rate request filing

7/27/2019 Rate Request filing

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ECE 592: Business of

Electric UtilitiesTeam Project-Fall 2012

Sarah Hambridge

Sruthi Varma Patchamatla

Bharadwaj Vasudevan

Dinesh Baradi

DOMINION ELECTRIC UTILITY


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INTRODUCTION:Dominion serves electric customers in Virginia and North Carolina and gas customers in Ohioand West Virginia. It is one of the nations largest producers and transporters of energy. Itsportfolio consists of approximately 27,400 megawatts of generation and 6,300 miles of electrictransmission lines[1].

SUMMARY OF CUSTOMER COUNTS:The electric delivery customers for Dominion Virginia power are shown below for 2011 and2012. Dominion Virginia organizes its customer classes into four categories for retail and onecategory for wholesale.

ELECTRIC DELIVERY CUSTOMERS in the twelve month period ENDING DECEMBER 31, 2011-12 [2]

Customer Class 2012 2011

Residential 2,210,587 2,180,233

Commercial 239,193 236,208

Industrial 548 560

Governmental 29,537 29,371

Total Retail 2,479,865 2,435,178

Wholesale - sales for resale 3 3

Total 2,479,868 2,435,181

SUMMARY OF TOTAL ANNUAL ENERGY DELIVERED:The annual energy delivered (in GWh) to customers of Dominion Virginia power are shownbelow for the year in 2011 and 2012. The energy delivered is organized by customer class.

Electricity delivered (GWH) in the twelve month period ENDING DECEMBER 31, 2011-12 [2]

Customer Class 2012 2011

Residential 31,056 30,769

Commercial 34,000 28,949

Industrial 8,628 7,960Governmental 11,559 10,823

Total Retail 85,243 78,500

Wholesale - sales for resale 1,946 3,814

Total 87,189 82,314


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SUMMARY OF PEAK DEMAND FORECASTING:The Dominion Utility services are primarily divided between two zones, namely DOM LSE-Dominion Load Serving Entity which represents the Companys service territories in theCommonwealth of Virginia and DOM ZONE which includes other LSEs as a part of PJMinterconnection.

The actual peak load demands from 2007-2010 have been used to forecast the 2011 peakdemand. The same is shown below [2].

LOAD (MW) 2007 2008 2009 2010 2011

1. Summer

a. Adjusted Summer Peak 17,891 16,908 16,067 16,952 17,530

b. Other Commitments 150 150 150 389 431

c. Total System Summer Peak 17,741 16,758 15,917 16,563 17,099

2. Winter

a. Adjusted Winter Peak 15,765 14,787 15,577 14,376 14,577b. Other Commitments 127 128 132 124 128

c. Total System Winter Peak 15,638 14,659 15,445 14,253 14,449

GENERATION FLEET 2011:The Companys existing generating resources are located at multiple sites distributedthroughout its service territory as shown [2]


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Generation Resource Type Net SummerCapacity (MW)

Percentage (%)

Coal 5,442 27.20%

Nuclear 3,270 16.34%

Natural Gas - Boiler 316 1.58%

Natural Gas - Combined Cycle 1,606 8.03%

Natural Gas - Turbine 3,353 16.76%

Pumped Storage - Hydro 1,802 9.01%

Light Fuel Oil - Turbine 352 1.76%

Heavy Fuel Oil - Boiler 1,604 8.02%

Renewable - Hydro 318 1.59%

Renewable - Biomass 169 0.84%

Purchases 1,779 8.89%

Total - Owned 18,232 91.11%

Total 20,011 100%

REF:Doc2[Dominion VA&NCFleet]


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The Companys load forecast indicates that the region is expected to have future annualincreases in energy demand of approximately 2.02% and peak load of approximately 2.01%[2]. At present, the Company has three options for meeting future increases in energy and peakdemand including supply-side resources, demand-side resources, and market purchases. TheCompany also remains committed to meeting its renewable energy and energy efficiency goalsin a cost-effective manner.

The Company uses PJMs reserve margin guidelines in conjunction with its own loadforecast. The decrease in reserve margin from the previous study is the result of a slightincrease in the PJM/World load diversity.

