study presented in Schedule PMN-5 employing weather
normalized class base revenues from existing firm rates. Schedule PMN-3 shows a
similar summary of a class cost of service study where the existing and targeted revenue
requirements from each class are included in the calculations to generate existing and
uniform class rates of return equal to the overall 8.08% targeted rate of return identified by the Company for its cost of service. A separate Proposed Revenues section was
included to present the class revenue requirements with the Company's revenue
deficiency as developed in Mr. VonSteuben's testimony. The third analysis, Schedule
PMN-4, summarzes the costs to serve each major cost category component at present
rates and at an equalized rate of return target for each class of service to assist in the rate
design process. The calculated monthly customer charge for each class of service is
shown on line 24 for the existing and uniform RORs.
Description of Cost Model
12. Q: How does the computerized cost model operate?
A: The cost of service model is essentially a very large cost matrix. The vertical
dimension of the study consists of all the costs to serve elements as provided by the
Company. The horizontal portion consists of customer classes (Schedule PMN-5). The
development of a cost of service study begins with rate base details for each account of
plant and continues with revenues, operating expenses, taxes, and the computation of a ~ Direct Testimony of Paul M. Normand PSC Docket No. 06- Page 9
labor allocator. The cost model includes three additional pieces, a summary of costs to
serve, a list of the allocation factors employed in the study and a revenue requirements
summary section.
Each page, starting with page 1 has an important column immediately preceding
the numerical data marked "ALLOC", an abbreviation for ALLOCATOR. The ALLOC
column contains an acronym to indicate the allocation factor used to allocate the costs
shown in the Total Company Column to individual customer classes to the right. A
tabulation of these allocators in absolute form, typically total dollars or volumes
beginning on page 26 and as a percent of total has been provided at the end of the study, beginning on page 35.
Using these allocation factors, costs shown in the Total Company column are
assigned or allocated to each customer class shown on the horizontal for each page of the
cost study. The cost of service information provided in the vertical column are the per
books numbers as adjusted for the test period based on the testimonies of Messrs. Driggs and Von Steuben.
13. Q: What customer classes did YOU recol!nize in your cost of service study?
A: The cost of service study recognized and allocated the Company's costs to all
firm sales and transportation customer tariff classes as follows:
R Residential RSH Residential Heating GG + GVFT General Service MVG + MVFT Medium Volume General Service LVG + LVFT Large Volume General Service LTG Lighting (I Direct Testimony of Paul M. Normand PSC Docket No. 06- Page 10
14. Q: Were there any other adjustments that YOU made before developinl! your cost of
service study?
A: The cost of service studies presented in my testimony and schedules reflect the
removal from total revenues and expenses of the Company's gas costs recovered in their
GCR clause. The cost of service results, therefore, represent class-allocated results
excluding recoverable gas commodity costs. The supporting details for this data have
been provided in Mr. Yon Steuben's exhibits.
Cost of Service Model Allocation Methodolol!y
15. Q: Would you please tell us how you choose allocation factors for your cost study?
A: In the cost allocation process, I attempted to determine the intended use of
specific plant investments and then examined the specific use of these assets in the test
period. As part of the cost of service process, I then developed the required external
allocators or selected internal allocators to assign the varous costs appropriately to
customer classes. A complete and detailed list of each allocation factor has been
provided in Schedule PMN-5, pages 26 through 34 from Company data and these values
have also been restated on a unitized or ratio basis on pages 35 through 43. This latter
data represents the individual class percent or responsibility ratio ifthat allocator is used
to assign a cost item in the study. In order to provide additional information for these
factors, I included in Schedule PMN-7 a detailed explanation of each allocation factor.
f! Direct Testimony of Paul M. Normand PSC Docket No. 06-_ Page 11
Rate Base Allocation
16. Q: How did YOU select allocators for production costs?
A: Delmara Power & Light Company utilizes a diversified mix of supply sources in
order to serve its customers. This process has resulted in a mix of supply sources which
include various pipeline and storage contracts. The cost of service study presented herein
removed all GCR related gas costs and associated revenues. The only remaining supply
costs to be allocated were with respect to Pipeline and LNG storage inventory costs and
the LNG-related plant costs.
17. Q: What were the principal allocation factors used to assil!n the LNG production
capacity costs in your accountinl! cost of service studies?
A: LNG facilities are intended to primarly provide pressure support and satisfy
additional customer demand on the coldest or extreme weather days of the year.
Accordingly, I have allocated the LNG capacity costs on a Design Day allocator less a
daily base use for each customer class using a two-summer-month average as the base.
The development of this allocator is shown on page 26 of the cost study, Schedule PMN-
5 and is called DEMSTOR. This approach to allocation recognizes that a portion of the design day demand is met by other than peaking supplies.
18. Q: How did yOU develop the desil!n day allocator used in your cost of service
calculations?
A: The design day allocator was developed by the Company. In developing the
allocation factor, however, I considered only the contract MDQs as the most appropriate
demand for the larger rate classes of Medium Volume and Large Volume sales and
transportation customers. The remaining classes of Residential Non-Heating, Heating, ~ Direct Testimony of Paul M. Normand PSC Docket No. 06- Page 12
and General Service utilized estimated Design Day demands. After adjusting for losses, I
combined these results with the contract MDQs for the larger classes to arrve at my final
design day estimate used in the allocation process of the cost of service study. The
design day calculated results are presented in the cost of service results, Schedule PMN-
5, page 26, line 17.
19. Q: How did YOU allocate the pipeline storal!e inventory included in rate base?
A: The pipeline inventory costs were allocated only to sales customer classes using a
five-month winter use from November through March excluding a five month winter
base average use calculated from two summer months. The ESTOR storage inventory
allocator was developed using line 20 Total Winter Sendout less line 15 Total Winter
Base Sendout on page 27 of the cost of service study, Schedule PMN-5. The winter base
use on line 15 was calculated by simply multiplying the summer daily base use shown on
line 14 by 151 days (winter period).
20. Q: Please describe the remaininl! allocation of rate base to customer classes.
A: The remaining rate base allocations are shown on pages 3 through 8 of Schedule
PMN-5. The transmission plant costs were allocated using a DEMTRAN to each
customer class based on a relative weighting of their respective design day contribution and average annual use values. The distribution plant allocation factor DEMDIST is the
capacity allocation factors used for the allocation of distribution plant, capacity-related
costs such as distribution land and land rights, structures and improvements, measuring
and regulating station equipment, other equipment. The demand allocators were derived
based on the Commission's prescribed method whereby Design Day and average annual ~ Direct Testimony of Paul M. Normand PSC Docket No. 06- Page- 13 use were calculated and weighted so that cost responsibilities developed and used to
allocate costs recognize both consumption components in developing a final allocator.
Distribution mains were allocated to each customer class using a design day and
anual volume composite factor for each class excluding those very large customers
served off the transmission system (DEMMAlN). By performing this extra step, a
considerable amount of distribution facilities and associated expenses not serving these
large customers can be properly allocated to the remaining distribution customers.
21. Q: What are the customer-related allocation factors included in your cost study?
A: Customer-related plant items were allocated using CUST -prefixed allocators for
services, meters, and other such customer-related items. These allocation factors were
developed from engineering records and other available Company sources and used to
assign the specific customer-related costs to each customer class. A complete list of
these factors has been provided on page 28 of the cost of service study, Schedule PMN-5.
22. Q: How were services allocated to customer classes?
A: Other than distribution mains, services is the largest plant account cost included in
the Company's rate base. Recognizing the importance of these costs and the impact of
any allocation to customer classes, the Company undertook a very comprehensive and
detailed analysis of its services by size and type based on their engineering records.
This detailed analysis considered all customer classes in developing the
assignent of the service costs to each customer class for use in the cost of service study.
Costs associated with interrptible customers were identified and removed from the final
calculated allocator so that all booked costs were ultimately allocated only to firm ~ Direct Testimony of Paul M. Normand PSC Docket No. 06- Page 14
customers. This approach is consistent with prior Commission orders and recognizes that
interrptible margins are credited to all firm customers in the Company's fuel clause and
my cost of service study, as shown on page 9 of Schedule PMN-5. A summary of this special study for services has been included as part of the workpapers provided in
Schedule PMN-6.
23. Q: How were Meters. Account 381. allocated to customer classes? A: Here again, meter costs are also a large part of the rate base which impact
allocated costs to customer classes. The Company undertook a similar detailed analysis
as was done for services for all its meters and metering devices based on engineering
records. The result of this study was an identification of all metering costs by rate class
which was then used to allocate the booked meter costs to all firm customers. Consistent
with the approach used for services, all costs relating to interrptible customers were
identified and removed prior to developing the final allocator used in the study. A
detailed summary of this study by meter type and customer class is included in the
workpapers, Schedule PMN-6.
24. Q: How were l!eneral and common plant allocated on pal!e 2 of Schedule PMN-5?
A: General plant was allocated on an internally generated labor allocation factor
(LABOR) based on labor expensed and allocated in the test period. The labor allocation
factor was developed by reviewing each Operations and Maintenance account to
determine the labor portion of expense included in each account. These costs were then
allocated separately in the same manner as the total accounts were allocated. The
allocated labor costs were then subtotaled by class to arrve at the final composite
allocation factor, LABOR. The development ofthis allocator is shown in detail on
Schedule PMN-5, pages 20 through 24 ofthe cost of service study. ~ Direct Testimony of Paul M. Normand PSC Docket No. 06- Page 15
25. Q: How was each account of reserves for depreciation allocated?
A: Functional total reserves were allocated on the subtotal of the corresponding
allocated plant cost. The details for each category are shown on Schedule PMN-5, page
5.
26. Q: What other elements of rate base were included in your study?
A: Each adjustment to rate base has been detailed on Schedule PMN-5, pages 6, 7
and 8. Additions to net plant included construction work in progress, prepayments,
storage gas, plant materials and supplies, and cash working capitaL. The deductions from
net plant include customer advances, customer deposits, and accumulated deferred
income taxes.
Each adjustment to rate base was allocated on the most appropriate allocation
factor. For example, CWIP was functionalized and allocated on the corresponding plant
functional costs. The cash working capital component of rate base was developed in
detail by the Company and allocated on related expenses or plant costs in the cost study.
Revenues
27. Q: How did yOU establish the revenues to be utilzed in the cost of service study?
A: The Company provided the class-by-class weather normalized revenues used in
the cost of service study. These revenues exclude gas revenues recovered through the
GCR clause with the corresponding O&M gas costs also removed.
The remaining revenues are listed as Other Operating Revenues and reflect ~ Direct Testimony of Paul M. Normand PSC Docket No. 06- Page 16 primarily non-firm transportation revenues and forfeited discounts with the line-by-line
detail provided on Schedule PMN-5, page 9. Non-firm transportation revenues were
allocated to all firm classes using an equal weighting of meters, services, and
transmission plant.
Operatinl! Expense Allocation
28. Q: How were operatinl! expenses allocated?
A: The allocation of O&M expenses follows the method by which these expenses
were incurred. Therefore, the plant-related O&M expenses are allocated using the same
allocators used for their associated plant investment.
29. Q: How were the l!as costs allocated?
A: As I mentioned earlier, all recoverable gas costs and revenues recovered through
the GCR were removed from the cost of service study. The only remaining portion of
gas costs related to purchasing gas in Accounts 807 and 813 which were allocated only to
sales customers. LNG expenses were allocated on the corresponding plant allocations to
each customer class.
30. Q: How were the remaininl! Operation and Maintenance Expenses allocated?
A: Transmission and Distribution O&M expenses follow the allocation of plant.
Customer Accounts, Sales Expenses, and Administrative and General Expenses were
allocated using a variety of methods based on direct assignents, revenues, gas costs,
number of bills and number of customers. Whenever possible, specific information
detailing class cost responsibilities or weightings was utilized in order to develop the ~ Direct Testimony of Paul M. Normand PSC Docket No. 06- Page 17
most accurate cost study possible. Externally developed allocators were used for
Accounts 902 and 903. For example, Account 902, Meter Reading Expense, was
allocated to customer classes on an externally developed allocator (CUST902) which
weighted customers based on a Company analysis. Accounts 907 through 910 used a
composite allocation factor that was weighted 50% on customers and 50% on class sales.
A&G expenses were primarily allocated on the labor allocator. The remaining
A&G expenses were partly allocated on revenue and partly on plant in service
components, all developed internally and shown beginning on page 14 of Schedule PMN-
5.
31. Q: What are the remaininl! operatinl! expenses?
A: The remaining operating expenses consist of depreciation and amortization
expenses, taxes other than income taxes, and a detailed state and federal income tax
calculation.
32. Q: How were they allocated?
A: Depreciation expenses were allocated on the basis of plant in service similar to
the allocation of depreciation reserves. Taxes Other Than Income Taxes, that are plant
related were allocated on PLANT and those that are labor related were allocated on the
LABOR allocator discussed earlier. Federal and state income taxes were computed for
each customer class based on the allocated expenses with the details developed on pages
16 through 19 of the cost of service study, Schedule PMN-5. ~ Direct Testimony of Paul M. Normand PSC Docket No. 06- Page 18
Accountinl! Class Cost Study Results
33. Q: Could YOU summarize the results of your cost study at present rates?
A: The results ofthe test period cost of service study demonstrate that the rates
presently in effect generate different rates of return for each customer class. Schedule
PMN-2 clearly demonstrates the Company's current rates produce inequities among
existing firm rate classes.
All classes except Residential Space Heating, General Service, Large Volume
General Service, and Lighting are generating below-average rates ofretum. For
Residential non heating and MVG classes, this is an indication of interclass subsidization.
These results are based on a test period ended March 31, 2006 and do not fully reflect the
Company's rate year adjustments and total revenue requirements as presented on Mr.
Yon Steuben's testimony and exhibits. However, these results can be used as a guide or
input in establishing reasonable revenue targets and class increases. Schedule PMN-3,
line 11, shows the percent increase or decrease required to existing class revenue levels
for each customer class to achieve the Company's overall 8.08% ROR as shown on line
7. The Proposed Revenues section calculates the class and total Company revenue
requirements by adjusting the ROR on a uniform basis.
~ Direct Testimony of Paul M. Normand PSC Docket No. 06-_ Page 19
34. Q: Could YOU please summarize your cost of service results?
A: The cost of service results presented on Schedules 2 and 3 for the 12 months ended
March 31,2006 are as follows: Rate of Index of Return Rate of Customer Class Actual Return
Residential 4.14 0.76 Residential Heating 5.44 1.00 General Service 5.82 1.07 Medium Volume General Service 3.80 0.70 Large Volume General Service 6.19 1.14 Lighting 12.81 2.36 Total Company 5.43 1.00
Use of the Cost of Service Results
35. Q: Let's turn now to the subject of revenue tarl!ets. Could YOU explain your results in
the rate desil!n process?
