appendix a emily medine resume - nova scotia power · resume of emily s. medine educational...

Appendix A

Emily Medine Resume

RESUME OF EMILY S. MEDINE

EDUCATIONAL BACKGROUND M.P.A. Woodrow Wilson School of Public and International Affairs, Princeton

University, 1978 B.A. Geography, Clark University, 1976 (magna cum laude, Phi Beta Kappa)

PROFESSIONAL EXPERIENCE

Current Position Emily Medine, a Principal, has been with Energy Ventures Analysis since 1987. Her experience includes bankruptcy support, market strategy development, fuel procurement audits, fuel procurement, acquisition and investment analyses, strategic studies and forecasting. She has also provided expert testimony on utility fuel procurement practices. The types of projects in which she is involved are described below:

Fuel Procurement Audits

Manages and performs fuel procurement audits on behalf of regulatory commissions, utility management, and third-party interveners. She has performed over 20 audits of utilities regulated by the Public Utilities Commission of Ohio and testified in a number of proceedings. She also managed two major audits of the fuel procurement practices of PacifiCorp. In 2005, Ms. Medine performed a management/performance audit of the Fuel and Purchased Power costs of the Cincinnati Gas & Electric Company. On behalf of the Consumer Advocate of the State of West Virginia Ms. Medine audited Appalachian Power fuel procurement costs in 2006 and 2007 and Monongahela Power in 2007.

Fuel Procurement

Develops and implements fuel procurement strategies for utilities and independent power projects. Fuel procurement assistance has ranged from determining an appropriate contract/spot mix to soliciting bids and negotiating purchase agreements. Ms. Medine has negotiated fuel supply agreements for three qualifying facilities (QF’s) and has worked on fuel supply arrangements for a number of other plants. Ms. Medine is an advisor to Nova Scotia Power on its fuel procurement activities. Ms. Medine is currently developing the fuel procurement strategy for a new solid-fuel power plant on the Great Lakes.

Forecasting

Develops forecasts of coal demand and prices for alternative coal types and market segments. These forecasts are provided to individual clients and are documented in various COALCAST reports including the regional reports and the Long-Term Regional Coal Price Forecast reports.

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Acquisition and Investment

Ms. Medine was the agent for Lexington Coal Company in the sale of its assets in Indiana and Illinois. As part of this engagement, Ms. Medine was responsible for the sale of three mines to Peabody Energy. Ms. Medine also routinely evaluates the economics of potential projects or acquisitions for producers, developers, and industrials. For coal projects, this includes market and financial forecasts. Ms. Medine completed the sale of six idle mine assets and various other properties.

Bankruptcy Support

Ms. Medine was an advisor to the Horizon Natural Resource companies which operated as a debtor-in-possession in the development of a plan to accomplish reclamation on all permits not sold and transferred as part of the plan of reorganization. For a period of 15 months, Ms. Medine served as Executive Vice President of Centennial Resources, Inc., a debtor-in-possession, as part of EVA’s contract to manage this company post-petition. In this capacity, she managed the day-to-day operations of the company as well as serving as the liaison between the company, state and county regulatory agencies, the bankruptcy court, and the lenders. This assignment ended upon the filing of Centennial’s plan of reorganization. Ms. Medine had also served as the advisor to secured lenders in another coal industry bankruptcy. In this capacity, she reviewed and developed independent financial forecasts and operating plans of the debtor-in-possession.

Market Strategy Development

Assists clients in the development of marketing strategies on behalf of coal suppliers and transporters. She has helped to identify the high value markets and strategies for obtaining these accounts.

Expert Testimony

Prepares analyses and testimony in support of clients involved in regulatory and legal proceedings. Provides testimony in commission hearings on fuel procurement issues and arbitration proceedings on contract disputes.

Prior Experience Prior to joining EVA, Ms. Medine held various positions at CONSOL including Assistant District Sales Manager – Chicago Sales Office and Strategic Studies Coordinator. Prior to CONSOL, Ms. Medine was a Project Manager at Energy and Environmental Analysis, Inc. where she directed two large government studies. For the Environmental Protection Agency, Ms. Medine directed an evaluation of the energy, environmental and economic impacts of New Source Performance Standards on Industrial Boilers. For the Department of Energy, Ms. Medine directed an evaluation of the financial impacts of requiring utilities with coal capable boilers to reconvert to coal. Ms. Medine worked as a Research Assistant at Brookhaven National Laboratory while she attended graduate school.

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Appendix B

Leonard Crook Resume

LEONARD R. CROOK, JR EDUCATION 1972 MA, History, University of Memphis, Outstanding Graduate Student Award 1970 BA, History and Economics, with Honors in History, University of Memphis. Phi

Alpha Theta National History Honor Society EXPERIENCE After a career with Federal Energy Regulatory Commission (FERC), Mr. Crook joined ICF in 1984 and is now a Vice President. He directs ICF’s natural gas practice, specializing in natural gas market structure and operations, gas supply contracting, pipeline transportation issues, distribution costs and supply planning, LNG strategies, and climate change issues related to natural gas systems. He has authored a number of reports and made presentations on all aspects of the natural gas industry. Some of his principal areas of expertise are described below. Mr. Crook has a strong background in natural gas market structure and dynamics. Gas Market Studies • Mr. Crook has provided market, pipeline, and sales advisory services to developers of synthetic natural

gas projects in Indiana and Louisiana. The work involved identifying markets, pipeline access, pricing terms, and other related issues for the sale of syngas to local distribution companies and power utilities.

• For a consortium of gas companies and government agencies in Australia, Mr. Crook participated in a team from ICF advising on the development and design of a national gas market.

• For a group of New England electric and natural gas utilities, Mr. Crook co directed a large study of the avoided costs of gas, oil, and power in the Northeast. The purpose of the study was to develop a consistent set of avoided cost estimates for use in demand side management program planning. Mr. Crook presented his findings before groups of utility managers, regulators, and public interest groups.

• Mr. Crook directed ICF’s work on a quick turnaround project for the Newfoundland and Labrador Department of Natural Resources to study the opportunities for monetizing natural gas resources in the offshore fields. Mr. Crook presented the findings in St. John’s to DNR staff.

• Mr. Crook led the preparation of a White Paper on LNG economic, contracting, market, and safety issues for the National Association of Regulatory Utility Commissioners (NARUC). He has worked with the NARUC gas committee chairman and presented at the Mid-year conference. The paper will be published in the United States to present the state regulatory commissions’ policies on LNG.

• Mr. Crook as part of a high level team of economists and gas industry executives, prepared a set of policy reviews and recommendations for restructuring the gas market in Ontario. The client is the Ontario Energy Board. Specifically, evaluated restructuring gas storage and gas system supply and the application of performance based ratemaking.

• Mr. Crook led independent study of a long term natural gas markets and commercial arrangements for The Amir of Qatar in anticipation of a major expansion of LNG imports to the U.S.. This work involved basic market modeling, market research, competitor research, and pricing and contracting strategies. Mr. Crook led separate briefings of our findings for the Foreign Minister and the Energy Minister.

• Mr. Crook has advised the Government of the Bahamas on developing tax and fee structures applicable to LNG terminals. This work involves both research into analogous fee regimes, developing alternative structures and modeling potential revenues to identify those with the highest

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NPV to the government consistent with economic operation of the project. Mr. Crook provided independent reviews of contract documents and briefed the Prime Minister and the Cabinet.

• For a Mitsubishi, Mr. Crook has evaluated the competitive situation for LNG deliveries to the U.S. from different countries in the Atlantic LNG market zone. We evaluated the receiving capacity in the U.S. through 2015, LNG liquefaction capacities and plans, shipping availability, and costs along the value chain. ICF compared these estimates with our forecasts of ex-terminal gas prices in the U.S. to establish a merit order of imports.

• Mr. Crook directed an evaluation of the market for natural gas (including LNG) in eastern Canada and the northeastern U.S. for Anadarko Petroleum.

• Mr. Crook has assisted several other LNG import project investor groups (in the early 1990’s) to understand the North American gas market dynamics and regulatory framework associated with importing LNG. Again, using NANGAS, we developed forecasts of future market conditions, with and without the LNG. These studies were supplemented by specific pipeline and gas contract assistance. We have briefed investor groups in Europe and South America on U.S. market and regulatory issues relevant to LNG.

• Mr. Crook has directed a due diligence review of the New York gas market in support of the Iroquois Gas Transmission System’s Eastchester Pipeline extension into New York City. The analysis examined the outlook for gas consumption, pipeline competition, and long-distance electric transmission competition.

• Mr. Crook co-led ICF’s analysis of the impact of bringing Alaskan natural gas into the U.S. market at specific locations and at specific quantities. This work was done on behalf of a consortium of the North Slope producers, led by ExxonMobil. It analyzed the impact on prices and flows across the North American gas network.

• Mr. Crook has directed ICF due diligence reviews of the Portland Natural Gas Transmission System,

Maritimes and Northeast Pipeline and the Pacific Gas Transmission Company's first major expansion. The work involved evaluating the market for gas, the availability of gas supply to support the project, and the outlook for competition from other pipelines and supply sources.

Gas Supply and Transportation Planning

• Mr. Crook led a valuation of an Appalachian region gathering pipeline system. The study evaluated

the production potential in eastern Pennsylvania, the competing access to market for the production, and the value at market to estimate a value for the asset. The client in this case was a major pipeline company in the east.

• For Portland General Electric, Mr. Crook led a study of the gas supply options for the Beaver Power Plant, a large gas-fired facility. The analytic approach used ICF’s Asset Optimization Model to analyze specific issue of concern to PGE – establishing the value of firm transportation, storage and a capacity call-back option.

• For eCorp, a storage developer, Mr. Crook participated in ICF’s analysis of the Stagecoach Storage Facility in New York /Pennsylvania. This valuation examined the value of the facility as storage and for trading.

• For Carolina Power and Light, Mr. Crook helped to analyze the gas pipeline capacity and gas supply availability to support new gas-fired power plants in the CP&L service territory. Our analysis evaluated capacity availability on Transco, the possibility of extending the Southern Natural Pipeline, and other pipeline alternatives.

• For Philadelphia Gas Works, Mr. Crook directed an evaluation of the gas supply functions in the company, including using ICF’s models to find the optimal mix of contracts, capacity, storage, and LNG; performing a management review of the gas supply department, reviewing peak day sendout


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methodology, assessing; analyzing risk management options; and performing a preliminary engineering study of LNG plant upgrade options.