Year Net Summer Peak Effective Reserve Margin ReserveRequirement

Total ResourceRequirement

MW % MW MW

2011 17,530 16.10% 2,822 20,3522012 18,194 16.70% 3,040 21,234

2013 19,312 13.00% 2,519 21,842

New Generation:The Companys aims to identify the mix of resources necessary to meet future energy andcapacity needs in an efficient and reliable manner at the lowest reasonable cost. TheCompanys load forecast indicates that the region is expected to have future annual increasesin energy demand of approximately 2.02% and peak load of approximately 2.01%. At present,

the Company has three options for meeting future increases in energy and peak demandincluding supply-side resources, demand-side resources, and market purchases. The Companyalso remains committed to meeting its renewable energy and energy efficiency goals in a cost-effective manner.

2012 2011 2010

Customer Class Accounts GWH Accounts GWH Accounts GWH

Residential 2210587 31056 2180233 30769 2156473 32539

Commercial 239193 34000 236208 28949 233608 29224

Industrial 548 8628 560 7960 572 8512Governmental 29537 11559 29371 10,823 29184 10951

Total retail 2479865 85243 2435178 78500 2419837 81226

Wholesale-Sales of resale 3 1946 3 3814 3 3311

Total 2479868 87189 2435181 82314 2419837 84537

Table reference(Doc2) Pg.119


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Estimated Customer Growth & GWH Consumption:


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Taking into account the increase in the Industrial load in GWH, it is decided that a Nuclear plantbe established at the Virginia City Hybrid Energy Centre(VHEC) which has an average life of 60years and an estimated capacity of 585MW. Since it will operate to the base load the capacityfactor is assumed to be 55% and the time of operation is calculated using the formula

Time of Operation(Days)=Capacity Factor*(8760), therefore the fixed O&M and variable O&Mcost are determined based in the document 8 cited in reference. Therefore it is estimated thatthis establishment will serve our industrial load and offset the deficit energy usage by 60%.The remaining 40% is compensated by setting up a Gas Turbine plant at Brunswick countyhaving a demand capacity of 350MW. This is set up with an intention to serve our increase insummer peak as gas fired plant take less time to attain steady state operation. The expensesrelated to it are estimated in the same way mentioned for Nuclear Plant. It is assumed that theGas Turbine plant will last for 25 years and the capital cost related to it is depreciated linearly.As per our estimation this plant will compensate for 30% increase in the GWH consumption ofour total energy demand. This will primarily supply our ever-growing commercial andresidential classes.

The company has adapted to the changing regulatory environment and now with an intentionto serve the REPS it has decided to establish a Biomass Plant at Gloucester County. With acapacity of 100MW it is expected to operate at 50% capacity factor serving 9.4% of ourincreased energy demand. The deficit demand of 0.6-1.00% is to be bought from the PJMsenergy market. This is a drastic reduction compared to the figures from 2010 where 3% of thedeficit energy demand was bought. The company believes that this forward step will eventuallylead to the self sustainable future and secure its ability to serve the customers.

Baseload/Peak:The graph below depicts screening curves for a variety of plants[7]. According to each plants

fixed (y-intercept) and variable costs (slope), the best economical use for that plant can bedetermined.


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In order to determine which plants should compromise the baseload and the peak power, thecosts required at each hour for each plant should be considered. The Combined Cycle andCombustion Cycle are the cheapest plants to run at ~2000 h/yr. These plants will provide thepeak demand, since they run economically for only a portion of the total year. The Oil/GasSteam may contribute to the peak load if the Combined Cycle and Combustion Cycle plants arerunning at full capacity. As seen on the graph, the Oil/Gas Steam is the most economicalrunning at below ~3000 h/yr. From ~2000 h/yr to ~6000 h/yr, Combined Cycle is the mosteconomical and will provide power to the intermediate load. The baseload power will beprovided by Hydroelectric and Pulverized Coal. Nuclear and Biomass are also good options forbaseload power that are used by Dominion. At above ~6000 h/yr, Hydroelectric and PulverizedCoal become the cheapest plants to run. Since they are the most economical to run for thegreatest number of hours per year, they become the baseload power, which is typically onlyswitched off for maintenance. This information is summarized below.