A: In the accounting cost of service study, I identified the costs to serve each
customer class at a uniform rate of return (Schedule PMN-3). However, it is frequently
impractical or impossible to design rates to exactly match calculated costs. In some
instances, doing so would result in unacceptably large increases to some classes and
substantial decreases to others. Rate stability and bil impact considerations dictate some
level of gradualism in rate design initiatives in order to moderate change and minimize
such problems. The cost of service study is but one input in the rate revenue targets to be
established in the Company's rate design process. For example, cost of service study is
historical and does not contain all of the adjustments presented in Mr. Von Steuben's
exhibits.
~ Direct Testimony of Paul M. Normand PSC Docket No. 06- Page 20
36. Q: Did YOU develop any other costs result which could assist in the rate desil!n? A: Yes, I did. Schedule PMN-4 shows the summary cost of service results for the
customer demand and commodity costs for each rate class. Taking these results at the
Company's ROR on a uniform basis yields the following monthly customer charges
which can be a guide in adjusting the Company's curent monthly customer charges.
Uniform Current 8.08% ROR Monthly Monthly Customer Customer Customer Class Charl!es Charl!es
Residential $ 8.40 $ 15.19
Residential Space Heating 8.40 16.26
General Service 19.00 46.93
Medium General Service 315.00 553.00
Large General Service 500.00 893.90
37. Q. Does this conclude your testimony?
A. Yes, it does.
~ Direct Testimony of Paul M. Normand PSC Docket No. 06-
SCHEDULE PMN-l
QUALIFICA TIONS OF PAUL M. NORMAND
~ Direct Testimony of Paul M. Normand PSC Docket No. 06-
Schedule PMN-1
QUALIFICATIONS OF PAUL M. NORMAND
Q: Mr. Normand. what is your present position? A: I am a principal in the consulting firm of Management Applications Consulting, Inc. (MAC). This Company provides consulting services to the utility industry in such
field as loss studies, econometric studies, cost analyses, rate design, expert testimony, and
regulatory assistance. The Company has two offices, located in Austin, Texas and Sinking Spring, Pennsylvania.
Q: What is your educational back2round? A: I graduated from Northeastern University in 1975, with a Bachelor of Science
Degree and a Master of Science Degree in Electrical Engineering-Power System
Analysis. I have attended various conferences and meeting concerning engineering and
cost analysis.
Q: What is your professional back2round?
A: I was employed by the Massachusetts Electric Company in the Distrbution
Engineering Deparment while attending Northeastern University. My principal areas of assignent included new service, voltage conversions, and system planing. Upon
graduation from Northeastern University, I joined Westinghouse Electrc Corporation Nuclear Division in Pittsburgh, Pennsylvania. In that position, I assisted in the procurement and economic analysis of electrical/electronic control equipment for the
nuclear reactor system.
In 1976, I joined Gilbert Associates as an Engineer providing consulting services in the rate and regulatory area to utility companies. I was promoted to Senior Engineer in
1977, Manager of the Austin office 1980, and Director of Rate Regulatory Service since 1981. (! Direct Testimony of Paul M. Normand PSC Docket No. 06-
Schedule PMN-l
In June, 1983, I left Gilbert to form a separate consulting firm and I am now a
principal and President of Management Applications Consulting, Inc. My principal areas of concentration have been in loss studies, economic analyses, and pricing.
Q: Have you testifed in support of any cost studies that you participated in or performed? A: Yes, I have testified about such studies before the following regulatory agencies: the Maryland Public Service Commission, the Maine Public Utility Commission, the
Public Utility Commission of Texas, Ilinois Commerce Commission, New Hampshire
Public Utilities Commission, New Jersey Board of Public Utilities, New York Public Service Commission, Pennsylvania Public Utility Commission, the Massachusetts Departent of Public Utilities, the Kentucky Public Service Commission, the Arkansas Public Service Commission, the Public Service Commission of Louisiana, the Public
Utilities Commission of Ohio, the Public Service Commission of Missouri, and the
Federal Energy Regulatory Commission.
Q: Could yOU please briefly discuss your technical experience? A: I have performed numerous accounting and marginal cost of service studies, time
differentiated bundled and fully unbundled cost studies for both electric and gas utilities since 1980. I have also used such studies in the design and presentation of detailed rate
proposals before regulatory agencies.
My additional experience has been in the area of unaccounted for loss evaluations for electric and gas utilities for over twenty four years. These studies include a detailed review of each system and the calculation of appropriate recovery factors.
iI Direct Testimony of Paul M. Normand PSC Docket No. 06-
SCHEDULE PMN-2
ACCOUNTING CLASS COST OF SERVICE
SUMMARY RESULTS AT ACTUALROR
(! DELMARVA POWER & LIGHT Page 1-1 29-Aug-06 19:13 GAS COST OF SERVICE STUDY FOR THE 12 MONTHS ENDING MARCH 31, 2006 DELAWARE TRAN & DIST 73% DEM & 27% COMM ALLOC MEDIUM LARGE DISTR MAINS 75% DEM & 25% COMM ALLOC TOTAL RESIDENTIAL GENERAL VOLUME VOLUME COMPANY RESIDENTIAL HEATING SERVICE GENERAL GENERAL LIGHTING ALLOC (1) SUMMARY OF RESUL TS-1 (2) (3) (4) (5) (6) (7)
DEVELOPMENT OF RATE BASE 1 GAS PLANT IN SERVICE PAGE 4 356,107,669 12,922,648 211,366,506 88,790,953 22,225,326 20,797,384 2 LESS: RESERVE FOR DEPRECIATION PAGE 5 144,732,298 4,852 5,252,555 86,145,634 36,059,155 9,019,207 8,253,801 1,947 3 NET PLANT IN SERVICE 211,375,370 7,670,092 125,220,872 52,731,798 13,206,119 12,543,584 2,905 4 PLUS: CWiP PAGE 6 7,309,188 241,177 4,278,721 1,839,808 480,184 469,205 93 5 PLUS: MATERIALS & SUPPLIES PAGE 6 18,281,431 234,986 11,141,171 5,358,024 1,157,435 389,805 6 PLUS: CASH WORKING CAPITAL PAGE 7 9,339,527 9 254,841 5,310,083 2,596,383 655,543 522,435 7 PLUS: MISC RATE BASE ITEMS PAGE 6 10,336,893 243 485,720 6,372,307 2,391,421 565,055 522,211 180 8 LESS: DEFERRED FIT PAGE 8 18,253,777 662,404 10,834,468 4,551,349 1,139,251 1,066,056 249 9 LESS: DEFERRED SIT PAGE 8 5,110,514 185,453 3,033,328 1,274,242 318,956 298,464 70 10 LESS: ACCUM ITC PAGE 8 904,630 35,087 542,138 223,761 54,295 49,336 13 11 LESS: CUSTOMER ADVANCES PAGE 8 207,715 21,425 170,253 16,037 0 0 0 12 LESS: CUSTOMER DEPOSITS PAGE 8 2,317,383 239,034 1,899,429 178,920 0 0 0 13 TOTAL RATE BASE 229,848,390 7,743,414 135,843,538 58,673,124 14,551,832 13,033,383 3,099 DEVELOPMENT OF RETURN 14 OPERATING REVENUES PAGE 9 58,727,645 2,209,883 36,041,160 14,307,503 2,955,767 3,211,785 1,548 OPERATING EXPENSES 15 OPERATION & MAINTENANCE PAGE 14 25,155,705 1,191,687 16,081,629 5,448,787 1,265,072 1,167,827 703 16 DEPRECIATION & AMORT EXPENSE PAGE 15 12,231,041 454,382 7,295,582 3,050,832 751,013 679,062 171 17 TAXES OTHER THAN INCOME TAX PAGE 15 3,601,232 136,764 2,150,520 887,700 220,357 205,840 18 INCOME TAXES PAGE 15 51 5,314,754 104,223 3,146,810 1,528,427 174,472 360,594 19 INVESTMENT TAX CREDIT DEF-NET PAGE 15 227 (66,463) (2,597) (39,852) (16,384) (3,984) 20 INTEREST ON CUSTOMER DEPOSITS PAGE 15 63,573 (3,645) (1) 6,557 52,107 4,908 0 0 0 21 TOTAL EXPENSES 46,299,843 1,891,017 28,686,796 10,904,271 2,406,930 2,409,678 1,151 22 OPERATING INCOME 12,427,802 318,866 7,354,364 3,403,232 548,837 802,107 396 23 AFUDC PAGE 15 56,226 1,643 31,991 14,194 3,971 4,427 24 TOTAL EARNINGS 12,484,028 320,509 7,386,355 3,417,426 552,808 806,534 397 25 RATE OF RETURN 5.43% 4.14% 5.44% 5.82% 3.80% 6.19% 12.81% 26 INDEX RATE OF RETURN 1.00 0.76 1.00 1.07 0.70 1.14 2.36
PRINT DATE 8130/2006 PRINT TIME 8:57 AM Page 1-1 DPLGasCOSNew-MAC-8-29-06.xls COST OF SERVICE Direct Testimony of Paul M. Normand PSC Docket No. 06-
SCHEDULE PMN-3
ACCOUNTING CLASS COST OF SERVICE
SUMMARY RESULTS AT CLAIMED ROR
~ DELMARVA POWER & LIGHT Page 25-1 29-Aug-06 19:13 GAS COST OF SERVICE STUDY FOR THE 12 MONTHS ENDING MARCH 31, 2006 DELAWARE TRAN & DIST 73% OEM & 27% COMM ALLOC MEDIUM LARGE DISTR MAINS 75% OEM & 25% COMM ALLOC TOTAL RESIDENTIAL GENERAL VOLUME VOLUME COMPANY RESIDENTIAL HEATING SERVICE GENERAL ALLOC GENERAL LIGHTING (1) (2) REVENUE REQUIREMENTS-25 (3F (4) (5) (6) (7)
PRESENT RATES
1 RATE BASE 229,848,390 7,743,414 135,843,538 58,673,124 14,551,832 13,033,383 2 NET OPER INC (PRESENT RATES) 12,484,028 3,099 320,509 7,386,355 3,417,426 552,808 806,534 3 RATE OF RETURN (PRES RATES) 5.4314% 397 4.1391% 5.4374% 5.8245% 3.7989% 6.1882% 12,8052% 4 RELATIVE RATE OF RETURN 1.00 0.76 1.00 1.07 0.70 5 SALES REVENUE (PRE RATES) 57,731,937 1.14 2.36 2,171,153 35,225,260 14,186,890 2,945,458 3,201,632 6 SALES REV REQUIRED $/CCF $0.3176 1,545 $0.7936 $0.4571 $0.3223 $0.1700 $0.0788 $0.3858
CLAIMED RATE OF RETURN
7 CLAIMED RATE OF RETURN 8.08% 8.08% 8.08% 8.08% 8.08% 8.08% 8 RETURN REQ FOR CLAIMED ROR 18,571,750 8.08% 625,668 10,976,158 4,740,788 1,175,788 1,053,097 9 SALES REVENUE REQ CLAIMED ROR 67,900,310 250 2,680,862 41,221,337 16,397,314 3,986,026 3,613,470 10 REVENUE DEFICIENCY SALES REV 10,168,372 1,301 509,710 5,996,077 2,210,424 1,040,568 411,837 11 PERCENT INCREASE REQUIRED 17.6131% (245) 23.4764% 17.0221% 15.5808% 35.3279% 12.8634% 12 ANNUAL BOOKED CCF SALES 181,755,519 -15.8311% 2,735,824 77,056,777 44,020,598 17,324,205 40,614,110 4,005 13 SALES REV REQUIRED $/CCF $0.3736 $0.9799 $0.5349 $0.3725 $0.2301 $0.0890 14 REVENUE DEFICIENCY $/CCF $0.0559 $0.3247 $0.1863 $0.0778 $0.0502 $0.0601 $0.0101 -$0.0611 PROPOSED REVENUES