• For the Philadelphia Gas Works, Mr. Crook assisted in a procurement to outsource all of the gas

supply functions for the distributor. Mr. Crook was brought into the process to review the RFP and make recommendations; develop evaluation criteria for selecting suppliers; review the bids; interview the finalists (Enron, Williams, Sempra, PECO, and TPC); make the final selection recommendations; and assist in negotiations.

• For Niagara Mohawk Gas Company (NMGas), Mr. Crook directed an analysis of NMGas' contract

supply portfolio to evaluate the reasonableness of costs and reliability of supply. • For the Defense Fuel Supply Center, Mr. Crook has directed a major study of least cost gas supply

strategies for California facilities. This analysis included an assessment of a wide array of gas supply, transportation, storage and fuel switching options. Using ICF's Gas Acquisition Strategy Model, the study analyzed alternative strategies under different pricing and demand assumptions.

• For Southern California Edison Co., Mr. Crook helped develop a model to analyze gas purchasing

decisions, focusing on storage. • For a New Jersey Natural Gas, he analyzed alternative peaking supply options and developed a

cost/benefit analysis of the available alternatives and their respective revenue requirements. Among the alternatives considered were hook-up moratorium, LNG, new storage, and pipeline supply.

Gas Supply Contracting and Due Diligence • Mr. Crook has served as the principal gas consultant for over $4 billion of project financing for gas-fired

cogeneration and independent power projects; advised clients on gas supply contracting, transportation and regulatory issues in the US and Canada. He worked closely with developers and bankers in finalizing project documents, and on occasion supporting negotiations with pipelines or suppliers. He has made presentations for loan syndication and financing club groups. Principal projects and lead banks include:

Midland Cogeneration Venture (Michigan)—First Chicago, CitiBank Ave Fenix (Argentina)—NationsBank Encogen Four Partners (New York)—First Chicago Nevada Cogen Associates (Nevada)—Swiss Bank Encogen Northwest (Washington State)—First Chicago Hazleton (Pennsylvania)—ABN Amro Indeck Olean (New York)—CIBC Gordonsville (Virginia)—First Chicago, Norweb West Windsor (Ontario)—Citibank, Bank Nationale de Paris Panda Rosemary (Virginia/N.C.)—Energy Initiatives Project Orange (New York)—ABN Amro AG Energy (New York)—Swiss Bank PGT Expansion (Canada to California)—First Chicago Maritimes and Northeast Pipeline (Canada to New England)—CIBC, Toronto Dominion SkyGen Energy/Calpine IPPs: Hog Bayou (Alabama), Pine Bluff (Arkansas), Rockgen (Wisconsin), Broad River (South Carolina), Zion—Credit Suisse First Boston, DG Bank Ennis Power Project (Texas) – DG Bank Tuxpan Power Plants (Mexico) – Mitsubishi Rio Bravo Power Plants (Mexico) – International Finance Corporation, Societe Generale

• For the Bonneville Power Administration, Mr. Crook served as advisor on gas issues related to

Bonneville's all-source-bidding program. He critiqued and advised BPA on its gas supply evaluation


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criteria, assessed the reliability and costs of the proposed gas supply for gas-fired generation bids, assisted in negotiations with the winning bidder, and advised BPA on gas industry issues in general, particularly the potential impact of FERC Order 636.

• For Oglethorpe Power Corporation, Mr. Crook assisted the Corporation staff to develop its own bid

for gas fired generating capacity in a solicitation.

Tariff and Rates Issues

• For the City of Charlottesville Gas Department, Mr. Crook performed a study of the interruptible

service tariff in order to develop a revised tariff design and to implement a transportation-only service.

• Mr. Crook has assisted in the preparation of tariff case testimony before the Federal Energy Regulatory Commission and the District of Columbia Public Utility Commission. In the former case, he prepared a study to support a secondary market for pipeline capacity on the ANR pipeline system. In the latter, he assisted in preparation of marginal cost rate design for the Washington Gas Light Company.

• While a member of the FERC staff, Mr. Crook developed a Commission opinion on the application of socioeconomic impact costs to the Alaska Natural Gas Transportation System. Mr. Crook performed research, held hearings in Alaska, and performed the factual analysis on the issue of whether the pipeline rates should include additional costs associated with socioeconomic impacts on the Alaskan communities.

• Under a contract with the U.S. Agency for International Development, Mr. Crook prepared an analysis

of the Natural Gas Sector in the Czech Republic as part of an overall assessment of privatization program. Mr. Crook reviewed alternatives for structuring the Czech gas industry. The report was submitted to AID and the Ministry for Economic Policy and Development for the Czech Republic.

• Under contract to USAID, Mr. Crook worked with the staff of the Ceske Plynarenske Podniky (CPP)

to develop a program for applying long run marginal cost pricing principles to the development of rates for the gas distribution company in the Czech Republic. Mr. Crook met with CPP senior staff to review current pricing policies and rates procedures, briefed the CPP staff on alternative approaches to developing rates, and prepared a Long-Run Marginal Cost Briefing Paper for the CPP. Mr. Crook also developed a work plan for how the CPP could analyze its gas loads and develop information to support long run marginal cost based rates.

Natural Gas Industry Environmental Issues • For the Environmental Protection Agency, Mr. Crook has led an ICF team to develop guidelines for

mandatory monitoring of greenhouse gas emissions from fuel suppliers, including in the natural gas, petroleum and coal industries. The work will be used as a basis for developing national regulations on reporting fuel throughput.

• For the Environmental Protection Agency, Mr. Crook has directed ICF’s support of the Natural Gas STAR Program, a cooperative gas industry/government program that identifies ways to reduce methane emissions from natural gas systems. Elements of this program include: • Marketing to gas companies to join the program • Working with gas companies to identify best management practices to reduce emissions, including

the development of Lessons Learned Studies on cost effective emission reduction technologies and practices

• Analyzing leak reduction reports • Developing and implementing computerized information systems for maintaining and analyzing

leak reduction data by company and reporting data to EPA


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• Mr. Crook led the development of the national methane emissions inventory from gas and oil systems. The inventory is an annual report to the United Nations on greenhouse gas emissions.

• Mr. Crook developed gas industry marginal abatement curves for reducing methane emissions. These are used to identify emission reductions achievable at various gas price and carbon price levels.


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Federal Energy Regulatory Commission 1972 - 1983 Office of Pipeline Regulation (OPR) 1978 - 1983

Served as an Industry Economist in Pipeline Certificates Division, managed environmental assessments (EAs) and environmental impact statements (EISs) for pipeline projects, curtailment plans and FERC rule makings; testified in FERC hearings on environmental matters; was given special assignments relating to the Alaska Natural Gas Transportation System (ANGTS), and as expert advisory staff to Commissioners Matthew Holden and Anthony Souza. Significant accomplishments included:

• Developed an environmental impact analytic approach for natural gas curtailment planning and applied that methodology in Florida for the Florida Gas Transmission Company’s curtailment plan. We did air quality impact assessments for all of the counties in Florida as a result of curtailments under five alternative curtailment plan proposals. Testified in on the results.

• Developed and led a cost benefit analysis on Port Everglades of the effect of introducing a oil pipeline into Florida, then being sponsored by FGT. The analysis evaluated shipping under Jones Act tankers and barges, the effect on the port, and the effect on the local economy. Testified on the results.

• Researched and wrote a Commission policy statement on who should bear the socioeconomic impact costs in Alaska of the ANGTS. Conducted hearings in Alaska with Commissioner Souza, interacted with State agencies and social organizations.

• Developed the affirmative action and minority business enterprise plans for ANGTS, which under the Alaska Natural Gas Act required special MBE provisions. Coordinated the inputs of eight Federal Agencies, co-conducted hearings in Alaska (including one in Barrow), and successfully got the regulations implemented for FERC and the Office of the Federal Inspector. Received an outstanding performance award.

Office of Regulatory Analysis (Office of Economics) 1975 - 1978

Served on the staff of the Commission's Advisor on Environmental Quality, an office created to implement the National Environmental Policy Act (NEPA); helped develop environmental regulations for the Commission; performed general policy and management analyses. Significant accomplishments included:

• Developed FERC (then Federal Power Commission) regulations under the National Historic Preservation Act.

• Assigned to the ANGTS economics analysis team, prepared the socioeconomic impact analysis for the FPC’s EIS, testified in hearings, participated in preparing the Recommendation to the President and the President’s Report to Congress.

Bureau of Power (Office of Hydroelectric Licensing) 1972 - 1975

Served on Bureau of Power’s environmental staff preparing environmental impact statements specializing in the economic and cultural resource impacts of hydroelectric projects. Also prepared FPC jurisdictional memoranda on dams across various rivers in New England, New York, and Michigan. Significant accomplishments included:

• Developed the first studies of the impact of power dams on historic and archeological resources and established FPC policies in this area in response to new legislation protecting cultural resources. Developed a primer for hydro license applicants on how to comply with this legislation.


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PUBLICATIONS and PRESENTATIONS “Integrating World LNG Markets into North America: Issues and Challenges,” 2006 Advanced Regulatory

Studies Program, Institute of Public Utilities, Michigan State University. East Lansing, Michigan. June 7, 2006.

“Towards a World Gas Market, Recent Trends.” Presented to the 2006 Winter Meeting of National Association of Regulatory Utility Commissioners, Washington, D.C., February 14, 2006.

“Towards a World Gas Market; Implications for the U.S.” Presented to the 4th Annual Gas and Power Institute, University of Texas Law School, Houston. October 21, 2005.

“NARUC LNG Paper Highlights.” Presented to the 2005 Summer Meeting of the National Association of Regulatory Utility Commissioners, Austin, Texas. July 25, 2006.

“Dawn Hub Market Dynamics” Presented to the NEGM/ANE Annual Customer/Supplier Conference. Cape Cod, Massachusetts. July 13, 2005.

“Towards a World Natural Gas Market, Observations along the Way” Presented to Ontario Energy Association. Toronto, Ontario, Canada. April 28, 2005.

“LNG at the Tipping Point,” Infocast National LNG Conference. Houston, Texas. July 28, 2003 “How to Structure a Financeable Fuel Arrangement,” Project Finance: The Tutorial, by Infocast. New York,

New York, September 23, 2002 “Natural Gas and Climate Change,” Presented to the Society of Gas Operators, New York, New York,

October 28, 1999 “Buying Gas Today,” presentation to Pennsylvania Association of County Commissioners meeting on

“Getting the Most from Utility Competition;” Harrisburg, PA; May 7, 1997 “Becoming an Energy Services Company,” Presentation to the IGT Energy Marketing Conference, Las

Vegas, NV; Dec. 1996. “Methane Emissions from Natural Gas Pipelines--Current Estimates, Technologies and Practices;” with M.