Baseload (~6000 to 8760 h/yr) Hydroelectric, Pulverized Coal, Nuclear,Biomass

Intermediate Load(~2000 to 6000 h/yr)

Combined Cycle

Peak Load (~0 to 2000 h/yr) Combustion Cycle

Resource Resource Type Dispatchable PrimaryFuel

BusbarResource

Biomass Baseload Yes Renewable Yes

CC 2nd Intermediate Yes Natural Gas Yes

CC 3rd Intermediate Yes Natural Gas Yes

CT Peak Yes Natural Gas Yes

Fuel Cell Intermediate Yes Natural Gas No

Geothermal Baseload Yes Renewable No

IGCC Baseload Yes Coal Yes

IGCC CCS Baseload Yes Coal Yes

Municipal Solid Waste Baseload Yes Renewable No

Nuclear Baseload Yes Uranium Yes

PC Baseload Yes Coal Yes

PC CCS Baseload Yes Coal Yes

Hydro Power Intermittent No Renewable Yes

Solar PV Intermittent No Renewable Yes

Solar Thermal Intermittent No Renewable No

Wave Power Intermittent No Renewable No

Wind-Off-shore Intermittent No Renewable Yes

Wind-On-Shore Intermittent No Renewable Yes


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REF:Dominion VI&NC FLEET IRP 2010

The table above summarizes the resources that the company reviewed as part of the evaluationfor plant establishment study. It is evident that the Uranium was the best possible choice toserve the Industrial Customers when long-term benefits were considered.

TRANSMISSION & DISTRIBUTION:According to the 2011 Dominion IR Reference Book [4], Dominion had 6,300 miles of electrictransmission lines and 56,900 miles of electric distribution lines. In 2011, infrastructureinvestment was $0.5 billion in electric transmission and $0.2 billion in electric distribution,[totalling $0.7 billion. According to the Democratic Policy Committee [5], the cost per mile oftransmission falls between $1.5 to 2 million per mile. Distribution lines can cost from $10,000to $250,000 per mile [6]. Using this information, the miles and cost of infrastructure added in2011 and in previous years are calculated below.

2011 Infrastructure Previous InfrastructureTransmissionInfrastructure

250 milesTotal Cost = $500 million(at $2 million per mile)

6,300 - 250 = 6,050 milesTotal Cost = $12,100 million(at $2 million per mile)

DistributionInfrastructure

2000 milesTotal Cost = $200 million(at $100,000 per mile)

56,900 - 2000 = 54,900 milesTotal Cost = $5,490 million(at $100,000 per mile)

We have assumed that for every 25 feeders we have a Distribution Substation. the cost statedabove includes all these substations and the equipments associated with it. In the transmission

sector, the system primarily includes 500 kV lines[19] and a number of 230 kV lines are beingadded in the recent past. We assume for every 150 mile of transmission line a interconnection

substation is placed. Again the cost presented above has already included these substations.

BALANCE SHEET EXPLANATIONS:

Asset Expenditure: [23]Our total asset value of the plants including the transmission and distribution infrastructurecosts we end up with a total asset worth of $45,614 Million. As of 2011 the company had a debtto equity ratio of 1.519 and the total shareholders equity including the retained earnings

added up to $11,446 Million. The total long term debt was $17,394 Million.

Equity and Long Term Debt: (in million)

Debt $17394

Shareholder's Equity $11446


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Shares and Dividends:The total number of shares as of 2011 are 430 Million and the corresponding stock quote forthe same is $26.68 [18].

Dividend Information: [24]

Ex-Dividend Date Record Date Payment Date Amount Per Share

March 2, 2011 March 4, 2011 March 20, 2011 .4925

May 25, 2011 May 27, 2011 June 20, 2011 .4925

Aug. 24, 2011 Aug. 26, 2011 Sept 20, 2011 .4925

Nov. 30, 2011 Dec. 2, 2011 Dec. 20, 2011 .4925

The dividend yield as per the values mentioned above will be,

Annual Dividend yield = (Dividends per share) / (Stock price) x 100% = 7.38%

Maturity Index: [20]This graphical representation gives the bonds maturity index i.e., the term of a bond and its

yield depending on the term.