15 PROPOSED SALES REVENUES 67,900,310 2,680,862 41,221,337 16,397,314 3,986,026 3,613,470 16 REVENUE DEFICIENCY SALES REV 10,168,372 1,301 509,710 5,996,077 2,210,424 1,040,568 411,837 17 PERCENT INCREASE PROPOSED 17.6131% (245) 23.476% 17.022% 15.581% 35.328% 12.863% 18 PROPOSED RATE OF RETURN 8.08% -15.831% 8.08% 8.08% 8.08% 8.08% 8.08% 19 RETURN REQ FOR PROPOSED REV 18,571,750 8.08% 625,668 10,976,158 4,740,788 1,175,788 1,053,097 20 ANNUAL BOOKED CCF SALES 181,755,519 250 2,735,824 77,056,777 44,020,598 17,324,205 40,614,110 4,005 21 SALES REV REQUIRED $/CCF $0.3736 $0.9799 $0.5349 $0.3725 $0.2301 $0.0890 22 REVENUE DEFICIENCY $/CCF $0.0559 $0.3247 $0.1863 $0.0778 $0.0502 $0.0601 $0.0101 -$0.0611
PRINT DATE 8/30/2006 PRINT TIME 9:10 AM Page 25-1 DPLGasCOSNew-MAC-8-29-06.xls COST OF SERVICE Direct Testimony of Paul M. Normand PSC Docket No. 06-
SCHEDULE PMN-4
ACCOUNTING CLASS COST OF SERVICE
UNBUNDLED SUMMARY RESULTS
rI DELMARVA POWER & LIGHT Page 1-1 GAS COST OF SERVICE STUDY FOR THE 12 MONTHS ENDING MARCH 31,2006 DELAWARE
MEDIUM LARGE TOTAL RESIDENTIAL GENERAL VOLUME VOLUME COMPANY RESIDENTIAL HEATING SERVICE GENERAL GENERAL LIGHTING (1) PRESENT RATE OF RETURN SUMMARY SCHEDULE - FUNCTION FORMAT (2) (3) (4) (5) (6) (7)
RATE OF RETURN 5.43% 4.14% 5.44% 5.82% 3.80% 6.19% 12.81% REVENUES REQUIRED ------1 DEMAND COMPONENTS 30,972,061 308,327 16,756,934 8,620,058 2 DEMA"lD STORAGE 2,391,526 2,894,739 476 2,495,455 18,782 1 ,436,275 676,386 3 DEMAND TRANSMISSION 207,358 156,654 0 4,993,768 47,708 2,541,062 1,321,707 4 DEMAND DISTRIBUTION 394,366 688,842 82 23,482,837 241,837 12,779,597 6,621,965 5 COMMODITY COMPONENTS 1,789,802 2,049,243 394 3,407,750 46,034 1,967,857 1,057,768 193,617 6 COMMODITY STORAGE 142,402 72 1,659,689 15,188 1,016,268 518,437 7 OTHER COMMODITY 72,854 36,944 0 1,748,061 30,847 951,589 539,331 8 CUSTOMER COMPONENTS 120,764 105,459 72 23,352,126 1,816,791 16,500,469 4,509,064 360,314 164,491 9 CUSTOMER DISTRIBUTION 997 0 0 0 0 10 CUSTOMER ACCT 380 SERVICES 0 0 0 11,221,650 787,611 8,177,393 2,053,339 122,506 11 CUSTOMER ACCT 381 METERS 80,342 460 6,527,097 477,136 3,914,229 1,894,396 12 CUSTOMER OTHER DISTR 186,843 54,493 0 0 0 0 0 0 13 CUSTOMER ADVANCES 0 0 (19,260) (1,546) 14 CUSTOMER DEPOSITS (16,111) (1,603) 0 0 0 (107,607) (6,173) (91,760) (9,675) 0 0 15 CUSTOMER ACCT 902 METER RDG 2,299,542 0 218,708 1,784,289 240,252 35,545 20,749 0 16 CUSTOMER ACCT 903 CUST REC & COLL 3,507,956 345,353 2,779,526 351,604 18,911 12,023 538 17 CUSTOMER OTHER 0 0 0 0 0 0 0 18 CUSTOMER SERV & INFO 9,682 563 6,039 1,545 452 1,082 1 19 CUSTOMER OTHER 0 0 0 0 0 0 0 20 CUSTOMER NON FIRM TRANS (86,934) (4,862) (53,136) (20,793) (3,942) (4,200) (1) 21 TOTAL COMPANY 57,731,937 57,731,937 2,171,153 35,225,260 14,186,890 2,945,458 3,201,632 57,731,937 1,545 22 ANNUAL BOOKED CCF SALES 181,755,519 2,735,824 77,056,777 44,020,598 17,324,205 40,614,110 57,731,937 4,005 57,731,937 2,171,153 35,225,260 14,186,890 2,945,458 3,201,632 1,545 23 TOTAL ANNUAL CUSTOMERS 1,411,392 145,440 1,155,708 108,984 840 204 216 24 CUSTOMER $/MONTH/CUSTOMER $16.55 $12.49 $14.28 $41.37 $428.95 $806.33 $4.62
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SCHEDULE PMN-5
ACCOUNTING CLASS COST OF SERVICE
DETAILED RESULTS
rm DELMARVA POWER & LIGHT Page 1-1 29-Aug-06 19:13 GAS COST OF SERVICE STUDY FOR THE 12 MONTHS ENDING MARCH 31,2006 DELAWARE
TRAN & DIST 73% DEM & 27% COMM ALLOC MEDIUM LARGE DISTR MAINS 75% DEM & 25% COMM ALLOC TOTAL RESIDENTIAL GENERAL VOLUME VOLUME COMPANY RESIDENTIAL HEATING SERVICE GENERAL GENERAL LIGHTING ALLOC (1) (2) (3) SUMMARY OF RESUL TS-1 (4) (5) (6) (7)
DEVELOPMENT OF RATE BASE 1 GAS PLANT IN SERVICE PAGE 4 356,107,669 12,922,648 211,366,506 88,790,953 22,225,326 20,797,384 4,852 2 LESS: RESERVE FOR DEPRECIATION PAGE 5 144,732,298 5,252,555 86,145,634 36,059,155 9,019,207 8,253,801 1,947 3 NET PLANT IN SERVICE 211,375,370 7,670,092 125,220,872 52,731,798 13,206,119 12,543,584 2,905 4 PLUS: CWIP PAGE 6 7,309,188 241,177 4,278,721 1,839,808 480,184 469,205 93 5 PLUS: MATERIALS & SUPPLIES PAGE 6 18,281,431 234,986 11,141,171 5,358,024 1,157,435 389,805 9 6 PLUS: CASH WORKING CAPITAL PAGE 7 9,339,527 254,841 5,310,083 2,596,383 655,543 522,435 243 7 PLUS: MISC RATE BASE ITEMS PAGE 6 10,336,893 485,720 6,372,307 2,391,421 565,055 522,211 180 8 LESS: DEFERRED FIT PAGE 8 18,253,777 662,404 10,834,468 4,551,349 1,139,251 1,066,056 249 9 LESS: DEFERRED SIT PAGE 8 5,110,514 185,453 3,033,328 1,274,242 318,956 298,464 70 10 LESS: ACCUM ITC PAGE 8 904,630 35,087 542,138 223,761 54,295 49,336 13 11 LESS: CUSTOMER ADVANCES PAGE 8 207,715 21,425 170,253 16,037 0 0 0 12 LESS: CUSTOMER DEPOSITS PAGE 8 2,317,383 239,034 1,899,429 178,920 0 0 0 13 TOTAL RATE BASE 229,848,390 7,743,414 135,843,538 58,673,124 14,551,832 13,033,383 3,099 DEVELOPMENT OF RETURN 14 OPERATING REVENUES PAGE 9 58,727,645 2,209,883 36,041,160 14,307,503 2,955,767 3,211,785 1,548 OPERATING EXPENSES 15 OPERATION & MAINTENANCE PAGE 14 25,155,705 1,191,687 16,081,629 5,448,787 1,265,072 1,167,827 703 16 DEPRECIATION & AMORT EXPENSE PAGE 15 12,231,041 454,382 7,295,582 3,050,832 751,013 679,062 171 17 TAXES OTHER THAN INCOME TAX PAGE 15 3,601,232 136,764 2,150,520 887,700 220,357 205,840 51 18 INCOME TAXES PAGE 15 5,314,754 104,223 3,146,810 1,528,427 174,472 360,594 227 19 INVESTMENT TAX CREDIT DEF-NET PAGE 15 (66,463) (2,597) (39,852) (16,384) (3,984) (3,645) 20 INTEREST ON CUSTOMER DEPOSITS PAGE 15 63,573 (1) 6,557 52,107 4,908 0 0 0 21 TOTAL EXPENSES 46,299,843 1,891,017 28,686,796 10,904,271 2,406,930 2,409,678 1,151 22 OPERATING INCOME 12,427,802 318,866 7,354,364 3,403,232 548,837 802,107 396 23 AFUDC PAGE 15 56,226 1,643 31,991 14,194 3,971 4,427 24 TOTAL EARNINGS 12,484,028 320,509 7,386,355 3,417,426 552,808 806,534 397 25 RATE OF RETURN 5.43% 4.14% 5.44% 5.82% 3.80% 6.19% 12.81% 26 INDEX RATE OF RETURN 1.00 0.76 1.00 1.07 0.70 1.14 2.36
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TRANSMISSION PLANT 1 365.1-LAND & LAND RIGHTS DEMTRAN 56,104 601 28,451 2 365.2-RIGHTS OF WAY 14,495 5,188 7,367 1 DEMTRAN 192,269 2,060 3 366-STRUCTURES & IMPROVEMENT 97,504 49,675 17,780 25,248 2 DEMTRAN 580,273 6,218 4 367-MAINS 294,269 149,920 53,662 76,199 6 DEMTRAN 29,434,997 315,403 5 368-COMPRESSOR STATION EQ 14,927,124 7,604,848 2,722,041 3,865,276 304 DEMTRAN 0 0 6 369-MEAS & REG STATION EQUIP 0 0 0 0 0 DEMTRAN 3,595,879 38,531 7 1,823,548 929,034 332,534 472,195 37 370-COMMUNICATION EQUIP DEMTRAN 0 0 0 0 0 0 8 371-0THER EQUIPMENT DEMTRAN 0 0 0 0 0 0 9 TOTAL TRANSMISSION PLANT 33,859,522 0 0 362,813 17,170,897 8,747,972 3,131,204 4,446,286 350 DISTRIBUTION PLANT 10 374.1-LAND DEMDIST 24,197 262 12,375 6,305 2,191 3,064 11 374.2-LAND RIGHTS DEMDIST 53,561 0 579 27,393 13,957 4,851 6,782 12 375-STRUCTURES & IMPROV DEMDIST 389,413 1 4,210 199,157 101,470 35,266 49,306 13 376-MAINS DEMMAIN 162,044,819 4 1,854,585 88,198,452 44,895,296 14,159,258 12,935,450 14 378-MEAS & REG EQUIP - GEN DEMDIST 3,723,216 1,778 40,248 1,904,162 970,166 337,179 471,422 15 380-SERVICES CUST380 82,223,836 39 6,395,105 59,550,436 14,679,484 1,035,316 561,326 16 381-METERS CUST381 35,875,025 2,170 2,848,344 21,377,747 10,207,164 1,153,498 288,272 17 385-INDUST MEAS & REG EQUIP DEMDIST 57,138 0 618 29,222 14,888 5,174 7,235 18 387-0THER EQUIPMENT DEMDIST 0 1 0 0 0 0 0 19 ASSET RETIREMENT OBLIGATION CUST381 30,168 0 2,395 17,977 8,584 970 242 20 TOTAL DISTRIBUTION PLANT 284,421,373 0 11,146,346 171,316,920 70,897,313 16,733,703 14,323,099 3,992
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INTANGIBLE PLANT INTPLT 1,737,389 61,536 1,028,023 435,674 109,520 102,613 23 2 OTHER STORAGE PLANT STORPL T 7,352,147 56,654 4,212,866 1,988,653 634,854 459,120 0 3 TRANSMISSION PLANT TRANPL T 10,571,669 113,278 5,361,122 2,731,304 977,629 1,388,226 109 4 DISTRIBUTION PLANT DISTPL T 108,565,397 4,254,629 65,392,728 27,061,943 6,387,358 5,467,215 1,524 5 GENERAL PLANT GENPL T 3,874,365 182,134 2,388,574 896,191 211,729 195,670 68 6 COMMON PLANT COMPL T 10,226,880 . 471,292 6,279,959 2,389,209 566,716 519,522 181 7 CONECTIV RESOURCE PARTNERS RES CRPPL T 2,404,451 113,033 1,482,362 556,181 131,400 121,434 42 8 TOTAL RESERVE FOR DEPRECIATION 144,732,298 5,252,555 86,145,634 36,059,155 9,019,207 8,253,801 1,947 9 NET PLANT IN SERVICE 211,375,370 7,670,092 125,220,872 52,731,798 13,206,119 12,543,584 2,905
PRINT DATE 8/30/2006 PRINT TIME 9:13 AM Page 5-1 DPLGasCOSNew-MAC-8-29-06.xls COST OF SERVICE DELMARVA POWER & LIGHT Page 6-1 29-Aug-06 19:13 GAS COST OF SERVICE STUDY FOR THE 12 MONTHS ENDING MARCH 31, 2006 DELAWARE
TRAN & DIST 73% DEM & 27% COMM ALLOC MEDIUM DISTR MAINS 75% DEM & 25% COMM ALLOC LARGE TOTAL RESIDENTIAL GENERAL VOLUME VOLUME COMPANY RESIDENTIAL HEATING SERVICE GENERAL GENERAL LIGHTING ALLOC (1) (2) (3) DEVELOP OF RATE BASE CON'T-6 (4) (5) (6) (7)
ADDITIONS TO NET PLANT:
CONST WORK IN PROGRESS 1 INTANGIBLE PLANT INTPL T 0 0 0 0 0 0 0 2 OTHER STORAGE PLANT STORPL T 370,223 2,853 212,142 100,140 31,969 23,119 0 3 TRANSMISSION PLANT TRANPL T 1,193,530 12,789 605,265 308,361 110,373 156,729 12 4 DISTRIBUTION PLANT DISTPL T 5,691,271 223,038 3,428,051 1,418,655 334,841 286,605 80 5 GENERAL PLANT GENPL T 1,109 52 684 257 61 6 COMMON PLANT 56 0 COMPL T 53,054 2,445 32,579 12,394 2,940 2,695 7 TOT CONSTR WORK IN PROG 7,309,188 1 241,177 4,278,721 1,839,808 480,184 469,205 93 8 NET PLANT IN SERVICE & CWiP 218,684,558 7,911,270 129,499,593 54,571,606 13,686,303 13,012,788 2,998 ADDITIONS TO RATE BASE