Lang; presentation to International Energy Agency Conference: “Natural Gas Technologies: A Driving Force for Market Development;” Berlin, Germany, Sept. 1-4, 1996.

“Can Gas Compete on a Long Term Basis? The Implications of Power Industry Restructuring,” Presentation at 14th CERI International Oil and Gas Markets Conference, Calgary, Sept., 1995

“Technologies Affecting Future Gas Demand,” Institute of Gas Technology Conference; Chicago; 1995. "Identifying Risks through Due Diligence and Analyzing Risk Significance: The Technical Perspective,"

Presentation at the INFOCAST Project Finance Tutorial; October, 1993 through 1995. "Getting It Right: The Supply Side of Integrated Resource Planning," paper and presentation to the NARUC-

DOE Integrated Resource Planning Conference in Kalispell, Montana; May, 1994. "Gas Supply Strategies in the Post-Order 636 Environment," Presentation to the American Forest and

Paper Association: Sept. 1993 "Integrated Resource Planning in Gas Utilities," Presentation to The National Regulatory Research Institute

Seminars on The Energy Policy Act of 1992; Indianapolis and Portland, OR; June and July, 1993 "Making Sense of End-Use Gas Price Forecasts," Natural Gas, Nov. 1992. "Environmental Policy and the Natural Gas Exploration and Production Industry," Natural Resources and the

Environment, Spring, 1992. "FERC Order 636," Two day seminar and presentation to staff of the Bonneville Power Administration; May,

1992. "Preparing Bid and Evaluating Response to Competitive Solicitation for Power Projects: A Hands On

Approach," a half day presentation to electric utility executives. "Gas Supply Planning after the Bubble," with W. Hederman, Natural Gas, April 1989.


Appendix C

Steve Seelye Resume

WILLIAM STEVEN SEELYE

Summary of Qualifications Bachelor of Science degree in Mathematics; completed 54 hours of graduate level course work in Industrial Engineering and Physics. Provides consulting services to numerous investor-owned utilities, rural electric cooperatives, and municipal utilities regarding utility rate and regulatory filings, cost of service and wholesale and retail rate designs; and develops revenue requirements for utilities in general rate cases, including the preparation of analyses supporting pro-forma adjustments and the development of rate base. Employment Senior Consultant and Principal Provides consulting services in the areas The Prime Group, LLC of tariff development, regulatory analysis (July 1996 to Present) revenue requirements, cost of service, rate design, fuel and power procurement,

depreciation studies, lead-lag studies, and mathematical modeling.

Assists utilities with developing strategic marketing

plans and implementation of those plans. Provides utility clients assistance regarding regulatory policy and strategy; project management support for utilities involved in complex regulatory proceedings; process audits; state and federal regulatory filing development; cost of service development and support; the development of innovative rates to achieve strategic objectives; unbundling of rates and the development of menus of rate alternatives for use with customers; performance-based rate development.

Prepared retail and wholesale rate schedules and filings submitted to the Federal Energy Regulatory Commission (FERC) and state regulatory commissions for numerous of electric and gas utilities. Performed cost of service studies and developed rates for over 100 utilities throughout North America. Prepared market power analyses in support of market-based rate filings submitted to the FERC for utilities and their marketing affiliates. Performed business practice audits for electric utilities, gas utilities, and independent transmission organizations (ISOs), including audits of production

Appendix C Page 1 of 4

cost modeling, retail utility tariffs, retail utility billing practices, and ISO billing processes and procedures.

Manager of Rates and Other Positions Held various positions in the Rate Louisville Gas & Electric Co. Department of LG&E. In December 1990, (May 1979 to July 1996) promoted to Manager of Rates and Regulatory Analysis. In May 1994, given additional responsibilities in the marketing

area and promoted to Manager of Market Management and Rates.

Education Bachelor of Science Degree in Mathematics, University of Louisville, 1979 54 Hours of Graduate Level Course Work in Industrial Engineering and Physics. Expert Witness Testimony Alabama: Testified in Docket 28101 on behalf of Mobile Gas Service Corporation

concerning rate design and pro-forma revenue adjustments. Colorado: Testified in Consolidated Docket Nos. 01F-530E and 01A-531E on behalf of

Intermountain Rural Electric Association in a territory dispute case. FERC: Submitted direct and rebuttal testimony in Docket No. EL02-25-000 et al.

concerning Public Service of Colorado‘s fuel cost adjustment. Submitted direct and responsive testimony in Case No. ER05-522-001 concerning

a rate filing by Bluegrass Generation Company, LLC to charge reactive power service to LG&E Energy, LLC.

Submitted testimony in Case Nos. ER07-1383-000 and ER08-05-000 concerning

Duke Energy Shared Services, Inc.’s charges for reactive power service. Florida: Testified in Docket No. 981827 on behalf of Lee County Electric Cooperative,

Inc. concerning Seminole Electric Cooperative Inc.’s wholesale rates and cost of service.

Illinois: Submitted direct, rebuttal, and surrebuttal testimony in Docket No. 01-0637 on

behalf of Central Illinois Light Company (“CILCO”) concerning the modification of interim supply service and the implementation of black start service in connection with providing unbundled electric service.


Indiana: Submitted direct testimony and testimony in support of a settlement agreement in Cause No. 42713 on behalf of Richmond Power & Light regarding revenue requirements, class cost of service studies, fuel adjustment clause and rate design.

Submitted direct and rebuttal testimony in Cause No. 43111 on behalf of Vectren

Energy in support of a transmission cost recovery adjustment. Kansas: Submitted direct and rebuttal testimony in Docket No. 05-WSEE-981-RTS on

behalf of Westar Energy, Inc. and Kansas Gas and Electric Company regarding transmission delivery revenue requirements, energy cost adjustment clauses, fuel normalization, and class cost of service studies.

Kentucky: Testified in Administrative Case No. 244 regarding rates for cogenerators and

small power producers, Case No. 8924 regarding marginal cost of service, and in numerous 6-month and 2-year fuel adjustment clause proceedings.

Submitted direct and rebuttal testimony in Case No. 96-161 and Case No. 96-362

regarding Prestonsburg Utilities’ rates. Submitted direct and rebuttal testimony in Case No. 99-046 on behalf of Delta

Natural Gas Company, Inc. concerning its rate stabilization plan. Submitted direct and rebuttal testimony in Case No. 99-176 on behalf of Delta

Natural Gas Company, Inc. concerning cost of service, rate design and expense adjustments in connection with Delta’s rate case.

Submitted direct and rebuttal testimony in Case No. 2000-080, testified on behalf

of Louisville Gas and Electric Company concerning cost of service, rate design, and pro-forma adjustments to revenues and expenses.

Submitted rebuttal testimony in Case No. 2000-548 on behalf of Louisville Gas

and Electric Company regarding the company’s prepaid metering program. Testified on behalf of Louisville Gas and Electric Company in Case No. 2002-

00430 and on behalf of Kentucky Utilities Company in Case No. 2002-00429 regarding the calculation of merger savings.

Submitted direct and rebuttal testimony in Case No. 2003-00433 on behalf of

Louisville Gas and Electric Company and in Case No. 2003-00434 on behalf of Kentucky Utilities Company regarding pro-forma revenue, expense and plant adjustments, class cost of service studies, and rate design.

Submitted direct and rebuttal testimony in Case No. 2004-00067 on behalf of

Delta Natural Gas Company regarding pro-forma adjustments, depreciation rates, class cost of service studies, and rate design.


Testified on behalf of Kentucky Utilities Company in Case No. 2006-00129 and on behalf of Louisville Gas and electric Company in Case No. 2006-00130 concerning methodologies for recovering environmental costs through base electric rates.

Testified on behalf of Delta Natural Gas Company in Case No. 2007-00089

concerning cost of service, temperature normalization, year-end normalization, depreciation expenses, allocation of the rate increase, and rate design.

Submitted testimony on behalf of Big Rivers Electric Corporation and E.ON U.S.

LLC in Case No 2007-00455 and Case No. 2007-00460 regarding the design and implementation of a Fuel Adjustment Clause, Environmental Surcharge, Unwind Surcredit, Rebate Adjustment, and Member Rate Stability Mechanism for Big Rivers Electric Corporation in connection with the unwind of a lease and purchase power transaction with E.ON U.S. LLC.

Nevada: Submitted direct and rebuttal testimony in Case No. 03-10001 on behalf of

Nevada Power Company regarding cash working capital and rate base adjustments.

Submitted direct and rebuttal testimony in Case No. 03-12002 on behalf of Sierra

Pacific Power Company regarding cash working capital. Submitted direct and rebuttal testimony in Case No. 05-10003 on behalf of

Nevada Power Company regarding cash working capital for an electric general rate case.


Pacific Power Company regarding cash working capital for a gas general rate case.

Submitted direct and rebuttal testimony in Case Nos. 06-11022 and 06-11023 on

behalf of Nevada Power Company regarding cash working capital for a gas general rate case.


Pacific Power Company regarding cash working capital for an electric general rate case.

Nova Scotia: Testified on behalf of Nova Scotia Power Company in NSUARB – NSPI – P-887

regarding the development and implementation of a fuel adjustment mechanism. Submitted testimony in NSUARB – NSP – P-884 regarding Nova Scotia Power

Company’s application to approve a demand-side management plan and cost recovery mechanism.


Appendix D

Operating Maintenance and General (OM&G) Expense Line-by-Line Account and Variance Analysis

Redacted

REACTED Appendix D Page 1 of 48

Appendix E

Five Year OM&G Summary

Redacted

REDACTED Appendix E Page 1 of 1

Appendix F

Kathleen McShane Resume

________________________________________________________________________________________________________________________ Foster Associates, Inc.

QUALIFICATIONS OF KATHLEEN C. McSHANE

Kathleen McShane is President and senior consultant with Foster Associates, Inc., where she has

been employed since 1981. She holds an M.B.A. degree in Finance from the University of Florida,

and M.A. and B.A. degrees from the University of Rhode Island. She has been a CFA charterholder

since 1989.

Ms. McShane worked for the University of Florida and its Public Utility Research Center,

functioning as a research and teaching assistant, before joining Foster Associates. She taught both

undergraduate and graduate classes in financial management and assisted in the preparation of a

financial management textbook.

At Foster Associates, Ms. McShane has worked in the areas of financial analysis, energy economics

and cost allocation. Ms. McShane has presented testimony in more than 190 proceedings on rate of

return and capital structure before federal, state, provincial and territorial regulatory boards, on

behalf of U.S. and Canadian telephone companies, gas pipelines and distributors, and electric

utilities. These testimonies include the assessment of the impact of business risk factors (e.g.,

competition, rate design, contractual arrangements) on capital structure and equity return

requirements. She has also testified on various ratemaking issues, including deferral accounts, rate

stabilization mechanisms, excess earnings accounts, cash working capital, and rate base issues. Ms.