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INCOME SHEET EXPLANATIONS:Other income expense: Given below are the schedule for plants under construction and the

transmission projects added in the year 2010/2011.

PLANNED TRANSMISSION ADDITIONS [2]Line Terminal Line Voltage

(kV)Target Date

Pleasant View Hamilton 230 Oct 2010

Chickahominy Lanexa Sub 230 Nov 2010

Chickahominy Old Church 230 Mar 2011

Garrisonville Underground Cable 230 Dec 2011

Uprate Pleasant View Dickerson 230 May 2011

Brambleton Pleasant View (#201) Reconductor 230 May 2011

Carson Suffolk 500 kV Line, Suffolk Transformer andSuffolk Thrasher 230 kV Line

500/230 May 2011

Meadowbrook Loudoun Line 500 June 2011

Ironbridge Southwest 230 May 2011

PLANNED GENERATION UNDER CONSTRUCTION [2]COD UNIT LOCATION FUEL Unit

TypeCAPACITY(MW)Summer Winter

2011 Bear Garden BuckinghamCounty, VA

NaturalGas

I 590 613

2012 Virginia City HybridEnergy Center

Wise County, VA Uranimum B 585 635


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The expenses for all these activities are reflected in our AFUDC expenses which is accounted asthe other income expense in our income statement.

Income Tax Expense: For the revenue generated for the year 2010-11 we have assumed a sumof $745 million as our income tax expense [1].

Debt Amortization: includes the amortization of intangible and acquired assets. As of 30th September 2011, bonds maturing in 2011 add up to $462.5 million [10]. We haveassumed an equal amount to be paid in as amortization for loan for the year 2011. The same isreflected in our income statement.

Property and other taxes: $554 million is the amount paid by Dominion in the year 2011 asproperty and and other indirect taxes other than income taxes for the utility sector. It includesfees for licenses and other business regulations to government agencies.

Purchased gas: $1764 million was purchased in the year 2011 for resale by Dominion [1].

FUEL COSTS:The total fuel cost for year comes to $1103 million. The capacity (MW), capacity factor [2] andtime of operation for each plant were used to find the plant output in MWh. The fuel costs forthe coal, oil/gas, CC, CT, and hydroelectric plants were calculated using the heat rate and fuelcost data below.Typical cost parameters for power plants and fuel types[7].

Technology Fuel Heat Rate (Btu/kWh) Fuel Cost ($/million Btu)

Pulverized coal steam coal 9700 1.5

Oil/gas steam oil/gas 9,500 4.6Combined cycle natural gas 7700 4.5

Combustion turbine natural gas 11400 4.5

Hydroelectric water 0 0

The cost for uranium (nuclear) fuel was calculated at 0.77 cents per kWh [11]. Biomass fuelcosts were calculated at 9 cents per kWh [12].

SMART METERS: [26]A small percentage of our total cost includes smart meters. Dominion has been demonstrating

the benefits of smart metering technology since 2009. To date, we have installed more than100,000 smart meters in portions of Midlothian, Charlottesville, Northern Virginia,Williamsburg, downtown Richmond, and in the Blue Ridge area.

The smart meter demonstrations help evaluate technologies that can improve infrastructurefor delivery and reliability of electric service, and provide safe, cost effective service to ourcustomers and also to enable a two way communication between the meter and Dominion'selectric distribution system.


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VEHICLE MANAGEMENT: [27]Dominion ensures that its electrical infrastructure can support the expected demand fromelectric vehicles, which have significantly lower carbon intensity than conventionalvehicles.

It has added the Chevrolet Volt and Nissan Leaf to its vehicle fleet in an effort to educate aboutas well as study the impact on our system. The electric vehicles will help to assess how utilitiescan manage the new technology. The main purpose of these electric vehicles would bedistribution circuit maintenance and meter reading.