OTHER RATE BASE ITEMS MATERIALS & SUPPLIES 9 GAS IN STORAGE - PIPELINE ESTOR 17,603,038 210,455 10,739,423 5,188,266 1,115,094 349,799 0 10 PLANT M&S - T&D PL T TDPL T 678,393 24,531 401,748 169,758 42,341 40,006 9 11 TOTAL MATERIALS & SUPPLIES 18,281,431 234,986 11,141,171 5,358,024 1,157,435 389,805 9 12 PREPAID PENSION (LABOR) LABOR 10,316,707 484,988 6,360,325 2,386,387 563,795 521,032 180 13 WORKING FUNDS PLANT 0 0 0 0 0 0 0 14 PREPAID INSURANCE PLANT 20,186 733 11,981 5,033 1,260 1,179 0 15 PLANT HELD FOR FUTURE USE DISTPL T 0 0 0 0 0 0 16 TOTAL OTHER RATE BASE ITEMS 0 28,618,324 720,706 17,513,478 7,749,445 1,722,489 912,016 189
PRINT DATE 8/30/2006 PRINT TIME 9:14 AM Page 6-1 DPLGasCOSNew-MAC-8-29-06.xls COST OF SERVICE DELMARVA POWER & LIGHT Page 7-1 29-Aug-06 19:13 GAS COST OF SERVICE STUDY FOR THE 12 MONTHS ENDING MARCH 31, 2006 DELAWARE TRAN & DIST 73% DEM & 27% COMM ALLOC MEDIUM LARGE DISTR MAINS 75% DEM & 25% COMM ALLOC TOTAL RESIDENTIAL GENERAL VOLUME VOLUME COMPANY RESIDENTIAL HEATING SERVICE GENERAL GENERAL ALLOC LIGHTING (1) (2) DEVELOP OF RATE BASE CON'T-7 (3) (4) (5) (6) (7)
CASH WORKING CAPITAL 1 PURCHASED GAS ESALES 6,093,214 117,218 3,301,534 2 OTHER PRODUCTION 1,845,072 474,649 354,569 172 STOREXP 149,424 1,822 3 TRANSMISSION 83,809 42,296 12,411 9,084 2 TRANEXP 88,869 952 45,067 4 DISTRIBUTION 22,960 8,218 11,670 1 DISTEXP 669,648 26,797 398,527 5 OTHER O&M 168,949 39,655 35,710 9 WCOTHOM 919,375 57,076 641,098 161,363 31,520 28,278 40 6 UTILITY TAXES CLAIM REV 119,452 4,716 72,518 28,847 7,012 6,357 7 PAYROLL TAXES LABOR 58,100 2 2,731 35,819 13,439 3,175 8 PROPERTY TAXES PLANT 2,934 1 1,183,069 42,932 702,206 294,983 73,837 9 FIT PLANT 69,094 16 365,152 13,251 216,735 91,046 22,790 10 SIT PLANT 21,326 5 278,881 10,120 165,529 69,535 17,405 11 INTEREST EXPENSE PLANT 16,287 4 (565,139) (20,508) (335,436) 12 IOCD CUSTDEP (140,910) (35,271) (33,005) (8) (22,761) (2,348) (18,656) ° 13 DEPRECIATION & AMORTIZATION PLANT (1,757) ° ° ° ° ° ° ° 14 PREFERRED DIVIDENDS PLANT 2,245 ° ° 81 1,333 560 140 131 15 TOTAL CASH WORKING CAPITAL 9,339,527 ° 254,841 5,310,083 2,596,383 655,543 522,435 243
PRINT DATE 8/30/2006 PRINT TIME 9:14 AM Page 7-1 DPLGasCOS New-MAC-8-29-06.xls COST OF SERVICE DELMARVA POWER & LIGHT Page 8-1 29-Aug-06 19:13 GAS COST OF SERVICE STUDY FOR THE 12 MONTHS ENDING MARCH 31, 2006 DELAWARE
TRAN & DIST 73% OEM & 27% COMM ALLOC MEDIUM LARGE DISTR MAINS 75% OEM & 25% COMM ALLOC TOTAL RESIDENTIAL GENERAL VOLUME VOLUME COMPANY RESIDENTIAL HEATING SERVICE GENERAL GENERAL LIGHTING ALLOC (1) (2) DEVELOP OF RATE BASE CON'T-8 (3) (4) (5) (6) (7)
DEDUCTIONS FROM RATE BASE
1 CUSTOMER ADVANCES CUSTADV 207,715 21,425 170,253 16,037 0 0 0 2 CUSTOMER DEPOSITS CUSTDEP 2,317,383 239,034 1,899,429 178,920 0 0 0 ACCUM DEFERRED FIT TAX 3 PENSION CREDIT LABOR 0 0 0 0 0 0 0 4 PLANT RELATED PLANT 18,253,777 662,404 10,834,468 4,551,349 1,139,251 1,066,056 249 5 TOTAL ACCUM DEF FIT TAX 18,253,777 662,404 10,834,468 4,551,349 1,139,251 1,066,056 249 ACCUM DEFERRED SIT TAX 6 PENSION CREDIT LABOR 0 0 0 0 0 0 0 7 PLANT RELATED PLANT 5,110,514 185,453 3,033,328 1,274,242 318,956 298,464 70 8 TOTAL ACCUM DEF SIT TAX 5,110,514 185,453 3,033,328 1,274,242 318,956 298,464 70 ACCUM ITC 9 INTANGIBLE PLANT INTPLT 0 0 0 0 0 0 0 10 OTHER STORAGE PLANT STORPL T 0 0 0 0 0 0 0 11 TRANSMISSION PLANT TRANPLT 46,060 494 23,358 11,900 4,259 6,048 0 12 DISTRIBUTION PLANT DISTPL T 724,836 28,406 436,594 180,679 42,645 36,502 10 13 GENERAL PLANT GENPL T 26,535 1,247 16,359 6,138 1,450 1,340 0 14 COMMON PLANT COMPL T 107,199 4,940 65,827 25,044 5,940 5,446 2 15 TOT ACCUM ITC 904,630 35,087 542,138 223,761 54,295 49,336 13 16 TOTAL RATE BASE 229,848,390 7,743,414 135,843,538 58,673,124 14,551,832 13,033,383 3,099
PRINT DATE 8/30/2006 PRINT TIME 9:14 AM Page 8-1 DPLGasCOSNew-MAC-8-29-06.xls COST OF SERVICE DELMARVA POWER & LIGHT Page 9-1 29-Aug-06 19:13 GAS COST OF SERVICE STUDY FOR THE 12 MONTHS ENDING MARCH 31, 2006 DELAWARE TRAN & DIST 73% DEM & 27% COMM ALLOC MEDIUM LARGE DISTR MAINS 75% OEM & 25% COMM ALLOC TOTAL RESIDENTIAL GENERAL VOLUME VOLUME COMPANY RESIDENTIAL HEATING SERVICE GENERAL ALLOC GENERAL LIGHTING (1) (2) OPERATING REVENUES-9 (3) (4) (5) (6) (7)
GAS OPERATING REVENUES
TOTAL REV FIRM SALE OF GAS 57,731,937 2,171,153 35,225,260 14,186,890 2,945,458 3,201,632 1,545 OTHER OPERATING REVENUES 2 LATE PAYMENT REVENUE-GAS UNCOLL 807,726 30,229 702,997 74,500 0 0 3 MISC SERVICE REVENUE - GAS PLANT 15,721 0 571 9,331 3,920 981 918 4 OTHER REVENUE RENT PLANT 86,929 0 3,155 51,597 21,675 5,425 5,077 5 UN BILLED REVENUE ESALES 0 1 0 0 0 0 6 INTERRUPTIBLE TRANSPORTATION CINTMARG 0 0 989,245 55,361 602,537 237,884 45,248 7 OFF-SYSTEM SALES - GAS REG ESALES 48,202 12 (4) (0) (2) 8 CASH OUT REVENUE ESALES (1) (0) (0) (0) (16) (0) (8) 9 IT REVENUE CREDITS CINTMARG (5) (1) (1) (0) (903,895) (50,584) 10 UTILITY TAX - OTHER (550,552) (217,360) (41,344) (44,043) (11) ESALES 0 0 11 TOTAL OTHER OPERATING REVENUE 0 0 0 0 0 995,708 38,730 815,900 120,613 10,309 10,153 2 12 TOTAL OPERATING REVENUES 58,727,645 2,209,883 36,041,160 14,307,503 2,955,767 3,211,785 1,548
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CUSTOMER ACCOUNTS EXPENSES 1 901-SUPERVISION TLABCA 0 0 2 902-METER READING EXPENSE 0 0 0 0 0 CUST902 1,170,840 113,933 3 903-CUST RECORDS & COLL EXP 905,347 122,246 18,785 10,529 0 CUST903 2,856,366 284,230 4 904-UNCOLLECTIBLE ACCOUNTS 2,258,571 287,573 15,728 9,842 422 UNCOLL 1,364,035 51,049 5 905-MISCEL CUST ACCTS EXP 1,187,175 125,810 0 0 0 EXP9023 2,875 284 6 TOTAL CUSTOMER ACCTS EXPENSE 2,259 293 25 15 0 5,394,116 449,496 4,353,352 535,922 34,537 20,386 422 CUSTOMER SERVICE & INFO EXP 7 907-SUPERVISION TLABCS (9) 8 908-CUSTOMER ASSISTANCE EXP (1) (5) (1) (0) (1) CSERV 5,869 347 3,647 (0) 9 909-INFO & INSTRUCT EXP 937 281 656 1 CSERV 673 40 10 910-MISC CUST SERV & INFO EX 418 108 32 75 0 CSERV 0 0 11 TOTAL CUST SERVICE & INFO EXP 0 0 0 0 0 6,533 386 4,060 1,043 313 730 1
PRINT DATE 8/3012006 PRINT TIME 9:15 AM Page 13-1 DPLGasCOSNew-MAC-8-29-06.xls COST OF SERVICE DELMARVA POWER & LIGHT Page 14-1 29-Aug-06 19:13 GAS COST OF SERVICE STUDY FOR THE 12 MONTHS ENDING MARCH 31, 2006 DELAWARE
TRAN & DIST 73% DEM & 27% GOMM ALLOC MEDIUM LARGE DISTR MAINS 75% DEM & 25% COMM ALLOC TOTAL RESIDENTIAL GENERAL VOLUME VOLUME COMPANY RESIDENTIAL HEATING SERVICE GENERAL GENERAL LIGHTING ALLOC (1) (2) (3) (4) (5) (6) OPERATION & MAl NT EXP CON'T-14 (7)
ADMINISTRATIVE & GENERAL EXP OPERATION 1 920-ADMIN & GENRL SALARIES LABOR 639,586 30,067 394,309 147,944 34,953 32,301 11 2 921-0FFICE SUPPLIES & EXP LABOR 62,774 2,951 38,700 14,520 3,430 3,170 1 3 922-ADMIN EXP TRANSF-CREDIT LABOR 0 0 0 0 0 0 0 4 923-0UTSIDE SERVICES EMPLOY LABOR 3,436,393 161,545 2,118,561 794,882 187,794 173,551 60 5 924-PROPERTY INSURANCE PLANT 96,572 3,504 57,320 24,079 6,027 5,640 1 6 925-INJURIES & DAMAGES LABOR 53,401 2,510 32,922 12,352 2,918 2,697 1 7 926-EMPLOYEE PENSNS & BENE LABOR 2,625,648 123,432 1,618,731 607,346 143,488 132,605 46 8 928-REGULATRY COMMISSION EX CLAIMREV 637,661 25,176 387,115 153,989 37,433 33,935 12 9 929-DUPLICATE CHARGES-CR. LABOR (1,512,638) (71,109) (932,552) (349,893) (82,664) (76,394) (26) 10 930.1-GENERL ADVERTISING EX LABOR 339 16 209 78 19 17 0 11 930.2-MISC GENERL EXP LABOR 425,072 19,983 262,060 98,325 23,230 21,468 7 12 931-RENTS LABOR 615,710 28,944 379,590 142,422 33,648 31,096 13 TOTAL OPERATION EXPENSE 11 7,080,518 327,019 4,356,966 1,646,046 390,277 360,086 124 MAINTENANCE 14 935-MAINT OF GENERAL PLANT GENPL T 136,384 6,411 84,082 31,547 7,453 6,888 15 TOTAL MAINTENANCE EXPENSE 2 136,384 6,411 84,082 31,547 7,453 6,888 2 16 TOTAL ADMIN & GENERAL EXPENSE 7,216,902 333,431 4,441,048 1,677,593 397,730 366,973 127 17 TOTAL OPERATION & MAINT EXP 25,155,705 1,191,687 16,081,629 5,448,787 1,265,072 1,167,827 703
PRINT DATE 8/30/2006 PRINT TIME 9:15 AM Page 14-1 DPLGasCOSNew-MAC-8-29-06.xls COST OF SERVICE DELMARVA POWER & LIGHT Page 15-1 29-Aug-06 19:13 GAS COST OF SERVICE STUDY FOR THE 12 MONTHS ENDING MARCH 31, 2006 DELAWARE TRAN & DIST 73% OEM & 27% COMM ALLOC MEDIUM DISTR MAINS 75% OEM & 25% COMM ALLOC TOTAL LARGE RESIDENTIAL GENERAL VOLUME COMPANY VOLUME RESIDENTIAL HEATING SERVICE ALLOC GENERAL GENERAL LIGHTING (1) (2) DEPRECIATION & AMORT EXP-15 (3) (4) (5) (6) (7)
DEPRECIATION EXPENSE 1 TOTAL INTANGIBLE PLANT INTPL T 0 0 2 OTHER STORAGE PLANT 0 0 0 0 0 STORPL T 324,014 2,497 3 TRANSMISSION PLANT 185,664 87,641 27,978 20,234 0 TRANPL T 710,591 7,614 4 DISTRIBUTION PLANT 360,356 183,589 65,713 93,312 7 DISTPL T 9,841,783 385,695 5 GENERAL PLANT 5,928,049 2,453,247 579,033 495,620 138 GENPL T 445,830 20,958 6 COMMON PLANT 274,858 103,126 24,364 22,516 8 COMPL T 451,567 20,810 7 TOTAL DEPRECIATION EXP 277,291 105,495 25,023 22,939 8 11,773,785 437,574 7,026,218 2,933,099 722,112 654,621 161 AMORTIZATION EXPENSE 8 INTANGIBLE SOFTWARE LABOR 4,186 197 2,581 968 229 9 INTANGIBLE OTHER INTPL T 211 0 8,833 313 5,227 2,215 10 ASSET RETIREMENT OBLIGATION CUST381 557 522 0 (91) (7) (54) 11 COMMON MIPR SOFTWARE LABOR 279,322 (26) (3) (1) 0 13,131 172,204 64,611 15,265 12 GAS PILOT CUSTOMER CHOICE ESALES 165,006 14,107 5 3,174 89,406 49,965 12,854 13 TOTAL AMORTIZATION EXP 457,256 9,602 5 16,808 269,364 117,733 28,901 12,231,041 24,441 10 TAXES OTHER THAN INCOME TAXES 14 PAYROLL TAXES LABOR 567,083 26,659 15 PROPERTY TAXES 349,611 131,174 30,990 28,640 10 PLANT 3,034,149 110,105 16 REGULATORY TAX 1,800,909 756,527 189,367 177,200 41 CLAIMREV 0 0 17 TOTAL TAXES OTHER THAN INCOME 0 0 0 0 0 3,601,232 136,764 2,150,520 887,700 220,357 205,840 51 18 TOTALINCOME TAXES 12,464,262 343,216 19 TOTAL DEFERRED INCOME TAXES 7,334,886 3,372,875 640,473 772,477 335 (7,149,508) 20 INVESTMENT TAX CREDIT ADJ-NET (238,993) (4,188,076) (1,844,449) (466,001) (66,463) (411,883) (107) TOTAL TAX EXPENSE (2,597) (39,852) (16,384) (3,984) (3,645) ;11 5,248,291 101,627 (1) 3,106,958 1,512,043 170,488 356,950 226 22 TOTAL OPERATING EXPENSES 46,236,270 1,884,459 28,634,689 10,899,363 2,406,930 2,409,678 1,151 23 NET OPERATING INCOME 12,491,375 325,424 7,406,471 3,408,140 548,837 802,107 396 AFUDC 24 TRANSMISSION RELATED TRANPL T 19,707 211 25 DISTRIBUTION RELATED 9,994 5,091 1,822 2,588 0 DISTPL T 36,471 1,429 21,968 26 GENERAL RELATED 9,091 2,146 1,837 1 GENPL T 48 2 27 TOTAL AFUDC 30 11 3 2 0 56,226 1,643 31,991 14,194 3,971 4,427 1 28 INTEREST ON CUSTOMER DEPOSITS CUSTDEP (63,573) (6,557) (52,107) (4,908) 0 0 0 29 TOTAL EARNINGS 12,484,028 320,509 7,386,355 3,417,426 552,808 806,534 397