McShane has provided consulting services for numerous U.S. and Canadian companies on financial

and regulatory issues, including financing, dividend policy, corporate structure, cost of capital,

automatic adjustments for return on equity, form of regulation (including performance-based

regulation), unbundling, corporate separations, stand-alone cost of debt, regulatory climate, income

tax allowance for partnerships, change in fiscal year end, treatment of inter-corporate financial

transactions, and the impact of weather normalization on risk.

Ms. McShane was principal author of a study on the applicability of alternative incentive regulation

proposals to Canadian gas pipelines. She was instrumental in the design and preparation of a study

of the profitability of 25 major U.S. gas pipelines, in which she developed estimates of rate base,

capital structure, profit margins, unit costs of providing services, and various measures of return on

Appendix F Page 1 of 6


investment. Other studies performed by Ms. McShane include a comparison of municipal and

privately owned gas utilities, an analysis of the appropriate capitalization and financing for a new

gas pipeline, risk/return analyses of proposed water and gas distribution companies and an

independent power project, pros and cons of performance-based regulation, and a study on pricing

of a competitive product for the U.S. Postal Service. She has also conducted seminars on cost of

capital for regulated utilities, with focus on the Canadian regulatory arena.

Publications, Papers and Presentations ■ Utility Cost of Capital: Canada vs. U.S., presented at the CAMPUT Conference, May 2003. ■ The Effects of Unbundling on a Utility’s Risk Profile and Rate of Return, (co-authored with

Owen Edmondson, Vice President of ATCO Electric), presented at the Unbundling Rates Conference, New Orleans, Louisiana sponsored by Infocast, January 2000.

■ Atlanta Gas Light’s Unbundling Proposal: More Unbundling Required? presented at the

24th Annual Rate Symposium, Kansas City, Missouri, sponsored by several commissions and universities, April 1998.

■ Incentive Regulation: An Alternative to Assessing LDC Performance, (co-authored with Dr.

William G. Foster), presented at the Natural Gas Conference, Chicago, Illinois sponsored by the Center for Regulatory Studies, May 1993.

■ Alternative Regulatory Incentive Mechanisms, (co-authored with Stephen F. Sherwin),

prepared for the National Energy Board, Incentive Regulation Workshop, October 1992.



EXPERT TESTIMONY/OPINIONS

ON

RATE OF RETURN & CAPITAL STRUCTURE

Client Date

Alberta Natural Gas 1994

AltaGas Utilities 2000

Ameren (Central Illinois Public Service) 2000, 2002, 2005, 2007 (2 cases)

Ameren (Central Illinois Light Company) 2005, 2007 (2 cases)

Ameren (Illinois Power) 2004, 2005, 2007 (2 cases)

Ameren (Union Electric) 2000 (2 cases), 2002 (2 cases), 2003, 2006 (2 cases)

ATCO Electric 1989, 1991, 1993, 1995, 1998, 1999, 2000, 2003

ATCO Gas 2000, 2003, 2007

ATCO Pipelines 2000, 2003, 2007

Bell Canada 1987, 1993

Benchmark Utility Cost of Equity (British Columbia) 1999

Canadian Western Natural Gas 1989, 1996, 1998, 1999

Centra Gas B.C. 1992, 1995, 1996, 2002

Centra Gas Ontario 1990, 1991, 1993, 1994, 1995

Direct Energy Regulated Services 2005

Dow Pool A Joint Venture 1992

Edmonton Water/EPCOR Water Services 1994, 2000, 2006

Enbridge Gas Distribution 1988, 1989, 1991-1997, 2001, 2002

Enbridge Gas New Brunswick 2000

Enbridge Pipelines (Line 9) 2007

Enbridge Pipelines (Southern Lights) 2007

FortisBC 1995, 1999, 2001, 2004

Gas Company of Hawaii 2000

Gaz Metropolitain 1988

Gazifère 1993, 1994, 1995, 1996, 1997, 1998



Generic Cost of Capital, Alberta (ATCO and AltaGas Utilities) 2003

Heritage Gas 2004

Hydro One 1999, 2001, 2006 (2 cases)

Insurance Bureau of Canada (Newfoundland) 2004

Laclede Gas Company 1998, 1999, 2001, 2002, 2005

Mackenzie Valley Pipeline 2005

Maritimes NRG (Nova Scotia) and (New Brunswick) 1999

Multi-Pipeline Cost of Capital Hearing (National Energy Board) 1994

Natural Resource Gas 1994, 1997, 2006

New Brunswick Power Distribution 2005

Newfoundland & Labrador Hydro 2001, 2003

Newfoundland Power 1998, 2002, 2007

Newfoundland Telephone 1992

Northland Utilities 2008 (2 cases)

Northwestel, Inc. 2000, 2006

Northwestern Utilities 1987, 1990

Northwest Territories Power Corp. 1990, 1992, 1993, 1995, 2001, 2006

Nova Scotia Power Inc. 2001, 2002, 2005

Ontario Power Generation 2007

Ozark Gas Transmission 2000

Pacific Northern Gas 1990, 1991, 1994, 1997, 1999, 2001, 2005

Plateau Pipe Line Ltd. 2007

Platte Pipeline Co. 2002

St. Lawrence Gas 1997, 2002

Southern Union Gas 1990, 1991, 1993

Stentor 1997

Tecumseh Gas Storage 1989, 1990

Telus Québec 2001

Terasen Gas 1992, 1994, 2005

TransCanada PipeLines 1988, 1989, 1991 (2 cases), 1992, 1993

TransGas and SaskEnergy LDC 1995



Trans Québec & Maritimes Pipeline 1987

Union Gas 1988, 1989, 1990, 1992, 1994, 1996, 1998, 2001

Westcoast Energy 1989, 1990, 1992 (2 cases), 1993, 2005

Yukon Electric Co. Ltd./Yukon Energy 1991, 1993



EXPERT TESTIMONY/OPINIONS

ON

OTHER ISSUES

Client Issue Date

New Brunswick Power Distribution Interest Coverage/Capital Structure 2007

Heritage Gas Revenue Deficiency Account 2006

Hydro Québec Cash Working Capital 2005

Nova Scotia Power Cash Working Capital 2005

Ontario Electricity Distributors Stand-Alone Income Taxes 2005

Caisse Centrale de Réassurance Collateral Damages 2004

Hydro Québec Cost of Debt 2004

Enbridge Gas New Brunswick AFUDC 2004

Heritage Gas Deferral Accounts 2004

ATCO Electric Carrying Costs on Deferral Account 2001

Newfoundland & Labrador Hydro Rate Base, Cash Working Capital 2001

Gazifère Inc. Cash Working Capital 2000

Maritime Electric Rate Subsidies 2000

Enbridge Gas Distribution Principles of Cost Allocation 1998

Enbridge Gas Distribution Unbundling/Regulatory Compact 1998

Maritime Electric Form of Regulation 1995

Northwest Territories Power Rate Stabilization Fund 1995

Canadian Western Natural Gas Cash Working Capital/ Compounding Effect

1989

Gaz Metro/ Province of Québec

Cost Allocation/ Incremental vs. Rolled-In Tolling

1984


Appendix G

Development of Incremental Equity Risk Premium for NSPI

DEVELOPMENT OF INCREMENTAL

EQUITY RISK PREMIUM FOR NSPI

RELATIONSHIP BETWEEN CAPITAL STRUCTURE AND ROE

There are effectively two approaches that can be used to determine the fair return. The first is to

assess the specific regulated company’s business risks, and then establish a capital structure that

is compatible with its business risks and permits the application of the cost of equity determined

by reference to proxies to the specific regulated company without any adjustment to the proxy

companies’ cost of equity.

The second approach entails acceptance of the specific regulated company’s actual capital

structure for regulatory purposes, or deeming a capital structure that adequately protects

bondholders but does not necessarily equate the total (business and financial) risk of the

regulated company to those of the proxies or “benchmark”. The actual or deemed capital

structure then becomes the key measure of the utility’s financial risks. The utility’s level of total

risk (business plus financial) is compared to that faced by the proxy companies used to estimate

the equity return requirement. If the total risk of the proxy companies is higher or lower than

that of the specific regulated company utility, an adjustment to the proxies’ cost of equity would

be required when setting the specific regulated company’s allowed return on equity.

Both of these approaches have been taken by regulators in Canada. The first approach was

employed by the National Energy Board when it established its multi-pipeline return on equity

and automatic adjustment mechanism for a number of Group 1 oil and gas pipelines in RH-2-94

(March 1995) and more recently by the Alberta Energy and Utilities Board in its generic cost of

capital decision (Decision 2004-052, July 2004). The second approach is the approach that has

been taken by the British Columbia Utilities Commission, the Ontario Energy Board and the

Régie de l’Énergie de Québec.

____________________________________________________________________________________________________________________

Foster Associates, Inc.

Appendix G Page 1 of 5

Both approaches are valid as long as the combination of capital structure and return on equity for

a particular utility produces a reasonable balance of capital structure and ROE and compensates

equity shareholders for the utility’s business risk relative to that of its peers or the benchmark.

Each of the approaches recognizes that the cost of capital is largely a function of business risk.

Business risk comprises the operating elements of the business that together determine the

probability that future returns to investors will fall short of their expected and required returns. In

other words, business risk is a function of the fundamental characteristics of the operations, i.e.,

of the firm’s assets. The cost of capital is also a function of financial risk. Financial risk refers

to the additional risk that is borne by the equity shareholder because the firm is using fixed

income securities – debt and preferred shares – to finance a portion of its assets. The capital

structure, comprised of debt, preferred shares and common equity, can be viewed as a summary

measure of the financial risk of the firm.

The use of debt creates a class of investors whose claims on the resources of the firm take

precedence over those of the equity holder. Since the issuance of debt carries fixed costs which

must be paid before the equity shareholder receives any return, the addition of debt to the capital

structure increases the potential variability of the equity shareholder’s return. Thus, as the debt

ratio rises, the cost of equity rises. In the absence of the deductibility of interest expense for

corporate income tax purposes and costs associated with the use of excessive debt (bankruptcy,

financial distress, loss of operating/financial flexibility), the increase in the cost of equity offsets

the increase in the debt ratio, so the overall cost of capital to a firm would not change materially

if the firm were to change its capital structure.

The existence of corporate income taxes and the deductibility of interest for income tax

purposes, in conjunction with the costs associated with potential bankruptcy or loss of financial

flexibility, alter the conclusion that the cost of capital is constant across all capital structures.