Fewer meter readers means fewer meter reading vehicles, less mileage, and lower insurancecosts.Hence ,Vehicle Management = auto insurance savings + (reduced number of vehicles * annualmiles driven * operating costs per mile)

LOAD DURATION CURVE

The load duration curve for Dominion is shown below [2].


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Baseload generation consists of coal, nuclear, biomass, and hydro, which have the highest timeof operation of the plants. Below is a breakdown of baseload capacity.

Plant Type Total Capacity (MW)

Coal 4296

Nuclear 3539

Hydro 3319

Biomass 83

Total 11237

The intermediate load consists of Combined Cycle plants. The total capacity for Combined Cycleis 2708 MW. The peak load consists of Combustion Turbine plants, with the lowest time ofoperation of the plants. The total capacity for Combustion Turbine is 1373 MW. The gas and oilsteam plants support the intermediate load and peak load when needed with a total capacity of2403 MW. Below is a table of the capacities for each load type.

Load Type Total Capacity (MW)

Baseload 11237

Intermediate Load 2708

Peak Load 1373

Gas/Oil Steam 2403

Reserve (1 Gas, 1 Coal) 2631

Total 20352

The total capacity of 20352 MW exceeds the maximum MW of the load duration curve by 2631MW which is equivalent to the reserve margin.

Present Value:The present value has been calculated using the formula below, Co = Cn / (1+(r/t))^tnwhere, r = inflation rate = 1.5%

t = 1n = period from the commercial operation of the plant to 2011

Depreciation: [22]The annual depreciation is given as,

Annual depreciation = ( Actual cost - Residual value ) / Useful lifeAccumulated depreciation = (period * Annual depreciation)


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Accumulated Reserves for Depreciation can be given as: (in million)

Generation $12,167.74

Transmission $4,242.29Distribution $4,248.53

Total Depreciation Reserve $20,658.56

Book Value: [22]Book Value = Initial cost - Accumulated depreciation

The Book values of the plants in service are: (in million)

Generation $32,306.87

Transmission $8,357.71

Distribution $1,441.47

Total Plants in service $42,106.05

WACC:Capital from Bonds (Cb): $17394 millionCapital from Stocks (Cs): $11446 millionRequired Return from bonds (rb): 2%Required Return from stock (rs): 9%

WACC = (rb*Cb+rs*Cs) / (Cb+Cs)

WACC= 4.7%

Rate Schedule:Our Electric Revenue for the year 2011 was $14379 million. keeping that as a basis, the newincome statement for the test period 2012 has been built. This includes the O&M cost for the allthe new plants added and also includes the portion of money allocated for the smart meterinitiative and also the addition of vehicle management. Based on this our test year revenue canup to $13,489 million[20].

Rate Base:Our rate base calculation is primarily based on the increase in operating revenue required dueto the addition of new plants. It includes the Allowance on working capital and the Net utilityplant available as of 2012 test period. the following were included as a part of the utility plantcost:

Utility plants in service Construction work in Progress Plants held for future use


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Negation of Depreciation reserves Negation of Operating ReservesOur Total Average Rate Base came up to $2505.51million[22].

Rate Design:Based on our operating revenue for 2012 test period which came up to $9571.51 [22] for aReturn on revenue of10.55%[22]., we have designed our rate design on the following manner:

Cost functionalization: [22 sheet Functionalization]We have functionalized all our expenses into the following three broad categories:

Generation costs Transmission costs Distribution costs.All our O&M costs and Tax expenses and annual depreciation expenses have been

functionalized within these 3 categories.

Cost Classification: [22 sheet Costclassification]After functionalizing the cost we have classified the costs in each of the functions based on theimpact that created the cost. Our primary classifiers are shown below within each functions

Generation costso Demand Related Costso Energy Related Costs Transmission costso Demand Related Costs Distribution costso Demand Related Costso Customer Related CostsWe have distributed our costs in the generation side on 60-40 basis between the 2 classifiers. for the transmission side there is only demand related costs and for the distribution we havedivided it equally(50-50).