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INTEREST CHARGES 1 INTEREST ON LONG TERM DEBT PLANT 5,429,744 197,038 3,222,806 1,353,838 338,880 317,108 74 2 AMORT OF PREMIUM I DISCOUNT PLANT a a a a a a a 3 OTHER INTEREST CHARGES PLANT a a a a a a a 4 TOTAL INTEREST CHARGES 5,429,744 197,038 3,222,806 1,353,838 338,880 317,108 74 5 GAIN ON DISPOSAL OF PROPERTY PLANT 24,450 887 14,512 6,096 1,526 1,428 a 6 STATE TAXABLE INCOME 30,658,620 844,217 18,041,781 8,296,336 1,575,385 1,900,079 823 7 STATE INCOME TAX ig 8.70% 2,667,300 73,447 1,569,635 721,781 137,058 165,307 8 OTHER STATE INCOME TAXES PLANT 72 a a a a a a a 9 TOT DELAWARE STATE INCOME TAX 2,667,300 73,447 1,569,635 721,781 137,058 165,307 72 10 FEDERAL TAXBLE INCOME 27,991,320 770,770 16,472,146 7,574,555 1,438,326 1,734,772 752 11 FEDERAL TAXES ig 35.00% 9,796,962 269,769 5,765,251 2,651,094 503,414 607,170 263 12 OTHER FEDERAL INCOME TAXES PLANT a a a a a a a 13 TOTAL FEDERAL INCOME TAXES 9,796,962 269,769 5,765,251 2,651,094 503,414 607,170 263 14 CURRENT FED & STATE INC TAXES 12,464,262 343,216 7,334,886 3,372,875 640,473 772,477 335
PRINT DATE 8/30/2006 PRINT TIME 9:16 AM Page 17-1 DPLGasCOSNew-MAC-8-29-06.xls COST OF SERVICE DELMARVA POWER & LIGHT Page 18-1 29-Aug-06 19:13 GAS COST OF SERVICE STUDY FOR THE 12 MONTHS ENDING MARCH 31, 2006 DELAWARE TRAN & DIST 73% DEM & 27% COMM ALLOC MEDIUM LARGE DISTR MAINS 75% DEM & 25% COMM ALLOC TOTAL RESIDENTIAL GENERAL VOLUME VOLUME COMPANY RESIDENTIAL HEATING SERVICE GENERAL GENERAL LIGHTING ALLOC (1) (2) DEVEL OF INCOME TAXES - CON'T-18 (3) (4) (5) (6) (7)
DEFERRED STATE INCOME TAX 1 WORKMEN'S COMP LABOR 3,513 165 2,166 813 2 HEALTH CLAIMS 192 177 0 LABOR (788) (37) 3 CLAIMS RESERVE (486) (182) (43) (40) (0) LABOR (3,492) (164) 4 WILMINGTON SITE CLEANUP (2,153) (808) (191) (176) (0) PLANT (9,238) (335) 5 DEFERRED COMPo BASE SALARY DEF LABOR (5,483) (2,303) (577) (540) (0) (3,201) (150) (1,973) (740) (175) 6 BOOK GAIN ON ASSET DISPOSITION PLANT 10,911 (162) (0) 396 6,476 2,721 681 637 0 7 EXCESS PROPERTY VALUE RESERVE PLANT 0 0 0 0 0 0 0 8 SERP LABOR (3,586) (169) (2,211) (829) (196) (181) (0) 9 DEFERRED FUEL GCRFUEL (201,765) (3,829) (109,879) (61,805) (16,143) (10,104) 10 DEFERRED FUEL INTEREST GCRFUEL 4,708 (5) 89 2,564 1,442 377 236 0 11 PENSION CREDIT LABOR 77,145 3,627 47,560 17,845 4,216 3,896 12 REACQUIRED DEBT PLANT 1 (6,235) (226) (3,701) (1,555) 13 ACCRUED VACATION EXPENSE LABOR (389) (364) (0) (5,709) (268) (3,520) (1,321) (312) (288) 14 JOBBING FOR CONSTRUCTION REV PLANT 0 (0) 0 0 0 0 0 0 15 MEALS & ENTERTAINMENT LABOR 0 0 0 0 0 0 0 16 MEDICARE SUBSIDY LABOR 0 0 0 0 0 0 0 17 PLANT RELATED PLANT (1,344,200) (48,779) (797,845) (335,159) (83,894) (78,504) (18) 18 TOTAL DEF STATE INCOME TAX (1,481,936) (49,681) (868,484) (381,883) (96,453) (85,413) (22) DEFERRED FEDERAL INCOME TAX 19 WORKMEN'S COMP LABOR 14,063 661 8,670 3,253 769 20 HEALTH CLAIMS 710 0 LABOR (3,153) (148) (1,944) 21 CLAIMS RESERVE (729) (172) (159) (0) LABOR (13,974) (657) (8,615) 22 WILMINGTON SITE CLEANUP (3,232) (764) (706) (0) PLANT (36,986) (1,342) (21,953) 23 DEFERRED COMPo BASE SALARY DEF LABOR (9,222) (2,308) (2,160) (1) (12,813) (602) (7,899) (2,964) (700) (647) 24 BOOK GAIN ON ASSET DISPOSITION PLANT 43,683 (0) 1,585 25,928 10,892 2,726 2,551 1 25 EXCESS PROPERTY VALUE RESERVE PLANT 0 0 0 0 0 0 0 26 SERP LABOR (14,347) (674) (8,845) (3,319) (784) 27 DEFERRED FUEL GCRFUEL (725) (0) (805,372) (15,284) (438,597) (246,703) 28 DEFERRED FUEL INTEREST (64,435) (40,332) (20) GCRFUEL 18,832 357 10,256 5,769 1,507 29 PENSION CREDIT 943 0 LABOR 308,711 14,512 190,323 71,409 REACQUIRED DEBT 16,871 15,591 5 30 PLANT (24,963) (906) (14,817) (6,224) (1,558) (1,458) (0) 31 ACCRUED VACATION EXPENSE LABOR (22,856) (1,074) (14,091) (5,287) (1,249) (1,154) (0) 32 JOBBING FOR CONSTRUCTION REV PLANT 0 0 0 0 0 0 0 33 MEALS & ENTERTAINMENT LABOR 0 0 0 0 0 0 0 34 MEDICARE SUBSIDY LABOR 0 0 0 0 0 0 0 35 PLANT RELATED PLANT (5,118,397) (185,739) (3,038,007) (1,276,208) (319,448) (298,924) (70) 36 TOTAL DEF FEDERAL INCOME TAX (5,667,572) (189,312) (3,319,592) (1,462,566) (369,547) (326,470) (85)
PRINT DATE 8/30/2006 PRINT TIME 9:16 AM Page 18-1 DPLGasCOSNew-MAC-8-29-06.xls COST OF SERVICE DELMARVA POWER & LIGHT Page 19-1 29-Aug-06 19:13 GAS COST OF SERVICE STUDY FOR THE 12 MONTHS ENDING MARCH 31, 2006 DELAWARE TRAN & DIST 73% DEM & 27% COMM ALLOC MEDIUM LARGE DISTR MAINS 75% DEM & 25% COMM ALLOC TOTAL RESIDENTIAL GENERAL VOLUME VOLUME COMPANY RESIDENTIAL HEATING SERVICE GENERAL GENERAL ALLOC LIGHTING (1) (2) DEVEL OF INCOME TAXES - CON'T-19 (3) (4) (5) (6) (7)
INVESTMENT TAX CREDIT NET 1 INTANGIBLE RELATED INTPL T o o o o 0 2 OTHER STORAGE RELATED STORPL T 0 0 o o o o 3 TRANSMISSION RELATED TRANPL T 0 0 0 (3,615) (39) (1,833) 4 DISTRIBUTION RELATED DISTPL T (934) (334) (475) (0) (49,387) (1,935) (29,748) 5 GENERAL RELATED GENPL T (12,311) (2,906) (2,487) (1) (2,214) (104) 6 COMMON RELATED COMPL T (1,365) (512) (121) (112) (0) (11,248) (518) 7 TOT INVEST TAX CREDIT NET (6,907) (2,628) (623) (571) (0) (66,463) (2,597) (39,852) (16,384) (3,984) (3,645) (1)
STATE TAX RATE 8.70% FEDERAL TAX RATE - CURRENT 35.00% 1 - EFFECTIVE TAX RATE 0.59869 EFFECTIVE TAX RATE 0.40131 EFFECTIVE FEDERAL RATE 0.31891 TAXABLE INCOME FACTOR 1.67031
PRINT DATE 8130/2006 PRINT TIME 9:16 AM Page 19-1 DPLGasCOSNew-MAC-8-29-06.xls COST OF SERVICE DELMARVA POWER & LIGHT Page 20-1 29-Aug-06 19:13 GAS COST OF SERVICE STUDY FOR THE 12 MONTHS ENDING MARCH 31, 2006 DELAWARE TRAN & DIST 73% DEM & 27% COMM ALLOC MEDIUM LARGE DISTR MAINS 75% OEM & 25% COMM ALLOC TOTAL RESIDENTIAL GENERAL VOLUME VOLUME COMPANY RESIDENTIAL HEATING SERVICE GENERAL ALLOC GENERAL LIGHTING (1) (2) DEV OF LABOR ALLOCATOR-20 (3) (4) (5) (6) (7)
OPERATION & MAINTENANCE LABOR
PURCHASED GAS SUPPLY LABOR 1 807-PURCHASED GAS EXPENSES EXP807 100,236 1,928 2 813-0THER GAS SUPPLY EXP 54,312 30,352 7,808 5,833 3 EXP813 19,026 366 10,309 3 TOTAL GAS SUPPLY LABOR 5,761 1,482 1,107 1 119,262 2,294 64,620 4 TOTAL PRODUCTION LABOR 36,113 9,290 6,940 3 119,262 2,294 64,620 36,113 9,290 6,940 3 LNG STORAGE LABOR OPERATION LABOR 5 840-SUPERVISION & ENGINEER LABSO 0 0 6 841-0PER LABOR & EXPENSES 0 0 0 0 0 EXP841 275,585 2,124 157,913 7 842-POWER (FUEL) 74,542 23,797 17,209 0 EXP842 3,306 25 1,895 8 TOTAL OPERATION LABOR 894 285 206 0 278,891 2,149 159,808 MAINTENANCE 75,436 24,082 17,416 0 9 843.1-MAINT SUPERV & ENGINEER LABSM 0 0 10 843.2-MAINT STUCT & IMPROV 0 0 0 0 0 EXP8432 8,008 62 4,589 11 843.3-MAINT OF GAS HOLDERS 2,166 691 500 0 EXP8433 13,011 100 12 843.4-MAINT OF PURIFICATION EO 7,455 3,519 1,123 812 0 EXP8434 48,662 375 13 843.5-MAINT OF L10UIFACTION EO 27,884 13,162 4,202 3,039 0 EXP8435 118,512 913 67,909 14 843.6-MAINT OF VAPORIZING EO 32,056 10,233 7,401 O' EXP8436 31,953 246 18,309 15 843.7-MAINT OF COMPRESSOR EO 8,643 2,759 1,995 0 EXP8437 24,302 187 13,925 16 843.8-MAINT OF MEAS & REG EO 6,573 2,098 1,518 0 EXP8438 779 6 446 17 843.9-MAINT OF OTHER EQUIP 211 67 49 0 EXP8439 141,391 1,090 81,019 18 38,244 12,209 8,829 0 TOTAL MAINTENANCE LABOR 386,617 2,979 19 TOTAL LNG STORAGE LABOR 221,536 104,574 33,384 24,143 0 665,508 5,128 381,344 180,011 57,466 41,559 0 20 TOTAL PROD & LNG STOR LABOR 784,769 7,423 445,964 216,124 66,756 48,499 3
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CUSTOMER ACCOUNTS LABOR 1 901-SUPERVISION LABCA 0 0 2 902-METER READING EXPENSE 0 0 0 0 0 EXP902 932,062 90,698 3 903-CUST RECORDS & COLL EXP 720,713 97,315 14,954 8,382 0 EXP903 485,330 48,294 4 905-MISCEL CUST ACCTS EXP 383,757 48,862 2,672 1,672 72 EXP905 106 10 83 5 TOTAL CUSTOMER ACCTS LABOR 11 1 1 0 1,417,498 139,002 1,104,554 146,188 17,627 10,054 72 CUSTOMER SERVICE & INFO LABOR 6 907-SUPERVISION LABCS 0 0 7 90B-CUSTOMER ASSISTANCE EXP 0 0 0 0 0 EXP908 2,534 150 8 909-INFO & INSTRUCT EXP 1,575 405 122 283 0 EXP909 0 0 9 910-MISC CUST SERV & INFO EX 0 0 0 0 0 EXP910 0 0 10 TOTAL CUST SERVICE & INFO LABOR 0 0 0 0 0 2,534 150 1,575 405 122 283 0
PRINT DATE 613012006 PRINT TIME 9:17 AM Page 23-1 DPLGasCOSNew-MAC-6-29-06.xls COST OF SERVICE DELMARVA POWER & LIGHT Page 24-1 29-Aug-06 19:13 GAS COST OF SERVICE STUDY FOR THE 12 MONTHS ENDING MARCH 31, 2006 DELAWARE TRAN & DIST 73% DEM & 27% COMM ALLOC DISTR MAINS 75% DEM & 25% COMM ALLOC MEDIUM LARGE TOTAL RESIDENTIAL GENERAL VOLUME COMPANY VOLUME RESIDENTIAL HEATING SERVICE GENERAL ALLOC GENERAL LIGHTING (1) (2) DEVEL OF LABOR ALLOC CON'T-24 (3) (4) (5) (6) (7)