The deductibility of interest expense for income tax purposes means that there is a cash flow

advantage to equity holders from the assumption of debt. When interest expense is deductible

for income tax purposes, the after-tax cost of capital is reduced when debt is used. However, as

the proportion of debt in the capital structure increases, the cost of capital tends to increase due

____________________________________________________________________________________________________________________



to the loss of financial flexibility and increased potential for bankruptcy, partially offsetting the

tax advantage. In addition, although interest expense is tax deductible at the corporate level, it is

taxable to investors at a higher rate than equity, offsetting some of the net after-tax advantage of

increasing the debt component of the capital structure. Further, in the specific case of regulated

companies, the benefits from the tax deductibility of interest flow through to customers.

While it is impossible to state with precision whether, within a reasonable range of capital

structures, raising the debt ratio decreases the overall cost of capital or leaves it unchanged, in

either case the costs of the components of the capital structure do change. An increase in

financial risk will be accompanied by an increase in the cost of equity. The amount by which the

cost of common equity increases for a given increase in the debt ratio can be estimated under

each of two theories.

Theory 1

The cost of capital remains unchanged as the capital structure changes.

Theory 2

The cost of capital declines as the percentage of debt in the capital structure increases.

Schedule 3 provides the formulas required to estimate the change in the cost of equity for a

change in common equity ratio under each theory.

The actual impact on the cost of capital most likely lies in between the results of the two

theories; income taxes and the deductibility of interest do tend to decrease the cost of capital (as

the income trust market has demonstrated), but as the debt ratio rises, there are increasing costs

in terms of loss of financing flexibility and potential bankruptcy. Moreover, as indicated above,

in the case of regulated companies, the benefit of the tax deductibility of interest is to the benefit

of ratepayers, while in the unregulated sector, the benefit goes to the shareholder. Since both

____________________________________________________________________________________________________________________



capital structure theories have merit, both were applied to estimate the impact of a change in

capital structure on return on equity.

APPLICATION OF CAPITAL STRUCTURE THEORY TO ESTIMATE THE INCREMENTAL EQUITY RISK PREMIUM For rate setting purposes, NSPI’s regulated capital structure contains 37.5 percent common

equity. However, the common equity ratio that would fully compensate for NSPI’s higher

business risks relative to those adopted for the regulated Canadian “wires” and “pipes” utilities,

assuming the operation of the FAM as proposed, would be no less than 45 percent. Through the

application of the capital structure theories set out above, the differential in capital structure

between NSPI’s 37.5 percent common equity ratio and the 45 percent common equity ratio that

would effectively offset the higher financial risks inherent in NSPI’s capital structure can be

translated into an incremental equity risk premium.

For different required returns on equity (or equity risk premiums) at different capital structures

begins with the recognition that the overall cost of capital for a firm is primarily a function of

business risk. In the absence of the deductibility of interest expense for corporate income tax

purposes and bankruptcy and financial distress costs associated with the use of excessive debt,

the overall cost of capital to a firm would not change materially if the firm were to change its

capital structure.

To estimate the incremental risk premium that is required to compensate for the difference

between the financial risk inherent in NSPI’s 37.5 percent common equity ratio and the 45

percent common equity ratio that would effectively offset the higher financial risks, the

following steps were taken:

1. Estimate NSPI’s weighted average cost of capital using a common equity ratio of

45 percent, a cost of long-term debt equal to 6.0 percent,1 an ROE of 8.8 percent

equal to the average 2008 allowed return of other major Canadian utilities whose

1 The 6.0% cost of new debt represents the forecast long-term GOC bond yield of 4.5% plus a spread of 150 basis points, approximately equal to the February 2008 spread on Canadian A/A(low) rated long-term utility debt. ____________________________________________________________________________________________________________________



debt is rated by one or more of the major debt rating agencies, and a statutory

corporate income tax rate of 35 percent (combined Federal corporate/Nova Scotia

income tax rate for 2009).

2. Estimate the incremental risk premium required to account for the difference in

financial risk between NSPI’s allowed common equity ratio of 37.5 percent and

the 45 percent common equity ratio that would effectively offset to higher

business risks.

To summarize the results found on Schedule 3, based on Theory 1 (no change in cost of capital

as the equity ratio declines), the difference between an equity ratio of 45 percent and an equity

ratio of 37.5 percent translates into an incremental equity risk premium of approximately 100

basis points. Thus, based on Theory 1, the required ROE increases from 8.8 percent to 9.8

percent. Based on Theory 2 (cost of capital declines as the equity ratio declines), the difference

between a common equity ratio of 45 percent and a common equity ratio of 37.5 percent

translates into an incremental equity risk premium of approximately 50 basis points, increasing

the ROE from 8.8 percent to 9.3 percent.2 Since both theories have merit, it is reasonable to give

weight to both. Based on the mid-point of the range of the results of the two theories, the

indicated incremental equity risk premium required to compensate for the difference between

NSPI’s 37.5 percent and the 45 percent equity ratio that would be warranted to offset its higher

business risk is 70 basis points; the corresponding ROE is 9.5 percent.

2 A third approach assumes that there are no income taxes, an assumption that recognizes that the benefit of the deductibility in interest expense for regulated companies flows to rate payers. In the absence of corporate income taxes – equivalent to a constant return on rate base – the required ROE would need to be increased from 8.8% to approximately 9.4% to compensate for the financial risk difference between common equity ratios of 45% and 37.5%. ____________________________________________________________________________________________________________________



Appendix H

Schedules Referenced in Testimony of Kathleen McShane

Table of Contents

SCHEDULE 1: Page 1 Equity Return Awards and Capital Structures Adopted by

Regulatory Boards for Canadian Utilities Page 2 Rates of Return on Common Equity Adopted by Regulatory

Boards for Investor-Owned Canadian Utilities Page 3 Comparison Between Allowed Returns on Equity for Canadian

and U.S. Utilities Page 4 Allowed ROEs and Long-Term Government Bond Yields –

Canada and U.S. SCHEDULE 2: Pages 1 & 2 Trend in Interest Rates and Outstanding Bond Yields SCHEDULE 3: Pages 1 & 2 Quantification of Impact on Equity Return Requirement for

Difference Between 37.5% and 45.0% Common Equity Ratios SCHEDULE 4: Page 1 Individual Company Risk Data for Nova Scotia Power and the

Sample of U.S. Electric Utilities Page 2 Equity Return Awards and Common Equity Ratios Adopted

for the Sample of U.S. Electric Utilities (2006-2008) SCHEDULE 5: DCF Costs of Equity for Sample of U.S. Electric Utilities

Appendix H Page 1 of 12

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1991

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1998

1999

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2003

2004

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2006

2007

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Schedule 2Page 1 of 2

Canada Bonds Canadian Scotia Capital Canadian Moody's U.S. Utility Exchange RatesOver 10 Inflation Long-Term A-Rated Long-Term (Canadian dollars

Year Canadian U.S. 1/ Canadian U.S. Canadian U.S. 2/ Years 3/ Indexed Bonds Corporates Utility Bonds 4/ A-Rated Bonds in U.S. funds)

1993 q1 5.84 2.96 7.65 6.28 8.27 6.98 8.38 4.57 9.54 9.54 8.07 0.79q2 4.91 3.01 7.46 5.99 8.11 6.87 8.12 4.39 9.16 9.35 7.81 0.79q3 4.52 3.02 6.99 5.62 7.63 6.29 7.58 4.21 8.50 8.84 7.28 0.77q4 4.11 3.09 6.76 5.61 7.42 6.19 7.31 3.94 8.20 8.58 7.22 0.75

1994 q1 4.29 3.42 7.09 6.07 7.67 6.74 7.48 3.80 8.33 8.79 7.53 0.75q2 6.28 3.96 8.49 7.08 8.69 7.33 8.67 4.38 9.52 10.09 8.29 0.72q3 5.48 4.61 8.99 7.33 9.13 7.55 9.14 4.67 9.92 10.11 8.51 0.73q4 6.11 5.36 9.12 7.84 9.25 7.94 9.23 4.80 10.00 10.24 8.87 0.73

1995 q1 7.99 5.73 8.89 7.48 9.01 7.61 8.99 4.86 9.80 9.99 8.54 0.71q2 7.34 5.58 8.00 6.62 8.32 6.91 8.19 4.48 8.93 9.38 7.93 0.73q3 6.47 5.32 8.05 6.32 8.45 6.71 8.28 4.76 8.97 9.30 7.72 0.74q4 5.76 5.15 7.39 5.89 7.85 6.18 7.66 4.61 8.37 8.44 7.37 0.74

1996 q1 5.11 4.92 7.39 5.91 7.95 6.37 7.71 4.78 8.40 8.41 7.44 0.73q2 4.70 5.04 7.75 6.72 8.17 6.95 7.99 4.87 8.60 8.58 7.98 0.73q3 4.14 5.13 7.37 6.78 7.88 7.00 7.65 4.71 8.22 8.23 7.96 0.73q4 2.89 5.08 6.30 6.34 6.99 6.60 6.67 4.07 7.23 7.19 7.62 0.74

1997 q1 2.96 5.11 6.54 6.64 7.24 6.91 6.94 4.19 7.50 7.52 7.76 0.74q2 3.00 5.12 6.49 6.64 7.03 6.90 6.80 4.26 7.28 7.30 7.88 0.72q3 3.18 5.06 5.85 6.18 6.39 6.45 6.16 4.06 6.64 6.59 7.49 0.72q4 3.89 5.14 5.55 5.84 5.98 6.07 5.79 4.07 6.38 6.34 7.25 0.71

1998 q1 4.44 5.08 5.41 5.63 5.76 5.93 5.60 4.07 6.25 6.22 7.11 0.70q2 4.82 4.99 5.39 5.58 5.63 5.80 5.53 3.90 6.09 6.05 7.12 0.69q3 4.92 4.76 5.36 5.12 5.59 5.35 5.50 4.00 6.31 6.23 6.99 0.66q4 4.75 4.34 5.02 4.72 5.38 5.10 5.23 4.12 6.25 6.16 6.97 0.65

1999 q1 4.73 4.41 5.07 5.03 5.34 5.41 5.23 4.13 6.13 6.15 7.11 0.66q2 4.55 4.53 5.34 5.56 5.54 5.80 5.50 4.07 6.40 6.34 7.48 0.68q3 4.92 4.76 5.36 5.12 5.59 5.35 5.50 4.00 6.31 6.23 6.99 0.66q4 4.75 4.34 5.02 4.72 5.38 5.10 5.23 4.12 6.25 6.16 6.97 0.65