Cost Allocation: [22 sheet Cost Allocation]Based on our classifiers we have decide on 6 allocation factors to allocated costs to teach of ourcustomer classes. All these factors have been assigned weightage primarily based on theelectricity usage pattern of all the customers. Our daily load curve is shown below:

Our allocation factors are listed below as a part of the classifiers:

Generation costso Demand Related Costs Average Excess Demand Factor(AED)This factor is based on the excess demand made on the average demand for the class.


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o Energy Related Costs MWh Usage Factor(MWh)This factor is based on the energy usage pattern of the class.

Transmission costso

Demand Related Costs 12 Coincidental Peak Factor(12CP)This factor considers the 12 month average coincidental peak for a class with the overallsystem peak.

Distribution costso Demand Related Costs Non Coincident Peak (NCP)This factor provides incentive for customers whose demands peaks never coincides with thesystem peak.

Customers FactorThis factor considers the customer count and allocated based on the general trend in thecustomer counts over the coming years as predicted by the inegrated resource plan.

o Customer Related Costs Weighted CostsThis includes weighted costs on each customer class based on their total contribution to therevenue.

Here is the table showing all our cost allocation factors:

Class GenerationFactor

TransmissionFactor

DistributionFactor

CustomerCounts Factor

MWhFactor

Residential 0.3 0.12 0.9 0.90 0.37

Commercial 0.5 0.5 0.1 0.09 0.40

Industrial 0 0.08 0 0.001 0.10

Governmental 0.2 0.3 0 0.009 0.13


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Daily load Curve:

Finally based on the above factors and our revenue required in place we have our ratestructure as shown below:

Residential Commercial Industrial Government

Customer Count 2210587 239193 548 29537

Basic charge 8 27.17 35 10

Energy(GWh) 31056 34000 8628 11559

cents/kWh* 9.92 12.11 4.18 14.40


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The basic charge is the minimum amount our customers are to pay based on the customer classthey belong to. And based on their usage of electricity we designed a flat rate structure. On comparing with our previous year we have found that the rates have impacted each class inthe following way:

Residential Commercial Industrial Government Average

2011 [25] 11.40 8.29 6.91 12.00 9.46

2012 9.92 12.11 4.18 14.40 10.18

% increase or decrease -12.97% 46.10% -39.53% 19.99% 7.66%

The average cost of electricity has changed in the following manner:

Year 2012 2011Average Cost of Electricity 10.18 9.46


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Balance Sheet Dec 2011

Assets AmountCapitalization AndLiabilities

Electric Utility Plant Capitalization

Net Utility Plant in Service(Book Value)

32746Common Stock HoldersEquity

Electric Plant Held For FutureUse

0 Long Term Debt

Construction Work in Progress 175 Total

Nuclear Fuel, Net ofAmortization

240

Total 33161

Current Assets Current Liabilities

Cash and Cash Equivalents 102 Accounts Payable

Accounts Receivable 1198 Accrued Expenses

Inventory 1156 Dividends Declared

Prepayments 262 Short Term Obligations

Other Current Assets 1683 Other Current Liabilities

Total 4401 Total

Deferred Debits and OtherAssets

Deferred Credits andOther Liabilities

Plant, Property, Equipment 2100Accumulated DeferredIncome Tax Liabilities

Long Term Investments 3804 Regulatory Liabilites

Other Long Term Assets andDeferred Debits

2148Other Liabilites andDeferred Credits

Total 8052 Total

Total Assets 45614Total Capitalization andLiabilities

Balance Sheet_Dec_2011


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Income Statement (Proxy)Dominion Power

As of 31st December 2012

Financial Statements in million U.S. Dollars

Operating RevenueElectric Revenue

Operating ExpensesElectric fuel and other energy-related purchases

Purchased electric capacity

Purchased gas

Operations and maintenance

Depreciation & Amortization

Other unusual operating expenses

Property & Other taxes

Total Expenses

Income from Operations

Non-Operating ExpensesOther Income(expense)

Interest expense(non-operating)

Total Other Income

Income before tax

Income Tax Expense

Net Income


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Income StatementDominion Power

As of 31st December 2011

Financial Statements in million U.S. Dollars

Operating RevenueElectric Revenue

Operating ExpensesElectric fuel and other energy-related purchases

Purchased electric capacity

Purchased gas

Operations and maintenance

Depreciation

Amortization

Other unusual operating expenses

Property & Other taxes

Total Expenses

Income from Operations

Non-Operating ExpensesOther Income(expense)

Interest expense(non-operating)

Total Other Income

Income before tax

Income Tax Expense

Net Income


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Generation Transmission S/S Prim

Particulars Total Demand Energy Demand Demand Dem

Revenue Req.