ADMINISTRATIVE & GENERAL LABOR OPERATION 1 920-ADMIN & GENRL SALARIES EXP920 292,755 13,762 180,486 67,718 2 921-0FFICE SUPPLIES & EXP EXP921 15,999 14,785 5 4,659 219 2,872 3 922-ADMIN EXP TRANSF-CREDIT EXP922 1,078 255 235 0 0 0 0 4 923-0UTSIDE SERVICES EMPLOY EXP923 0 0 0 0 91,170 4,286 56,207 5 924-PROPERTY INSURANCE EXP924 21,089 4,982 4,604 2 0 0 0 0 6 925-INJURIES & DAMAGES EXP925 0 0 0 0 0 0 7 926-EMPLOYEE PENSNS & BENE EXP926 0 0 0 0 0 0 0 8 928-REGULATRY COMMISSION EX EXP928 0 0 0 0 6,174 244 3,748 1,491 9 929-DUPLICA TE CHARGES-CR. EXP929 362 329 0 0 0 0 10 930-MISC GENERAL EXP EXP930 0 0 0 0 68,922 3,240 42,491 11 931-RENTS 15,943 3,766 3,481 1 EXP931 0 0 12 TOTAL OPERATION LABOR 0 0 0 0 0 463,680 21,751 MAINTENANCE 285,804 107,318 25,365 23,434 8 13 935-MAINT OF GENERAL PLANT EXP935 29,304 1,378 18,066 6,778 1,601 14 TOTAL MAINTENANCE LABOR 29,304 1,480 1 15 TOTAL ADMIN & GENERAL LABOR 1,378 18,066 6,778 1,601 1,480 492,984 23,129 1 303,870 114,096 26,966 24,914 9 16 TOTAL OPERATION & MAINT LABOR 9,140,975 429,717 5,635,478 2,114,425 499,542 461,653 159
PRINT DATE 8/30/2006 PRINT TIME 9:18 AM Page 24-1 DPLGasCOSNew-MAC-8-29-06.xls COST OF SERVICE DELMARVA POWER & LIGHT Page 25-1 29-Aug-06 19:13 GAS COST OF SERVICE STUDY FOR THE 12 MONTHS ENDING MARCH 31, 2006 DELAWARE TRAN & DIST 73% OEM & 27% COMM ALLOC MEDIUM LARGE DISTR MAINS 75% OEM & 25% COMM ALLOC TOTAL RESIDENTIAL GENERAL VOLUME VOLUME COMPANY RESIDENTIAL HEATING SERVICE GENERAL ALLOC GENERAL LIGHTING (1) (2) REVENUE REQUIREMENTS-25 (3) (4) (5) (6) (7)
PRESENT RATES
1 RATE BASE 229,848,390 7,743,414 2 NET OPER INC (PRESENT RATES) 135,843,538 58,673,124 14,551,832 13,033,383 3,099 12,484,028 320,509 3 RATE OF RETURN (PRES RATES) 7,386,355 3,417,426 552,808 806,534 397 5.4314% 4.1391% 5.4374% 4 RELATIVE RATE OF RETURN 5.8245% 3.7989% 6.1882% 12.8052% 1.00 0.76 5 SALES REVENUE (PRE RATES) 1.00 1.07 0.70 1.14 2.36 57,731,937 2,171,153 6 SALES REV REQUIRED $/CCF 35,225,260 14,186,890 2,945,458 3,201,632 1,545 $0.3176 $0.7936 $0.4571 $0.3223 $0.1700 $0.0788 $0.3858
CLAIMED RATE OF RETURN
7 CLAIMED RATE OF RETURN 8.08% 8.08% 8.08% 8.08% 8.08% 8.08% 8 RETURN REQ FOR CLAIMED ROR 18,571,750 8.08% 625,668 10,976,158 4,740,788 1,175,788 1,053,097 9 SALES REVENUE REQ CLAIMED ROR 67,900,310 250 2,680,862 41,221,337 16,397,314 3,986,026 3,613,470 10 REVENUE DEFICIENCY SALES REV 10,168,372 1,301 509,710 5,996,077 2,210,424 1,040,568 411,837 11 PERCENT INCREASE REQUIRED 17.6131% (245) 23.4764% 17.0221% 15.5808% 35.3279% 12.8634% 12 ANNUAL BOOKED CCF SALES 181,755,519 -15.8311% 2,735,824 77,056,777 44,020,598 17,324,205 40,614,110 13 SALES REV REQUIRED $/CCF $0.3736 4,005 $0.9799 $0.5349 $0,3725 $0.2301 $0.0890 14 REVENUE DEFICIENCY $/CCF $0,0559 $0.3247 $0.1863 $0.0778 $0,0502 $0.0601 $0.0101 -$0.0611 PROPOSED REVENUES
15 PROPOSED SALES REVENUES 67,900,310 2,680,862 41,221,337 16 REVENUE DEFICIENCY SALES REV 16,397,314 3,986,026 3,613,470 1,301 10,168,372 509,710 5,996,077 17 PERCENT INCREASE PROPOSED 2,210,424 1,040,568 411,837 17.6131% 23.476% (245) 18 PROPOSED RATE OF RETURN 17.022% 15.581% 35.328% 12.863% -15.831% 8.08% 8.08% 8.08% 19 RETURN REQ FOR PROPOSED REV 8.08% 8,08% 8.08% 8,08% 18,571,750 625,668 20 ANNUAL BOOKED CCF SALES 10,976,158 4,740,788 1,175,788 1,053,097 250 181,755,519 2,735,824 77,056,777 44,020,598 17,324,205 40,614,110 4,005 21 SALES REV REQUIRED $/CCF $0.3736 22 $0.9799 $0.5349 $0.3725 $0.2301 $0.0890 REVENUE DEFICIENCY $/CCF $0.0559 $0.3247 $0.1863 $0.0778 $0.0502 $0.0601 $0.0101 -$0.0611
PRINT DATE 8/30/2006 PRINT TIME 9:18 AM Page 25-1 DPLGasCOSNew-MAC-8-29-06.xls COST OF SERVICE DELMARVA POWER & LIGHT Page 26-1 29-Aug-06 19:13 GAS COST OF SERVICE STUDY FOR THE 12 MONTHS ENDING MARCH 31, 2006 DELAWARE TRAN & DIST 73% OEM & 27% OOMM ALLOC MEDIUM LARGE DISTR MAINS 75% OEM & 25% COMM ALLOC TOTAL RESIDENTIAL GENERAL VOLUME VOLUME COMPANY RESIDENTIAL HEATING SERVICE GENERAL GENERAL LIGHTING ALLOC (1) ALLOCATION FACTOR TABLE-26 (2) (3) (4) (5) (6) (7) CAPACITY-RELATED
1 LNG STORAGE - REM DO DEMAND DEMSTOR 168,964 1,302 96,818 2 45,702 14,590 10,551 0 3 PEAK DAY FIRM (g TRANS OEM (MCF) 188,112 1,712 101,221 4 ANNUAL SENDOUT TRANS (MCF) 49,733 17,197 18,248 1 18,629,941 280,422 7,898,320 4,512,111 5 73% OEM &. 27% COMM TRAN ALLOC 1,775,731 4,162,946 411 DEMTRAN 100.0000% 1.0715% 50.7122% 6 25.8361% 9.2476% 13.1316% 0.0010% 7 PEAK DAY FIRM (g DIST (MCF) 186,626 1,712 101,221 49,733 16,582 17,377 1 8 ANNUAL SENDOUT DIST (MCF) 18,439,889 280,422 9 73% OEM & 27% COMM DIST ALLOC 7,898,320 4,512,111 1,754,608 3,994,017 411 DEMDIST 100.0000% 1.0810% 51.1429% 26.0572% 10 9.0561% 12.6617% 0.0010% 11 PEAK DAY FIRM (g DIST MAINS (MCF) 179,618 1,712 101,221 49,733 12 ANNUAL SEND DIST MAINS (MCF) 15,233 11,718 1 16,255,243 280,422 7,898,320 13 75% OEM & 25% COMM DST MAIN 4,512,111 1,547,120 2,016,859 411 DEMMAIN 100.0000% 1.1445% 54.4284% 27.7055% 14 8.7379% 7.9826% 0.0011% 15 16 17 TOTAL DESIGN DAY SENDOUT 188,112 1,712 101,221 18 TOTAL DESIGN DAY SENDOUT-SALES 49,733 17,197 18,248 1 169,076 1,712 101,221 19 DAILY BASE USE SENDOUT - MCF 48,840 12,588 4,714 1 19,148 410 4,403 4,031 20 DAILY BASE USE SENDOUT - SALES 2,607 7,697 1 11,478 410 4,403 3,875 21 REMAINING DESIGN DAY SENDOUT 1,297 1,492 1 168,964 1,302 96,818 22 REMAINING DO SENDOUT-SALES 45,702 14,590 10,551 0 157,598 1,302 96,818 44,965 23 11,291 3,222 0 24 25 26 27 28 29 30 31 32 33 34
PRINT DATE 813012006 PRINT TIME 9:18 AM Page 26-1 DPLGasCOSNew-MAC-8-29-06.xls COST OF SERVICE DELMARVA POWER & LIGHT Page 26-2 29-Aug-06 19:13 GAS COST OF SERVICE STUDY FOR THE 12 MONTHS ENDING MARCH 31,2006 DELAWARE
TRAN & DIST 73% OEM & 27% COMM ALLOC DISTR MAINS 75% OEM & 25% COMM ALLOC
ALLOC ALLOCATION FACTOR TABLE-26 (11) (12) (13) (14) (15) CAPACITY-RELATED
1 LNG STORAGE - REM DO DEMAND DEMSTOR Page 26, Line 21 2 3 PEAK DAY FIRM (¡ TRANS OEM (MCF) Page 26, Line 17 4 ANNUAL SENDOUT TRANS (MCF) Page 27. Line 8 5 73% OEM & 27% COMM TRAN ALLOC DEMTRAN 73% Oem Line 3 above & 27% Comm Line 4 above 6 7 PEAK DAY FIRM (¡ DIST (MCF) Page 26, Line 17 less Trans Customers MDQ 8 ANNUAL SENDOUT DIST (MCF) Page 27. Line 9 9 73% OEM & 27% COMM DIST ALLOC DEMDIST 73% Oem Line 7 above & 27% Comm Line 8 above 10 11 PEAK DAY FIRM (¡ DIST MAINS (MCF) Page 26, Line 17 less Trans & FTR Direct Cust MDQ 12 ANNUAL SEND DIST MAINS (MCF) Page 27, Line 10 13 75% OEM & 25% COMM DST MAIN DEMMAIN 75% Oem Line 11 above & 25% Comm Line 12 above 14 15 16 17 TOTAL DESIGN DAY SENDOUT Design Day Sendout Sales & Transportation Customers 18 TOTAL DESIGN DAY SENDOUT-SALES Design Day Sendout Sales Customers 19 DAILY BASE USE SENDOUT - MCF Page 27, Line 13 20 DAILY BASE USE SENDOUT - SALES Page 27, Line 14 21 REMAINING DESIGN DAY SENDOUT Page 26 Line 17 less line 19 22 REMAINING DO SENDOUT-SALES Page 26 Line 18 less line 20 23 24 25 26 27 28 29 30 31 32 33 34
PRINT DATE 8/30/2006 PRINT TIME 9:18 AM Page 26-2 DPLGasCOSNew-MAC-8-29-06.xls COST OF SERVICE DELMARVA POWER & LIGHT Page 27-1 29-Aug-06 19: 13 GAS COST OF SERVICE STUDY FOR THE 12 MONTHS ENDING MARCH 31, 2006 DELAWARE TRAN & DIST 73% DEM & 27% COMM ALLOC MEDIUM LARGE DISTR MAINS 75% DEM & 25% COMM ALLOC TOTAL RESIDENTIAL GENERAL VOLUME VOLUME COMPANY RESIDENTIAL HEATING SERVICE GENERAL ALLOC GENERAL LIGHTING (1) (2) COMMODITY RELA TED-27 (3) (4) (5) (6) (7)
1 WINTER REM SALES NOV - MAR ESTOR 8,377,655 100,160 2 ANNUAL SENDOUT SALES (MCF) 5,111,117 2,469,205 530,697 166,477 o ESALES 14,576,906 280,422 3 GCR FUEL REVENUE 7,898,320 4,413,998 1,135,512 848,243 411 GCRFUEL 147,653,851 2,802,104 4 80,410,690 45,229,635 11,813,316 7,394,399 3,707 5 6 7 8 ANNUAL SENDOUT TRANS (MCF) 18,629,941 280,422 7,898,320 9 ANNUAL SENDOUT DIST (MCF) 4,512,111 1,775,731 4,162,946 411 18,439,889 280,422 7,898,320 10 ANNUAL SEND DIST MAINS (MCF) 4,512,111 1,754,608 3,994,017 411 16,255,243 280,422 7,898,320 11 4,512,111 1,547,120 2,016,859 411 12 13 DAILY BASE USE SENDOUT - MCF 19,148 410 14 DAILY BASE USE SENDOUT - SALES 4,403 4,031 2,607 7,697 1.125 11,478 410 15 WINTER BASE SNDT NOV-MAR-SALES 4,403 3,875 1,297 1,492 1.125 1,733,238 61,893 16 ANNUAL BASE SENDOUT-SALES 664,816 585,183 195,893 225,282 170 4,189,616 149,609 1,607,007 17 1,414,516 473,517 544,556 411 18 TOTAL ANNUAL SENDOUT 18,629,941 280,422 7,898,320 19 TOTAL ANNUAL SENDOU~SALES 4,512,111 1,775,731 4,162,946 411 14,576,906 280,422 20 TOTAL WINTER SDT NOV-MAR-SALES 7,898,320 4,413,998 1,135,512 848,243 411 10,110,893 162,053 5,775,933 21 3,054,388 726,590 391,759 170 22 REM WINTER SNDT NOV-MAR-SALES 8,377,655 100,160 5,111,117 23 2,469,205 530,697 166,477 0 24 LOAD FACTOR ANNUAL SENDOUT 27.13% 25 LOAD FACTOR DISTR MAINS 24.79% 26 27 28 29 30 31 32 33 34 35 36 37 38 39
PRINT DATE 8/30/2006 PRINT TIME 9:19 AM Page 27-1 DPLGasCOSNew-MAC-8-29-06.xls COST OF SERVICE DELMARVA POWER & LIGHT Page 27-2 29-Aug-06 19:13 GAS COST OF SERVICE STUDY FOR THE 12 MONTHS ENDING MARCH 31,2006 DELAWARE TRAN & DIST 73% DEM & 27% COMM ALLOC DISTR MAINS 75% DEM & 25% COMM ALLOC
ALLOC COMMODITY RELATED-27 (11) (12) (13) (14) (15)
1 WINTER REM SALES NOV - MAR ESTOR Page 27, Line 22 2 ANNUAL SENDOUT SALES (MCF) ESALES Page 27, Line 19 3 GCR FUEL REVENUE GCRFUEL Page 34, Line 2 4 5 6 7 8 ANNUAL SENDOUT TRANS (MCF) Page 27, Line 18 9 ANNUAL SENDOUT DIST (MCF) Page 27, Line 18 less Trans Customers Sendout 10 ANNUAL SEND DIST MAINS (MCF) Page 27, Line 18 less Trans & FTR Direct Cust Sendout 11 12 13 DAILY BASE USE SENDOUT - MCF July & Aug Sales & Trans Send out divided by 62 days 14 DAILY BASE USE SENDOUT - SALES July & Aug Sales Sendout divided by 62 days 15 WINTER BASE SNDT NOV-MAR-SALES Page 27, Line 14 X 151 days 16 ANNUAL BASE SENDOUT-SALES Page 27, Line 14 X 365 days 17 18 TOTAL ANNUAL SENDOUT Annual Sendout Sales & Transportation Customers 19 TOTAL ANNUAL SENDOUT-SALES Annual Sendout Sales Customers 20 TOTAL WINTER SOT NOV-MAR-SALES Winter Sendout Sales Customers 21 22 REM WINTER SNDT NOV-MAR-SALES Page 27 Line 20 less line 15 23 24 LOAD FACTOR ANNUAL SENDOUT Page 27 Line 18 I 365 days I Page 26 Line 17 25 LOAD FACTOR DISTR MAINS Page 27 Line 10 I 365 days I Page 26 Line 11 26 27 28 29 30 31 32 33 34 35 36 37 38 39