2000 q1 5.09 5.59 6.22 6.38 5.98 6.16 6.10 3.91 7.14 7.07 8.29 0.69q2 5.54 5.68 6.01 6.18 5.72 5.96 5.96 3.74 7.21 7.05 8.45 0.68q3 5.58 6.05 5.79 5.86 5.58 5.78 5.82 3.64 7.07 7.09 8.20 0.67q4 5.57 6.09 5.54 5.46 5.56 5.62 5.67 3.48 7.10 7.15 8.03 0.65

2001 q1 4.96 4.64 5.44 5.01 5.76 5.45 5.69 3.41 7.05 7.18 7.74 0.65q2 4.36 4.42 5.78 5.40 5.95 5.77 6.00 3.56 7.25 7.40 7.93 0.65q3 3.64 3.10 5.48 4.84 5.82 5.44 5.86 3.67 7.13 7.24 7.64 0.64q4 2.11 1.86 5.22 4.72 5.53 5.32 5.58 3.68 6.95 7.20 7.61 0.63

2002 q1 2.10 1.78 5.52 5.12 5.78 5.66 5.81 3.71 6.97 7.23 7.63 0.63q2 2.57 1.74 5.51 5.02 5.83 5.72 5.81 3.52 6.99 7.14 7.48 0.65q3 2.83 1.66 5.07 4.09 5.56 5.13 5.52 3.36 7.01 7.26 7.14 0.63q4 2.69 1.33 4.98 3.99 5.48 5.11 5.45 3.39 6.95 7.23 7.12 0.64

2003 q1 2.96 1.17 5.01 3.85 5.49 4.93 5.43 3.09 6.92 7.22 6.84 0.67q2 3.14 1.05 4.59 3.60 5.17 4.71 5.09 3.04 6.42 6.72 6.37 0.72q3 2.70 0.96 4.75 4.30 5.30 5.28 5.26 3.11 6.40 6.69 6.61 0.72q4 2.62 0.95 4.78 4.31 5.29 5.22 5.24 2.90 6.24 6.47 6.34 0.77

2004 q1 2.12 0.94 4.41 4.00 5.09 4.96 4.99 2.50 5.92 6.17 6.06 0.76q2 1.98 1.13 4.74 4.60 5.29 5.35 5.22 2.38 6.25 6.48 6.45 0.74q3 2.23 1.58 4.66 4.26 5.14 5.08 5.13 2.29 6.19 6.37 6.11 0.77q4 2.53 2.11 4.40 4.22 4.92 4.93 4.87 2.18 5.90 6.09 5.95 0.83

2005 q1 2.47 2.67 4.27 4.33 4.72 4.70 4.69 2.05 5.67 5.86 5.72 0.82q2 2.46 3.01 3.93 4.05 4.39 4.36 4.35 1.86 5.23 5.59 5.43 0.81q3 2.73 3.50 3.88 4.21 4.20 4.39 4.19 1.75 5.15 5.32 5.49 0.84q4 3.25 4.00 4.07 4.49 4.19 4.63 4.21 1.59 5.22 5.36 5.82 0.85

2006 q1 3.70 4.57 4.18 4.65 4.23 4.70 4.25 1.53 5.31 5.43 5.92 0.87q2 4.17 4.84 4.51 5.11 4.54 5.19 4.57 1.81 5.69 5.75 6.41 0.90q3 4.14 5.00 4.14 4.79 4.21 4.91 4.23 1.67 5.37 5.45 6.09 0.89q4 4.16 5.04 4.00 4.59 4.07 4.70 4.08 1.68 5.21 5.27 5.82 0.87

2007 q1 4.17 5.11 4.10 4.68 4.17 4.82 4.18 1.77 5.23 5.36 5.92 0.86q2 4.29 4.82 4.39 4.85 4.35 4.98 4.38 1.94 5.61 5.61 6.08 0.92q3 4.17 4.26 4.43 4.64 4.45 4.86 4.46 2.09 na 5.79 6.19 0.97q4 3.90 3.48 4.09 4.16 4.21 4.53 4.21 2.01 na 5.68 6.05 1.02

Annual1990 12.81 7.49 10.76 8.55 10.69 8.61 10.85 11.91 12.13 9.86 0.861991 8.73 5.38 9.42 7.86 9.72 8.14 9.76 10.80 11.00 9.36 0.841992 6.59 3.43 8.05 7.01 8.68 7.67 8.77 4.62 9.90 10.01 8.64 0.821993 4.84 3.02 7.22 5.87 7.86 6.59 7.85 4.28 8.85 9.08 7.59 0.771994 5.54 4.34 8.43 7.08 8.69 7.39 8.63 4.41 9.44 9.81 8.30 0.73

1995 6.89 5.44 8.08 6.58 8.41 6.85 8.28 4.68 9.02 9.29 7.89 0.731996 4.21 5.04 7.20 6.44 7.75 6.73 7.50 4.61 8.11 8.38 7.75 0.731997 3.26 5.11 6.11 6.32 6.66 6.58 6.42 4.14 6.95 7.19 7.60 0.721998 4.73 4.79 5.30 5.26 5.59 5.54 5.47 4.02 6.22 6.38 7.04 0.681999 4.69 4.71 5.55 5.68 5.72 5.91 5.69 4.07 6.64 6.92 7.62 0.67

2000 5.45 5.85 5.89 5.98 5.71 5.88 5.89 3.69 7.13 7.02 8.24 0.672001 3.78 3.34 5.49 4.99 5.77 5.50 5.76 3.59 7.09 7.25 7.73 0.652002 2.55 1.63 5.27 4.56 5.67 5.41 5.65 3.49 6.98 7.22 7.35 0.642003 2.86 1.03 4.78 4.02 5.31 5.03 5.26 3.04 6.50 6.78 6.54 0.722004 2.21 1.44 4.55 4.27 5.11 5.08 5.05 2.34 6.06 6.28 6.14 0.772005 2.73 3.29 4.04 4.27 4.38 4.52 4.36 1.81 5.32 5.53 5.62 0.832006 4.05 4.86 4.21 4.79 4.26 4.87 4.28 1.67 5.40 5.47 6.06 0.892007 4.13 4.42 4.25 4.58 4.30 4.80 4.31 1.95 5.42 5.61 6.06 0.94

1/ Rates on new issues.2/ 30-year maturities through January 2002. Theoretical 30-year yield, February 2002 to January 2006.3/ Terms to maturity of l0 years or more.4/ Series is comprised of the CBRS Utilities Index through 1995; CBRS 30-year Utilities Index from 1996- August 2000; a series of liquid long-term utility bonds maintained by Foster Associates from September 2000 forward.

Source: www.bankofcanada.ca; Globe and Mail; www.federalreserve.gov www.ustreas.gov

TREND IN INTEREST RATES AND OUTSTANDING BOND YIELDS(Percent Per Annum)

T-Bills 10 Year Long-Term

Government Securities


Schedule 2Page 2 of 2

Canada Bonds Canadian Scotia Capital Canadian Moody's U.S. Utility Exchange RatesOver 10 Inflation Long-Term A-Rated Long-Term (Canadian dollars

Year Canadian U.S. 1/ Canadian U.S. Canadian U.S. 2/ Years 3/ Indexed Bonds Corporates 4/ Utility Bonds 5/ A-Rated Bonds in U.S. funds)

2004 Jan 2.25 0.92 4.53 4.16 5.17 5.07 5.09 2.59 6.03 6.26 6.11 0.76Feb 2.12 0.96 4.36 3.99 5.05 4.95 4.94 2.52 5.87 6.13 6.08 0.75Mar 1.98 0.95 4.33 3.86 5.04 4.87 4.94 2.39 5.85 6.11 6.01 0.76Apr 1.92 0.98 4.62 4.53 5.24 5.36 5.15 2.46 6.15 6.41 6.46 0.73May 2.00 1.08 4.78 4.66 5.31 5.29 5.22 2.31 6.25 6.43 6.53 0.73June 2.01 1.33 4.83 4.62 5.33 5.41 5.30 2.37 6.36 6.60 6.36 0.75Jul 2.07 1.45 4.75 4.50 5.24 5.31 5.24 2.31 6.34 6.49 6.36 0.75Aug 2.17 1.59 4.60 4.13 5.09 4.97 5.08 2.24 6.17 6.33 6.02 0.76Sep 2.44 1.71 4.63 4.14 5.08 4.97 5.06 2.33 6.05 6.29 5.96 0.79Oct 2.57 1.91 4.47 4.05 4.94 4.87 4.91 2.26 5.99 6.17 5.89 0.82Nov 2.55 2.23 4.44 4.36 4.98 5.07 4.93 2.21 5.88 6.16 6.07 0.84Dec 2.48 2.22 4.30 4.24 4.83 4.86 4.77 2.07 5.82 5.94 5.99 0.83

2005 Jan 2.43 2.51 4.21 4.14 4.71 4.62 4.67 2.03 5.66 5.84 5.65 0.81Feb 2.46 2.76 4.28 4.36 4.75 4.71 4.71 2.09 5.62 5.86 5.76 0.81Mar 2.52 2.73 4.32 4.50 4.71 4.76 4.68 2.03 5.73 5.87 5.75 0.83Apr 2.45 2.90 4.14 4.21 4.58 4.53 4.54 1.90 5.04 5.79 5.54 0.80May 2.45 2.99 3.92 4.00 4.37 4.36 4.31 1.83 5.46 5.59 5.41 0.80Jun 2.48 3.13 3.74 3.94 4.21 4.19 4.20 1.85 5.20 5.40 5.35 0.82Jul 2.59 3.42 3.86 4.28 4.27 4.42 4.27 1.90 5.25 5.42 5.53 0.82Aug 2.72 3.52 3.81 4.02 4.12 4.23 4.09 1.74 5.04 5.23 5.30 0.84Sep 2.87 3.55 3.96 4.34 4.22 4.53 4.21 1.61 5.15 5.33 5.65 0.86Oct 3.06 3.98 4.17 4.57 4.35 4.73 4.36 1.66 5.34 5.49 5.91 0.85Nov 3.31 3.95 4.06 4.52 4.18 4.66 4.20 1.65 5.24 5.35 5.85 0.86Dec 3.39 4.08 3.98 4.39 4.05 4.51 4.06 1.45 5.09 5.23 5.69 0.86