Cost Excluding Fuel 8,976.91 4,837.42 2,343.49 1,075.24 712.16

Fuel Costs 541.00 541.00

Total 9,517.91 4,837.42 2,884.49 1,075.24 712.16

Rate Base 2,505.51 2,004.41 125.28 125.28

Allocation Factors AED mWh 12 CP NCP CustResidential 0.30 0.37 0.12 0.90

Commercial 0.50 0.40 0.50 0.10

Industrial 0.00 0.10 0.08 0.00

Government 0.20 0.13 0.30 0.00

Total 1.00 1.00 1.00 1.00

Allocated Rev. Req.

Residential 3,293.46 1,451.22 1,064.51 129.03 640.95

Commercial 4,195.85 2,418.71 1,167.53 537.62 71.22

Industrial 360.74 0.00 274.71 86.02 0.00

Government 1,667.86 967.48 377.73 322.57 0.00

Total 9,517.91 4,837.42 2,884.49 1,075.24 712.16

Allocated Rate BaseResidential 954.60 601.32 0.00 15.03 112.75

Commercial 1,099.92 1,002.21 0.00 62.64 12.53

Industrial 10.27 0.00 0.00 10.02 0.00

Government 440.72 400.88 0.00 37.58 0.00

Total 2,505.51 2,004.41 0.00 125.28 125.28

operating income from Electricity Generation - Cost Allocation


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Generation Transmission Distribution

Demand related Energy Related Demand related Demand related Customer Rela

Revenue Requirements

O&M (million $)

Generation 3,250.80 2,167.20

Transmission 17.50

Distribution S/S,Lines, Tr 7.00

Meters & Services

O&M Subtotal 3,250.80 2,167.20 17.50 7.00

Fuel 541.00

Net Operating Income &Taxes & Annual depreciation 1,586.62 176.29 1,057.74 705.16

Total 4,837.42 2,884.49 1,075.24 712.16

operating income from Electricity Generation - Cost Classification


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Total Generation Transmission Distribution

O&M Expense

Generation 5,418.00 5,418.00

Transmission 17.50 17.50

Distribution 14.00

Total O&M 5,449.50 5,418.00 17.50

Depreciation ExpenseIntangible 209.40

Generation 1,318.17 1,318.17

Transmission 340.20 340.20

Distribution 373.10

Total Depreciation Expense 2,240.87 1,318.17 340.20

Taxes

Taxes other than Income 554.00 277.00 166.20

Income Tax 1,117.50 558.75 335.25

Returns

Debt Related 2,087.00 1,565.25 313.05 Equity Related 451.00 338.25 67.65

Total Returns 2,538.00 1,903.50 380.70

operating income from Electricity Generation - Functionalization


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Description Total company per books

Allowances for Working Capital

Materials & supplies 807.00[1]

Cash Working capital(Lead Lag) -373.00

Deferred Fuel Net 541.00

Total Allowances for WorkingCapital 975.00

Net Utility Plant

Utility Plant in Service 0.00

CWIP 13.25

Plants held for Future Use 195.60[2]

Less: Depreciation Reserves

Less: Operating Reserves 4,470.00

Total Net Utility Plant -4,261.16

Rate Base DeductionsLess: Accumulated Deferred

Income Tax 3,024.00

Total Rate Base Deductions 3,024.00

Total Rate Base -6,310.16

operating income from Electricity Generation - Rate Base


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Total Company (Million $)Cost of Service After Proposed