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1 ACCT 378-MEAS & REG EQUIP - GEN PL T378 3,723,216 40,248 2 ACCT 380-SERVICES 1,904,162 970,166 337,179 471,422 39 PL T380 82,223,836 6,395,105 3 ACCT 381-METERS 59,550,436 14,679,484 1,035,316 561,326 2,170 PL T381 35,875,025 2,848,344 4 ACCT 385-INDUST MEAS & REG EQ 21,377,747 10,207,164 1,153,498 288,272 o PL T385 57,138 618 29,222 5 ACCT 387-0THER EQUIPMENT 14,888 5,174 7,235 1 PL T387 0 0 6 ACCT 376 & 380-MAINS & SERVICES 0 0 0 0 o PL T37680 244,268,656 8,249,691 7 DIST OPER EXP ACCTS 871-879 147,748,888 59,574,780 15,194,574 13,496,776 3,947 EXP87179 4,169,749 180,033 8 CUST ACCTS EXP ACCT 902-903 2,453,487 1,074,924 241,779 219,481 45 EXP9023 4,027,206 398,163 9 TOTAL OPERATION & MAINT LABOR 3,163,918 409,819 34,513 20,371 422 LABOR 9,140,975 429,717 10 TOTAL GENERAL PLANT 5,635,478 2,114,425 499,542 461,653 159 GENPL T 7,724,066 363,108 11 TOTAL INTANGIBLE PLANT 4,761,944 1,786,676 422,110 390,094 135 INTPL T 1,298,804 46,002 12 TOTAL COMMON PLANT 768,509 325,693 81,873 76,710 17 COMPL T 15,934,209 734,307 9,784,625 13 3,722,558 882,984 809,452 282 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42
PRINT DATE 8/30/2006 PRINT TIME 9:20 AM Page 32-1 DPLGasCOSNew-MAC-8-29-06.x1s COST OF SERVICE DELMARVA POWER & LIGHT Page 33-1 29-Aug-06 19:13 GAS COST OF SERVICE STUDY FOR THE 12 MONTHS ENDING MARCH 31, 2006 DELAWARE TRAN & DIST 73% OEM & 27% COMM ALLOC MEDIUM LARGE DISTR MAINS 75% OEM & 25% COMM ALLOC TOTAL RESIDENTIAL GENERAL VOLUME VOLUME COMPANY RESIDENTIAL HEATING SERVICE GENERAL GENERAL ALLOC LIGHTING (1) (2) INTERNALLY DEVELOPED CON'T-33 (3) (4) (5) (6) (7)
WORKING CASH OTHER O&M WCOTHOM 12,617,551 783,313 2 CONECTIV RESOURCE PLANT 8,798,460 2,214,558 432,581 388, 090 549 CRPPL T 4,348,180 204,408 2,680,685 3 TOTAL PROD & LNG STOR EXP 1,005,790 237,622 219,599 76 STOREXP 2,062,995 25,152 1,157,101 4 TOTAL TRANSMISSION EXPENSE 583,952 171,356 125,412 23 TRANEXP 1,227,280 13,151 622,380 5 TOTAL DISTRIBUTION EXPENSE 317,081 113,494 161,161 13 DISTEXP 9,247,880 370,072 5,503,688 6 ACCT 380 & 381 - SERVICES & METER 2,333,196 547,641 493,164 118 PL T3801 118,098,861 9,243,450 80,928,183 7 SALES REVENUE REQ CLAIMED ROR 24,886,647 2,188,814 849,598 2,170 CLAIMREV 67,900,310 2,680,862 41,221,337 16,397,314 8 3,986,026 3,613,470 1,301 9 10 11 ACCT 904 & LATE PAYMENT ASSIGN 12 CLAIMED REV RESIDENTIAL CREVRES 2,680,862 2,680,862 a 13 CLAIMED REV RESIDENTIAL HEATING a a a a CREVRSH 41,221,337 a 41,221,337 14 CLAIMED REV GENERAL SERVICE a a a a CREVGG 16,397,314 a a 15 CLAIMED REV MEDIUM VOLUME GAS 16,397,314 a a a CREVMVG 3,986,026 a a 16 CLAIMED REV LARGE VOLUME GAS a 3,986,026 a a CREVLVG 3,613,470 a a 17 CLAIMED REV LIGHTING a a 3,613,470 a CREVL TG 1,301 a a 18 a a a 1,301 19 CLAIMED REV RESIDENTIAL CREVRES 1.000000 1.000000 0.000000 20 CLAIMED REV RESIDENTIAL HEATING 0.000000 0.000000 0.000000 0.000000 CREVRSH 1.000000 0.000000 1.000000 21 CLAIMED REV GENERAL SERVICE 0.000000 0.000000 0.000000 0.000000 CREVGG 1. 000000 0.000000 O. 000000 22 CLAIMED REV MEDIUM VOLUME GAS 1.000000 0.000000 0.000000 0.000000 CREVMVG 1.000000 0.000000 0.000000 0.000000 23 CLAIMED REV LARGE VOLUME GAS 1.000000 O. 000000 0.000000 CREVLVG 1. 000000 0.000000 0.000000 24 CLAIMED REV LIGHTING 0.000000 0.000000 1.000000 0.000000 CREVL TG 1.000000 0.000000 0.000000 0.000000 25 0.000000 0.000000 1.000000 26 ACCT 904 RESIDENTIAL CREVRES 3.7425% 3.7425% 0.0000% 27 ACCT 904 RESIDENTIAL HEATING 0.0000% 0.0000% 0.0000% 0.0000% CREVRSH 87.0341% 0.0000% 87.0341% 28 ACCT 904 GENERAL SERVICE 0.0000% 0.0000% 0.0000% 0.0000% CREVGG 9.2234% 0.0000% 0.0000% 9.2234% 29 ACCT 904 MEDIUM VOLUME GAS 0.0000% 0.0000% 0.0000% CREVMVG 0.0000% 0.0000% 0.0000% 30 ACCT 904 & LATE PAYMENT ASSIGN 0.0000% 0.0000% 0.0000% 0.0000% UNCOLL 100.0000% 3.7425% 87.0341% 9.2234% 31 0.0000% 0.0000% 0.0000% 32 33 34 35 36 37 38 39 40 41 42
PRINT DATE 813012006 PRINT TIME 9:20 AM Page 33-1 DPLGasCOSNew-MAC-8-29-06.xls COST OF SERVICE DELMARVA POWER & LIGHT Page 34-1 29-Aug-06 19:13 GAS COST OF SERVICE STUDY FOR THE 12 MONTHS ENDING MARCH 31, 2006 DELAWARE TRAN & DIST 73% DEM & 27% COMM ALLOC MEDIUM LARGE DISTR MAINS 75% DEM & 25% COMM ALLOC TOTAL RESIDENTIAL GENERAL VOLUME VOLUME COMPANY RESIDENTIAL HEATING SERVICE GENERAL GENERAL LIGHTING ALLOC (1) REVENUES FROM SALES-34 (2) (3) (4) (5) (6) (7)
1 TOTAL SALES REVENUE 57,731,937 2,171,153 35,225,260 14,186,890 2,945,458 3,201,632 2 FUEL REVENUE 147,653,851 1,545 2,802,104 80,410,690 45,229,635 11,813,316 7,394,399 3,707 3 UTILITY TAX 2,569,236 4 ENVIROMENTAL 0 0 2,081,421 448,911 38,904 0 207,955 2,993 89,630 5 TOTAL REVENUES 51,235 19,848 44,249 0 208,162,980 4,976,250 115,725,580 6 61,549,181 15,227,533 10,679,185 5,252 7 8 9 10 11 12 13 14 15
REVENUE REQUIREMENTS INPUTS
16 CLAIMED RATE OF RETURN 8.0800% 8.0800% 17 TOTAL ANNUAL BILLS 8.0800% 8.0800% 8.0800% 8.0800% 8.0800% 1,411,392 145,440 18 ANNUAL BOOKED CCF SALES 1,155,708 108,984 840 204 216 181,755,519 2,735,824 77,056,777 19 PROPOSED SALES REVENUES 44,020,598 17,324,205 40,614,110 4,005 67,900,310 2,680,862 41,221,337 20 16,397,314 3,986,026 3,613,470 1,301 21 22 23 24 25 26 27
PRINT DATE 8'30'2006 PRINT TIME 9:20 AM Page 34-1 DPLGasCOSNew-MAC-8-29-06.xls COST OF SERVICE DELMARVA POWER & LIGHT Page 35-1 29-Aug-06 19:13 GAS COST OF SERVICE STUDY FOR THE 12 MONTHS ENDING MARCH 31, 2006 DELAWARE TRAN & DIST 73% DEM & 27% COMM AllOC MEDIUM LARGE DISTR MAINS 75% DEM & 25% COMM AllOC TOTAL RESIDENTIAL GENERAL VOLUME VOLUME COMPANY RESIDENTIAL HEATING SERVICE GENERAL GENERAL LIGHTING AlLOC (1) (2) RATIO T ABlE-35 (3) (4) (5) (6) (7) CAPACITY- RELATED
1 lNG STORAGE - REM DD DEMAND DEMSTOR 1.000000 0.007706 0.573012 2 0.270486 0.086349 0.062447 0.000000 3 4 73% DEM & 27% COMM TRAN AllOC DEMTRAN 1.000000 0.010715 0.507122 5 0.258361 0.092476 0.131316 0.000010 6 7 73% DEM & 27% COMM DIST AllOC DEMDIST 1.000000 0.010810 8 0.511429 0.260572 0.090561 0.126617 0.000010 9 10 75% DEM & 25% COMM DST MAIN DEMMAIN 1 .000000 0.011445 0.544284 11 0.277055 0.087379 0.079826 0.000011 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34
PRINT DATE 8130/2006 PRINT TIME 9:20 AM Page 35-1 DPLGasCOS New-MAC-8-29-06.xls COST OF SERVICE DELMARVA POWER & LIGHT Page 36-1 29-Aug-06 19: 13 GAS COST OF SERVICE STUDY FOR THE 12 MONTHS ENDING MARCH 31, 2006 DELAWARE TRAN & DIST 73% DEM & 27% COMM ALLOC MEDIUM LARGE DISTR MAINS 75% DEM & 25% COMM ALLOC TOTAL RESIDENTIAL GENERAL VOLUME VOLUME COMPANY RESIDENTIAL HEATING SERVICE GENERAL GENERAL ALLOC LIGHTING (1) (2) COMMODITY RELATED (3)-36 (3) (4) (5) (6) (7)
1 WINTER REM SALES NOV - MAR ESTOR 1.000000 0.011956 2 ANNUAL SENDOUT SALES (MCF) 0.610089 0.294737 0.063347 0.019872 0.000000 ESALES 1.000000 0.019237 3 GCR FUEL REVENUE 0.541838 0.302808 0.077898 0.058191 0.000028 GCRFUEL 1.000000 0.018978 4 0.544589 0.306322 0.080007 0.050079 0.000025 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 '27 28 29 30 31 32 33 34 35 36 37 38 39
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1 TOTAL SALES REVENUE 1.000000 0.037607 0.610152 2 FUEL REVENUE 0.245737 0.051020 0.055457 0.000027 1.000000 0.018978 0.544589 3 UTILITY TAX 0.306322 0.080007 0.050079 0.000025 1.000000 0.000000 4 ENVIROMENTAL 0.000000 0.810132 0.174725 0.015142 0.000000 1.000000 0.014393 5 TOTAL REVENUES 0.431007 0.246375 0.095444 0.212782 0.000000 1.000000 0.023906 0.555937 0.295678 6 0.073152 0.051302 0.000025 7 8 9 10
PRINT DATE 8/30/2006 PRINT TIME 9:22 AM Page 43-1 DPLGasCOSNew-MAC-8-29-06.xls COST OF SERVICE Direct Testimony of Paul M. Normand PSC Docket No. 06-
SCHEDULE PMN-6 WORKAPERS
(I Service Line to Rate Analysis Methodology. Cost data :
Data from the SAP Plant Accounting system for the 3/31/06 plant account balances by material and service line size as recorded in Accounts 380.1 (copper and steel) and 380.2 (plastic) was extracted. Known adjustments to the period ending March 31 data were included. The original acquisition value was summarized by service line material and size.
Service line data: Data indicating material, size, footage and rate code for services installed prior to 6/30106 was extracted from the Gas Facilities Gas Service database. Due to the small number of customers involved the L VG/L VFT class, service line data was individually determined based on detailed matching information not previously available. The service line data was summarized by service line material and size. Customer data : Customer counts for March 2006 were obtained from March accounting reports. Analysis: Using the Service line data the percentage of footage matched to each rate class was calculated for each material 1 size combination. The calculated investments were summarized for each rate class and the total divided by the number of customers to obtain the average investment per customer. NOTES: The 18 Gas Lamp customers active during the test year represent 22 lamps and 163 feet of service line used only for the lamps. The count of 18 customers was NOT added to the residential customer count. The 163 feet of service line is include in the residential rate analysis. For interruptible customers, the data for any Delmarva Power owned service line that served ONLY interruptible load was included in the firm class with the necessary deduction presented below the summary. The majority of service lines serving interruptible load also serve the customer firm load and should not be deducted. A separate detailed sheet on Interruptible data is also provided.