2006 Jan 3.51 4.47 4.17 4.53 4.26 4.69 4.26 1.53 5.30 5.43 5.84 0.88Feb 3.74 4.62 4.12 4.55 4.17 4.51 4.17 1.47 5.27 5.37 5.77 0.88Mar 3.86 4.61 4.26 4.86 4.26 4.89 4.32 1.58 5.37 5.49 6.14 0.86Apr 4.04 4.65 4.51 5.07 4.52 5.17 4.57 1.72 5.67 5.70 6.37 0.89May 4.18 4.86 4.45 5.12 4.50 5.21 4.51 1.83 5.60 5.68 6.43 0.91Jun 4.30 5.01 4.58 5.15 4.61 5.19 4.63 1.88 5.81 5.86 6.43 0.90Jul 4.15 5.10 4.31 4.99 4.37 5.07 4.39 1.73 5.60 5.62 6.29 0.88Aug 4.12 5.02 4.11 4.74 4.19 4.88 4.20 1.62 5.33 5.42 6.07 0.90Sep 4.16 4.89 3.99 4.64 4.08 4.77 4.09 1.67 5.18 5.30 5.90 0.89Oct 4.17 5.08 4.02 4.61 4.08 4.72 4.10 1.69 5.33 5.28 5.84 0.89Nov 4.17 5.03 3.90 4.46 3.99 4.56 4.00 1.60 5.11 5.18 5.68 0.88Dec 4.15 5.02 4.08 4.71 4.14 4.81 4.15 1.75 5.18 5.34 5.95 0.86

2007 Jan 4.17 5.12 4.17 4.83 4.22 4.93 4.23 1.79 5.28 5.41 6.01 0.85Feb 4.19 5.16 4.03 4.56 4.09 4.68 4.10 1.75 5.15 5.28 5.78 0.85Mar 4.16 5.04 4.11 4.65 4.20 4.84 4.21 1.77 5.27 5.39 5.97 0.87Apr 4.16 4.91 4.14 4.63 4.19 4.81 4.20 1.76 5.38 5.45 5.90 0.90May 4.29 4.73 4.49 4.90 4.38 5.01 4.42 1.99 5.63 5.62 6.10 0.93Jun 4.43 4.82 4.55 5.03 4.49 5.12 4.51 2.08 5.82 5.75 6.24 0.94Jul 4.56 4.96 4.52 4.78 4.45 4.92 4.48 2.07 na 5.78 6.18 0.94Aug 3.99 4.01 4.42 4.54 4.46 4.83 4.47 2.14 na 5.76 6.17 0.95Sep 3.96 3.82 4.34 4.59 4.44 4.83 4.44 2.07 na 5.83 6.22 1.01Oct 3.96 3.94 4.31 4.48 4.38 4.74 4.39 2.05 na 5.73 6.07 1.06Nov 3.91 3.15 3.98 3.97 4.16 4.40 4.15 2.07 na 5.69 6.00 1.00Dec 3.82 3.36 3.99 4.04 4.10 4.45 4.10 1.91 na 5.62 6.07 1.01

2008 Jan 3.38 1.96 3.88 3.67 4.18 4.35 4.16 1.96 na 5.81 6.07 1.00Feb 3.04 1.85 3.64 3.53 4.09 4.66 4.04 1.85 na 5.73 6.22 1.02

1/ Rates on new issues.2/ 20-year constant maturities for 1974-1978; 30-year maturities, 1978-January 2002. Theoretical 30-year yield, February 2002 to January 2006.3/ Terms to maturity of l0 years or more.4/ Series discontinued June 2007.5/ Series is comprised of the CBRS Utilities Index through 1995; CBRS 30-year Utilities Index from 1996- August 2000; a series of liquid long-term utility bonds maintained by Foster Associates from September 2000 forward.

Note: Monthly data reflect rate in effect at end of month.

Source: www.bankofcanada.ca; Globe and Mail; www.federalreserve.gov RBC Capital Markets, www.ustreas.gov

TREND IN INTEREST RATES AND OUTSTANDING BOND YIELDS(Percent Per Annum)

T-Bills 10 Year Long-Term

Government Securities


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Term

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t for

A ra

ted

utili

ty =

6.00

%Eq

uity

Cos

t =

Cos

t of E

quity

=8.

80%

Tax

Rat

e =

35.0

%

STE

PS:

1.

Es

timat

e W

AC

C AT

at a

45%

com

mon

equ

ity ra

tio (5

5% d

ebt r

atio

)W

AC

CA

T =

(6.0

0%)(

1-.3

5)(5

5%) +

(8.8

0%)(

45%

) =

6.11

%

2.

Es

timat

e C

ost o

f Equ

ity a

t a 3

7.5%

com

mon

equ

ity ra

tio (6

2.5%

deb

t rat

io) w

ith W

AC

C AT u

ncha

nged

at 6

.11%

WA

CC

AT

=(D

ebt C

ost)(

1-ta

x ra

te)(

Deb

t Rat

io) +

(Equ

ity C

ost)(

Equi

ty R

atio

)

6.11

% =

(6.0

0%)(

1-.3

5)(6

2.5%

) + (X

)(37

.5%

)C

ost o

f Equ

ity a

t 37.

5% E

quity

Rat

io =

9.78

%

3.

D

iffer

ence

bet

wee

n Eq

uity

Ret

urn

at 4

5% a

nd 3

7.5%

com

mon

equ

ity ra

tios:

9.78

% -

8.80

% =

0.98

% (9

8 ba

sis p

oint

s)

DIF

FER

EN

CE

BE

TW

EE

N 3

7.5%

and

45.

0% C

OM

MO

N E

QU

ITY

RA

TIO

SQ

UA

NT

IFIC

AT

ION

OF

IMPA

CT

ON

EQ

UIT

Y R

ET

UR

N R

EQ

UIR

EM

EN

T F

OR

The

afte

r-ta

x w

eigh

ted

aver

age

cost

of c

apita

l (W

AC

C AT)

is in

varia

nt to

cha

nges

in th

e ca

pita

l stru

ctur

e. T

he c

ost o

f equ

ity in

crea

ses a

s lev

erag

e (d

ebt r

atio

) inc

reas

es,

but t

he W

AC

C AT s

tays

the

sam

e.


Sch

edul

e 3

Pag

e 2

of 2

TH

EO

RY

2:

Afte

r-Ta

x C

ost o

f Cap

ital D

ecre

ases

as D

ebt R

atio

Incr

ease

s; C

ost o

f Equ

ity In

crea

ses

WA

CC A

T(M

L)=

WA

CC A

T(LL

) x

(1-tD

ML)

(1-tD

LL)

Whe

reM

L,LL

as b

efor

et =

tax

rate

D =

deb

t rat

ioA

SSU

MPT

ION

S:D

ebt C

ost

=C

urre

nt C

ost o

f Lon

g Te

rm D

ebt f

or A

rate

d ut

ility

=6.

00%

Equi

ty C

ost

=C

ost o

f Equ

ity=

8.80

%Ta

x R

ate

=35

.0%

STE

PS:

1.Es

timat

e W

AC

C AT

at a

45%

com

mon

equ

ity ra

tioW

AC

C AT

=(6

.00%

)(1-

.35)

(55%

) + (8

.80%

)(45

%)

=6.

11%

2.Es

timat

e W

AC

C AT

at a

37.

5% c

omm

on e

quity

ratio

W

AC

C AT(

ML)

= W

AC

CA

T(LL

) x (1

-t x

Deb

t Rat

ioM

L)/(1

-t x

Deb

t Rat

ioLL

)

WA

CC A

T(M

L)=

6.11

%

x

(1-.3

5 x

62.5

%)

(1-.3

5 x

55%

)

WA

CC A

T(M

L)=

5.91

%

3.Es

timat

e C

ost o

f Equ

ity a

t new

WA

CC A

T at

a 3

7.5%

com

mon

equ

ity ra

tio:

WA

CC A

T(M

L) =

(Deb

t Cos

t)(1-

tax

rate

)(D

ebt R

atio

ML)

+ (E

quity

Cos

t)(Eq

uity

Rat

ioM

L)5.

91%

=(6

.00%

)(1-

.35)

(62.

5%) +

(X)(

37.5

%)

Cos

t of E

quity

at 3

7.5%

Equ

ity R

atio

=9.

25%

4.D

iffer

ence

bet

wee

n Eq

uity

Ret

urn

at 4

5% a

nd 3

7.5%

com

mon

equ

ity ra

tios:

9.25

% -

8.80

%=

0.45

% (4

5 ba

sis p

oint

s)

EST

IMA

TE

OF

IMPA

CT

OF

CH

AN

GE

IN E

QU

ITY

RA

TIO

FR

OM

45%

to 3

7.5%

The

ory

1: R

OE

incr

ease

s by

appr

oxim

atel

y 10

0 ba

sis p

oint

sT

heor

y 2:

RO

E in

crea

ses b

y ap

prox

imat

ely

50 b

asis

poi

nts


Sch

edul

e 4

Pag

e 1

of 2

Valu

e Li

ne

Bus

ines

s Pr

ofile

C

ateg

ory

Fina

ncia

l Pr

ofile

C

ateg

ory

EBIT

C

over

age

2004

-200

6FF

O/D

ebt

2004

-200

6 1&

2/

FFO

Inte

rest

C

over

age

2004

-200

6 1/

Deb

t/Cap

ital2/

2004

-200

6D

ebt

Rat

ings

Moo

dy's

D

ebt R

atin

g

2006

Boo

k Va

lue

Com

mon

Equ

ity

Rat

io 3/

(Tot

al C

apita

l)

Ave

rage

A

ctua

l Ret

urn

on E

quity

2004

-200

6

Fore

cast

Ret

urn

on A

vera

ge

Com

mon

Equ

ity

2010

-201

2(1

)(2

)(3

)(4

)(5

)(6

)(7

)(8

)(9

)(1

0)(1

1)

Nov

a Sc

otia

Pow

erSa

tisfa

ctor

y In

term

edia

te2.

4 14

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3.3

68.6

B

BB

Baa

139

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na

Alle

te In

c.S

trong

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iate

3.6

24.7

5.2

52.2

BB

B+

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263

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12.5

%A

llian

t Ene

rgy

Cor

p.E

xcel

lent

Agg

ress

ive

2.5

21.8

4.0

52.3

BB

B+

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leco

Cor

p.S

trong

Agg

ress

ive

4.4

28.5

5.2

51.5

BB

BB

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%17

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nter

gy C

orp.

Stro

ngA

ggre

ssiv

e3.

524

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056

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BB

Baa

345

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12.0

%14

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FPL

Gro

up In

c.E

xcel

lent

Inte

rmed

iate

2.7

22.3

4.5

51.8

AA

244

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12.4

%14

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IDA

CO

RP

Inc.

Stro

ngA

ggre

ssiv

e2.

313

.43.

456

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BB

Baa

249

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8.0%

7.4%

Inte

grys

Ene

rgy

Gro

up In

c.S

trong

Inte

rmed

iate

3.4

13.8

4.1

58.6

A-

A3

42.4

%12

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9.0%

MG

E E

nerg

y In

c.E

xcel

lent

Mod

est

4.5

20.4

5.1

52.4

AA

-A

a354

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10.8

%14

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OG

E E

nerg

y C

orp.

Stro

ngIn

term

edia

te4.

023

.74.

856

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BB

+B

aa1

54.3

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12.4

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tter T

ail C

orp.

Stro

ngIn

term

edia

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725

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350

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BB

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361

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11.7

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PG

&E

Cor

p.E

xcel

lent

Inte

rmed

iate

3.3

18.1

2.7

57.1

BB

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142

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31.6

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Por

tland

Gen

eral

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ctric

Co.

Stro

ngIn

term

edia

te2.

222

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951

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BB

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aa2

53.0

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rogr

ess

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rgy

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elle

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ggre

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115

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BB

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47.2

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Cor

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Agg

ress

ive

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22.5

4.2

57.6

A-

Baa

143

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11.4

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Sou

ther

n C

o.E

xcel

lent

Inte

rmed

iate

3.8

22.3

5.3

57.0

AA

340

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14.9

%13

.0%

Vec

tren

Cor

p.E

xcel

lent

Inte

rmed

iate

2.7

15.9

3.9

55.9

A-

Baa

140

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10.5

%10

.7%

Wis

cons

in E

nerg

y C

orp.

Exc

elle

ntA

ggre

ssiv

e2.

916

.04.

362

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BB

+A

340

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12.0

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Xce

l Ene

rgy

Inc.

Exc

elle

ntA

ggre

ssiv

e2.

215

.63.

462

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BB

+B

aa1

43.6

%8.

8%10

.5%

Ave

rage

Exce

llent

Inte

rmed

iate

3.1

20.4

4.3

55.7

BB

B+

Baa

148

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12.1

%11

.3%

Med

ian

Exce

llent

Inte

rmed

iate

3.1

22.1

4.3

56.4

BB

B+

Baa

146

.5%

11.6

%11

.0%

Not

es:

1/ F

unds

from

Ope

ratio

ns (F

FO) i

s de

fined

as

inco

me

from

con

tinui

ng o

pera

tions

plu

s de

prec

iatio

n, a

mor

tizat

ion,

def

erre

d in

com

e ta

xes

and

inve

stm

ent t

ax c

redi

ts le

ss A

FUD

C a

nd o

ther

FFO

adj

ustm

ents

2/ S

&P

adj

usts

deb

t and

equ

ity fr

om b

ook

valu

es fo

r ope

ratin

g le

ases

, pos

t-ret

irem

ent b

enef

its a

nd d

ebt-l

ike

hybr

ids.

3/ B

ased

on

bala

nce

shee

t val

ues

of s

hort-

term

and

long

-term

deb

t, pr

efer

red

shar

es a

nd c

omm

on e

quity

.

Sou

rces

:

Col

umns

3, 4

, 5 &

6:

S&

P, "

Cre

dit S

tats

: E

lect

ric U

tiliti

es -

U.S

.", "C

redi

t Sta

ts: M

ulti-

Util

ities

- U

.S."

and

"Cre

dit S

tats

: Ele

ctric

Util

ities

- C

anad

a",

Sep

tem

ber 2

007.

Col

umns

7 &

8: S

&P

Rat

ings

(2/1

3/08

); M

oody

's R

atin

gs (2

/21/

08).

Col

umn

9: A

udite

d Fi

nanc

ial S

tate

men

ts 2

007

(NS

PI)

and

S&

P's

Res

earc

h In

sigh

t.

Col

umn

10: S

&P

"Res

earc

h: N

ova

Sco

tia P

ower

", A

pril

18, 2

007

and

S&

P's

Res

earc

h In

sigh

t.C

olum

n 11

: V

alue

Lin

e fr

om N

ovem

ber 3

0, 2

007,

Dec

embe

r 28,

200

7 an

d Fe

brua

ry 8

, 200

8.

Col

umns

1 &

2: S

&P

, "U

.S. R

egul

ated

Ele

ctric

Util

ities

", F

ebru

ary

1, 2

008;

"Iss

uer R

anki

ng: U

.S. N

atur

al G

as D

istri

buto

rs a

nd In

tegr

ated

Gas

Com

pani

es" F

ebru

ary

7, 2

008

(for V

ectre

n);

and

"Issu

er R

anki

ng: C

anad

ian

Gas

and

Ele

ctric

Util

ity C

ompa

nies

", Ja

nuar

y 11

, 200

8 (N

SP

I).

Stan

dard

& P

oor's

IND

IVID

UA

L C

OM

PAN

Y R

ISK

DA

TA F

OR

NO

VA S

CO

TIA

PO

WER

AN

D T

HE

SAM

PLE

OF

U.S

. ELE

CTR

IC U

TILI

TIES


Sch

edul

e 4

Pag

e 2

of 2

Pare

ntSu

bsid

iary

Stat

eD

ecis

ion

Dat

eA

llow

ed R

OE

Allo

wed

C

omm

onEq

uity

Rat

io

Alli

ant E

nerg

y C

orp.

Wis

cons

in P

&L

WI

1/19

/200

710

.80

54.1

3

Ent

ergy

Cor

p.E

nter

gy A

rkan

sas

AR

6/15

/200

79.

9032

.19

IDA

CO

RP

Inc.

Idah

o P

ower

Com

pany

ID5/

12/2

006

10.6

0N

A

Inte

grys

Ene

rgy

Gro

up In

c.W

isco

nsin

Pub

lic S

ervi

ceW

I1/

11/2

007

10.9

057

.46

MG

E E

nerg

y In

c.M

adis

on G

&E

WI

12/1

4/20

0710

.80

57.3

6

OG

E E

nerg

y C

orp.

Okl

ahom

a G

&E

AR

1/5/

2007

10.0

032

.33

PG

&E

Cor

p.P

acifi

c G

&E

CA

12/2

1/20

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52.0

0

Por

tland

Gen

eral

Ele

ctric

Co.

Por

tland

Gen

eral

O

R1/

12/2

007

10.1

050

.00

Sca

na C

orp.

Sou

th C

arol

ina

E&

GS

C12

/14/

2007

10.7

053

.32

Sou

ther

n C

o.G

eorg

ia P

ower

GA

12/3

1/20

0711

.25

NA

Vec

tren

Cor

p.S

outh

ern

Indi

ana

G&

EIN

8/15

/200

710

.40

47.0

5

Wis

cons

in E

nerg

y C

orp.

Wis

cons

in E

lect

ricW

I1/

17/2

008

10.7

554

.36

Xce

l Ene

rgy

Inc.

Nor

ther

n S

tate

Pow

er-M

NM

N9/

1/20

0610

.54

51.6

7

Xce

l Ene

rgy

Inc.

Pub

lic S

ervi

ce o

f CO

CO

12/1

/200

610

.50

60.0

0

Xce

l Ene

rgy

Inc.

Nor

ther

n S

tate

Pow

er-W

IW

I1/

8/20

0810

.75

52.5

1

Ave

rage

200

6-20

0810

.62

50.3

4M

edia

n 20

06-2

008

10.7

052

.51

Sou

rce:

Reg

ulat

ory

Res

earc

h A

ssoc

iate

s

EQU

ITY

RET

UR

N A

WA

RD

S A

ND

CO

MM

ON

EQ

UIT

Y R

ATI

OS

AD

OPT

ED F

OR

TH

E SA

MPL

E O

F U

.S. E

LEC

TRIC

UTI

LITI

ES20

06-2

008


Sch

edul

e 5

Ann

ualiz

edA

vera

ge D

aily

I/B/E

/SD

CF

Last

Pai

dC

losi

ng P

rices

Exp

ecte

dLo

ng-T

erm

EP

S F

orec

asts

Cos

t of

Com

pany

Div

iden

dJa

n 16

-Feb

15,

200

81/

Div

iden

d Y

ield

2/(J

anua

ry 2

008)

Equ

ity 3/

(1)

(2)

(3)

(4)

(5)

Alle

te In

c.1.

6437

.44

4.6

5.0

9.6

Alli

ant E

nerg

y C

orp.

1.40

36.9

34.

06.

010

.0C

leco

Cor

p.0.

9025

.62

4.0

14.0

18.0

Ent

ergy

Cor

p.3.

0010

8.17

3.1

10.6

13.7

FPL

Gro

up In

c.1.

6463

.74

2.8

9.9

12.7

IDA

CO

RP

Inc.

1.20

32.3

03.

96.

09.

9In

tegr

ys E

nerg

y G

roup

Inc.

2.64

49.2

05.

99.

815

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GE

Ene

rgy

Cor

p.1.

1733

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3.8

7.7

11.4

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r Tai

l Cor

p.1.

4440

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3.9

9.7

13.6

PG

&E

Cor

p.0.

9424

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4.1

7.3

11.4

Pro

gres

s E

nerg

y In

c.2.

4644

.98

5.7

5.0

10.8

Sca

na C

orp.

1.76

38.0

24.

84.

79.

5S

outh

ern

Co.

1.61

36.6

84.

65.

09.

6V

ectre

n C

orp.

1.30

27.5

35.

05.

09.

9W

isco

nsin

Ene

rgy

Cor

p.1.

0045

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8.2

10.5

Xce

l Ene

rgy

Inc.

0.92

20.9

04.

76.

010

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Mea

n1.

5641

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4.2

7.5

11.7

Med

ian

1.42

37.1

94.

16.

610

.7

Not

e: M

GE

Ene

rgy

and

Por

tland

Gen

eral

Ele

ctric

exc

lude

d du

e to

lack

of I

/B/E

/S fo

reca

sts.

1/ w

ww

.yah

oo.c

om2/

Exp

ecte

d D

ivid

end

Yie

ld =

(Col

(1) /

Col

(2))

* (1

+ C

ol (4

))3/

Exp

ecte

d D

ivid

end

Yie

ld (C

ol (3

)) +

I/B

/E/S

Gro

wth

For

ecas

t (C

ol (4

))

Sou

rce:

Sta

ndar

d &

Poo

r's R

esea

rch

Insi

ght,

I/B/E

/S

DC

F C

OST

S O

F EQ

UIT

Y FO

RSA

MPL

E O

F U

.S. E

LEC

TRIC

UTI

LITI

ES(B

ASE

D O

N A

NA

LYST

S' E

AR

NIN

GS

GR

OW

TH F

OR

ECA

STS)


appendix a emily medine resume - nova scotia power · resume of emily s. medine educational...

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