PLP WP 3 8/16/2006 Gas Service Matf'~k'''Size and Footage to Rate Class Analysis 2006
Service Card Dcl\ Plant Data Residential $ allocation Residenb",,, """,(/n9 $ allocation GG/GVFT ~ , Residential Residential i Residential % of Total Residential Acquisition Book Heating %of Footage Footage Original $ Footage Heating GG/GVFT %of GG/GVFT Size Inches I Material Value $ Total Of Footage Footage r''' Original $ Footage Footage Original $ 0.50 I;.U S 49,459 116,075 26039 24.7% $ 12,206 77,595 73.5% $ 36,372 1,879 1.8% $ 881 1.00 CU $ 1,304 144,799 33260 25.2% $ 32~ 94870 71.9% $ 937 3,836 2.9% $ 38 1.25 CU S - 155 90 58.1% $ 65 41.9% $ - 0.0% $ 2.00 CU $ - - 0 0.0% $ 0 0,0% $ - 0.0% $ 6.00 CI $ - 28 0 0.0% $ 0 0.0% $ 28 0.0% $ Residential Residential Residential % of Total Residential Acquisition Book Heating %of Footage Footage Original $ Heating GG/GVFT %of GG/GVFT Size Material Value $ Footage Total Of Footage Footage Original $ Footage Footage Original $ 0.50 Steel $ - 280 0 0.0% $ 242 100,0% $ - 0.0% $ - 0.75 Steel $ 114,004 1,437,113 51937 4.0% $ 4,539 1231741 94.4% $ 107,639 20,851 1.6% $ 1,822 1.00 Steel $ 35,073 14,548 819 8.0% $ 2,802 2744 26.8% $ 9,387 6,690 65.2% $ 22,885 1.25 Steel $ 172,206 301,680 69383 26.5% $ 45,587 176155 67.2% $ 115,740 16,558 6.3% $ 10,879 1.50 Steel $ 9,983 131 0 0,0% $ 56 52.8% $ 5,27' 50 47.2% $ 4,709 2.00 Steel $ 112,284 35,388 4305 19.7% $ 22,107 9367 42.8% $ 48,101 7,967 36.4% $ 40,911 3.00 Steel $ 14,862 12,313 13 0.2% $ 29 441 6.5% $ 969 5,986 88.5% $ 13,157 4.00 Steel $ 97,553 6,579 21 0.4% $ 378 177 3.3% $ 3,183 2,842 52.4% $ 51,105 6.00 Steel $ 39,630 1,035 0 0.0% $ 0 0.0% $ 536 51.8% $ 20,52 8.00 Steel $ - 740 0 0.0% $ 0 0.0% $ 12 0.0% $ 12.00 Steel :¡ - 747 0 0,0% :¡ 0 0.0% :¡ - 0.0% :¡ TOTAL 380.1 $ 646,358 :¡ 87,975 327,602 $ 166,910 Residential Residential % ofTotal Residential Acquisition Book Residential %of Footage Footage Heating Heating GG/GVFT %of GG/GVFT Size Material Value $ Original $ Footage Total Of Footage Footage Original $ Footage Footage Original $ 0.50 Plastic $ 42,822,161 3,004,162 202,709 7.4% $ 3,156,83' 2,514,383 91.4% $ 39,157,06 32,637 1.2% $ 508,263 0.75 Plastic $ 3,479,048 843,586 17,332 2.3% $ 79,517 639,549 84.3% $ 2,934,181 101,193 13.3% $ 464,262 1.00 Plastic $ 12,050,112 459,860 69,762 17.1% $ 2,063,310 251,932 61.8% $ 7,451,246 85,725 21.0% $ 2,535,438 1.25 Plastic $ 5,558,121 176,746 3,925 2.7% $ 148,350 39,397 26.8% $ 1,489,057 102,987 70.0% $ 3,892,518 1.50 Plastic $ - 105 - - 0.0% $ 0.0% $ 105 100.0% $ 2.00 Plastic $ 3,572,312 116,003 966 1.0% $ 35,987 11,905 12.4% $ 443,503 81,783 85.3% $ 3,046,702 3.00 Plastic $ 31,066 3,852 73 2.5% $ 781 53 1.8% $ 567 2,778 95,6% $ 29,708 4.00 Plastic $ 1,543,032 34,885 48 0.2% $ 2,602 1,760 6.2% $ 95,389 19,138 67.2% $ 1,037,252 6.00 Plastic $ 1,639,458 2,033 - 0.0% $ 1 0.0% $ 806 1,109 54.5% $ 894,323 8.00 Plastic :¡ 351,759 600 - - 0.0% :¡ 0.0% :¡ 372 62.0% $ 218,090 Plastic 1 380.2 Total 71,047,069 $ $ 5,487,380 $ 51,571,813 $12,626,557 Residential Residential Residential % of Total Residential %of Acquisition Book Heating Heating Footage Footage Original $ GG/GVFT %of GG/GVFT Size Material Value $ Footage Total Of Footage Footage Original $ Footage Footage Original $ TOTAL ALL MATERIAL $ 71,693,428 6,713,443 480,682 8.0% :¡ 5,575,355 5,052,433 83.6% :¡ 51,899,414 495,062 8.2% :¡12,793,468 % of cost 7.8% % of cost 72.4% % of cost 17.8% Total Customers Customers' 3/31/06 11,863 Customers 3/31/06 99,183 Customers 3/31/06 9,317 Per customer $ 470 Per customer $ 523 Per customer $ 1,373 . Included 18 Gas Lamp customers Cost per Foot $11.60
PLP WP 3 8/16/2006
8/24/2006 9:50 AM Page 1 of2 PLP WP3 2006 Gas Services-2.xis Serve OS! :,. ?,I!'2(;':,:.,~ Gas Service Ma~p"""Size and Footage to Rate Class
Service Card Dà, Plant Data MVG/MVFT/MVIT L VG/b.".,A_ VIT
MVGIMVFTI MVGIMVFTIM L VGIL VFT/ LVGILVFTIL Acquisition Book MVIT %of VIT Original LVIT %of VIT Size Inches Material Value $ Total Of Footage Footage Footage $ Footage Footage Original $ 0.50 CU 49,459 .. $ 116.075 0.0% $ - 0.0% $ 1.00 CU .. $ 1,304 144,799 0.0% $ - 0,0% $ 1.25 CU - .. $ 155 0.0% $ - 0,0% $ 2.00 CU - - - $ 0.0% $ - 0,0% $ 6.00 CL .. - $ 28 0.0% $ - 0.0% $
MVG/MVFTI MVG/MVFT/M L VG/L VFT/ LVGILVFTIL Acquisition Book MVIT %of VIT Original LVIT %of VIT Size Material Value $ Total Of Footage Footage Footage $ Footage Footage Original $ 0.50 Steel .. - $ 280 0,0% $ 0.0% $ 0.75 Steel 114,004 $ 1,437,113 52 0.0% $ 5 - 0.0% $ 1.00 Steel - $ 35,073 14,548 0.0% $ - 0.0% $ 1.25 Steel - $ 172,206 301,680 0.0% $ - 0.0% $ 1.50 Steel - $ 9,983 131 0.0% $ - 0.0% $ 2.00 Steel $ 112,284 35,388 227 1.0% $ 1,166 - 0,0% $ 3.00 Steel $ 14,862 12,313 239 3.5% $ 525 83 1.2% $ 18 4.00 Steel $ 97,553 6,579 1,436 26.5% $ 25,822 921 17.0% $ 16,561 6.00 Steel $ 39,630 1,035 102 9,9% $ 3,906 397 38.4% $ 15,201 8.00 Steel - - $ 740 0,0% $ 728 98.4% $ 12.00 Steel .. :¡ 747 .. 0,0% :i 747 100.0% $ TOTAL 380.1 $ 646,358 $ 31,423 $ 31,945
MVG/MVFTI MVGIMVFT/M LVGILVFTI LVG/LVFTIL Acquisition Book MVIT %of VIT Original LVIT %of VIT Size Material Value $ Total Of Footage Footage Footage $ Footage Footage Original $ 0.50 - Plastic $ 42,822,161 3,004,162 0,0% $ - 0.0% $ 0.75 Plastic $ 3,479,048 843,586 237 0.0% $ 1,087 - 0.0% $ 1.00 Plastic $ 12,050,112 459,860 4 0.0% $ 118 - 0.0% $ 1.25 Plastic $ 5,558,121 176,746 746 0.5% $ 28,19E - 0.0% $ 1.50 Plastic - .. $ 105 0,0% $ - 0.0% $ 2.00 Plastic $ 3,572,312 116,003 1,204 1,3% $ 44,853 14 0.0% $ 522 3.00 Plastic $ 31,066 3,852 1 0,0% $ 11 .. 0.0% $ 4.00 Plastic $ 1,543,032 34,885 6,112 21.5% $ 331,261 1,372 4.8% $ 74,360 6.00 Plastic $ 1,639,458 2,033 579 28.5% $ 466,9H 344 16.9% $ 277,410 8.00 Plastic :¡ 351,759 600 6 1,0% :i 3,51~ 222 37.0% :¡ 130,151 Plastic 1 380.2 Total $ 71,47,069 $ 875,963 $ 482,442
MVG/MVFTI MVG/MVFT/M L VG/L VFT/ L VG/L VFT/L Acquisition Book MVIT %of VIT Original LVIT %of VIT Size Material Value $ Total Of Footage Footage Footage $ Footage Footage Original $ TOTAL ALL MATERIAL $ 71,693,428 6,713,443 10,945 0.2% :¡ 907,387 4,828 O. % :¡ 54,38 % of cosi 1.3% % of cost 0.7% Total Customers Customers 3131/06 79 Customers 3/31106 24 Per customer $ 11,486 Per customer $ 21,433
MVG/MVFT (less IT) LVG/LVFT (less iT)
Total Total MVG/MVFT %of MVG/MVFT LVG/LVFT %of LVGILVFT Footage Footage Original $ Footage Footage Original $ ...:; illR".. 1....'.I,¡íeri¡~¡1Mé'Â~jt~ïfé~~ 10,759 u.2%1 :i 902,299 3,999 0.1% $ 489.207 % of COSI 1.3% % of cost 0.7% Customers 3/31/06 72 Customers 3131106 16 % Customer Change 8.9% % Customer Chanae 33.3% Per customer $ 12,532 Per customer $ 30,575 PLP WP 3 % Delta 9.1% % Delta 42.7% 811612006
8/2412006 9:50 AM Page 2 of2 PLP WP3 2006 Gas Services-2.xls ServCost to RateCode h.:PWP2
Gas Metering Devices to Rate Analysis Methodology. Cost data:
Data from the SAP Plant Accounting system for the 3/31/06 plant account balances by Bin number as recorded in Account 381 The original acquisition values were summarized by Bin Number The Bin Number represents a sub grouping of metering equipment with similar physical and installation cost characteristics. Metering Equipment in service data: Data indicating meter size and rate codes as of 6/23/2006 was extracted from available customer Meter records. This data was summarized by assigning the meter sizes to bin numbers. Customer data: Customer counts for 3/31/2006 were obtained from March accounting reports. Analysis: Using the meter equipment data, the percentage of devices matched to each Bin and rate class was calculated. This percentage was applied to the 2006 plant accounting acquisition value for the applicable Bin providing the allocation of Meter Device investment to each rate class. The calculated investments were summarized for each rate class and the total divided by the number of customers to obtain the average investment per customer.
NOTES: The 18 Gas Lamp customers (representing 22 lamps) active during the test period are not metered.
PLP WP 2 8/4/2006
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T"T" T"T" N N N N N N N NN N Gas Metering Devices to Rate Class Anal) ABC D N o P Q R 5 Plant Accounting Data M Records MVG & MVFT Analysis L VG & L VFT Analysis Acquisition Devices in Device BIN Type Bin% Acquisition Device Acquisition Book Value $ service Count Book Value $ Count Bin % Book Value $ 1 302 250/275 $ 17,946,667 113,113 5 0.00% $ 793 2 0.0% $ 317 2 303 630 $ 930,605 972 0 0.0% $ - 0 0.0% $ - 3 304 415/425 $ 2,247,458 7,223 0 0.0% $ - 0 0.0% $ - 4 307 1400 $ 3,746 1 0 0.0% $ - 0 0.0% $ - 5 308 1600 $ 103,423 66 1 1.5% $ 1,567 0 0.0% $ - 6 309 3000 $ 29,944 5 0 0.0% $ - 0 0.0% $ - 7 311 2300 $ 5,385 1 0 0.0% $ - 0 0.0% $ - 8 312 5000 $ 9,832 3 3 100.0% $ 9,832 0 0.0% $ - 9 313 10000 $ 455,232 3 0 0.0% $ - 0 0.0% $ - 10 1.5 rotary 310 $ 1,686,517 626 0 0.0% $ - 0 0.0% $ - 11 315 3M $ 1,098,539 539 11 2.0% $ 22,419 0 0.0% $ - 12 316 5M $ 1,420,833 304 22 7.2% $ 102,823 3 1.0% $ 14,021 13 317 7M $ 772,597 111 26 23.4% $ 180,969 0 0.0% $ - 14 318 11M $ 752,520 147 43 29.3% $ 220,125 0 0.0% $ - 15 319 16M $ 596,395 106 45 42.5% $ 253,187 11 10.4% $ 61,890 16 320 23M $ 28,043 6 6 100.0% $ 28,043 0 0.0% $ - 17 325 T18 $ 157,079 26 4 15.4% $ 24,166 13 50.0% $ 18 326 T30 $ 124,486 9 0 0.0% $ - 1 11.1% $ 19 327 T60 $ 14,450 13 Q 0.0% $ - § 38.5% $ 20 Meter Total 166 0.1% 35 0.0% 21 - 0.0% - - 22 443 t;;F::j',t::il-?r;H?/i;:-::,;~;.lt 23 165,815 24 Average $/ Device $ 206 25 Ave. Devices per Cust. or Ave. Meters per Cust. 1.02 3.42 2.31 4.19 2.19 26 % Cost 3.19% % Cost 0.80% 27 % of Cust 281 Total Metered Customers * 0.06% % of Cust 0.01% 120,448 Customers 3/06 72 Customers 3/06 16 29 * Gas Lighting Customers not metered Per customer $ 15,121.77 Per customer $ 17,006
Revised 8/4/2006 PLP WP 2
8/24/2006 9:49 AM Page 2 of3 PLP WP2 2006 Gas Meters.xls SUMMARY Gas Metering Devices to Rate Class Anali ABC D T U V W X Y Plant Accounting Data M Records MVIT Analysis LVIT Analysis Acquisition Devices in Device Acquisition Device BIN Type Bin% Bin% Acquisition Book Value $ service Count Book Value $ Count Book Value $ 1 302 250/275 $ 17,946,667 113,113 0 0.0% $ - 5 0.0% $ 793 2 303 630 $ 930,605 972 0 0.0% $ - 0 0.0% 3 304 415/425 $ 2,247,458 7,223 0 0.0% $ - 0 0.0% 4 307 1400 $ 3,746 1 0 0.0% $ - 0 0.0% 5 308 1600 $ 103,423 66 0 0.0% $ - 0 0.0% 6 309 3000 $ 29,944 5 0 0.0% $ - 0 0.0% 7 311 2300 $ 5,385 1 0 0.0% $ - 0 0.0% 8 312 5000 $ 9,832 3 0 0.0% $ - 0 0.0% 9 313 10000 $ 455,232 3 0 0.0% $ - 0 0.0% 10 310 1.5 rotary $ 1,686,517 626 0 0.0% $ - 0 0.0% 11 315 3M $ 1,098,539 539 0 0.0% $ - 0 0.0% 12 316 5M $ 1,420,833 304 0 0.0% $ - 0 0.0% 13 317 7M $ 772,597 111 3 2.7% $ 20,881 1 0.9% $ 6,960 14 318 11M $ 752,520 147 0 0.0% $ - 0 0.0% 15 319 16M $ 596,395 106 8 7.5% $ 45,011 0 0.0% 16 320 23M $ 28,043 6 0 0.0% $ - 0 0.0% 17 325 T18 $ 157,079 26 0 0.0% $ - 4 15.4% $ 24,166 18 326 T30 $ 124,486 9 0 0.0% $ - 4 44.4% 19 327 T60 $ 14,450 13 i 15.4% $ 2.223 ~ 23.1% 20 Meter Total 123,274 13 0.0% $ 68.115 17 0.0% fr;'âU;::'Z(e,t;;;;'?/:::;t~V"".~ 21 330 Index 42,098 \'W:;:";~:if;'mfY?T;:rtr~:;~\:+~ 22 I 443 (,;~JVY31Xr:D /;;;'\~?'; 23 165,815 24 Average $/ Device 206 25 Ave. Devices per Cust. or Ave. Meters per Cust. 1.02 3.00 1.86 4.00 2.13 26 % Cost 0.27% % Cost 0.40% 27 % of Cust 0.01% % of Cust 0.01% 28 Total Metered Customers .. 120,448 Customers 3/06 7 Customers 3/06 8 29 .. Gas Lighting Customers not metered Per customer $ 13,228 Per customer $ 17,061
Revised 8/4/2006 PLP WP 2
8/24/2006 9:49 AM Page 3 of 3 PLP WP2 2006 Gas Meters.xls SUMMARY Direct Testimony of Paul M. Normand PSC Docket No. 06-
SCHEDULE PMN-7
DESCRIPTION OF ALLOCATION FACTORS
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