Increase Proposed Change

Electric Operating Revenue $9,517.91 -$930.09

Operating Revenue Deductions

Operating & Maintanance $3,581.10 $98.10

Depreciation & Ammortization $1,354.31 $285.31

Income Taxes $1,117.50

Other taxes $554.00

Gain/loss on disposition of property $100.00

Total Operating Revenue Deductions $6,706.91 $383.41

Total Operating Income $2,811.00

Plus: AFUDC $13.25

Less: Other Interest expense $2,550.00

Interest Expense on Customer Deposits $0.00

Charitable Donations $10.00

Adjusted Operating Income $264.25 -$1,313.50

Total Average Rate Base $2,505.51

% Rate of Return Earned on Avg. Rate Base 10.55%

Total stockholders Equity 2,936.11

Return on equity 9.00%

operating income from Electricity Generation - ROR statement


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Plant/Unit NameUnit/PlantLocation

PrimaryFuel

CapcityFactor(%)

Time of Operation(Capacity

Factor*8760)Hour

Plant/UnitCapacity

(MW)

Plant Output(Time ofOperation*Capacity)MWH

Pla

Fixed O&M Cost $(2010)

Virginia City HybridEnergy Center Surry, VA Uraniu 55 4,818 585 2,818,530 51,918,750

BrunswickCounty (proposed)

BrunswickCo., VA Gas 45 3,942 350 1,379,700 5,036,500

Gloucester Biomass

Plant Biomas 50 4,380 100 438,000 33,879,000 1,035 4,636,230 90,834,250


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Salem Harbor * 1951 Salem, MA Oil 0.00 Brayton Point 1963 Somerset, MA Other 7.6 4 4.37 575Pittsylvania 1994 Hurt, VA Other/Biomass 83 654 598.11 7,206North Anna 1978 Mineral, VA Uranium 1,863 1300 1,103.61 592Surry 1972 Surry, VA Uranium 1,676 1160 927.83 553Millstone 1975 Waterford, CT Uranium 2097 11187 6,545.40 3,121Kewaunee* 1974 Carlton, WI Uranium 556 0.00 0Bath County 1985 Warm Springs, VA Water 3003 3753 2,228.78 742Gaston 1963 Roanoke Rapids, NC Water 220 275 153.87 699Roanoke Rapids 1955 Roanoke Rapids, NC Water

95 118 66.02 695Fowler Ridge Wind Farm 2007 Benton Co., IN Wind 301.3 610 341.31 1,132NedPower Mount Storm 2009 Mt. Storm, WV Wind 264 530 263.25 997

29,928.06

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Reference Number Title of Document Website

1 About Dominion https://www.dom.com/about/index.jsp

2 Dominion VI&NC Fleethttps://www.dom.com/about/conservation/pdf/2010_integrate

3 Dominion Resources Inc

http://quicktake.morningstar.com/StockNet/bonds.aspx?Symbol=D&Country=USA

4Dominion IR Reference Book,Sept 2011

http://investors.dom.com/phoenix.zhtml?c=110481&p=irol-irhome

5 Democratic Policy Committeehttp://dpc.senate.gov/dpcdoc.cfm?doc_name=fs-111-1-34

6

Virginia Report: Placement ofUtility Distribution LinesUnderground

http://www.scc.virginia.gov/comm/reports/report_hjr153.pdf

7

Renewable and EfficientElectric Power Systems By:Gilbert Masters Textbook

8Costs related to plant by type offuel http://www.eia.gov/oiaf/beck_plantcosts/

9 Energy_Purchased_dominion

https://www.dom.com/dominion-north-carolina-power/customer-service/rates-and-tariffs/pdf-rate-adjustment/testimony-

2012/Morgan-Direct-Testimony.pdf

103Q11 Earnings Release KitFinal 2

http://investors.dom.com/phoenix.zhtml?c=110481&p=irol-finModelEarn

11 Nuclear Energy Costs http://www.world-nuclear.org/info/inf02.html

12 Public Renewables Partnershiphttp://www.repartners.org/biomass/biocosts.htm

134Q11 Earnings Release KitFinal 2

http://investors.dom.com/phoenix.zhtml?c=110481&p=irol-finModelEarn

14 EIA www.eia.gov

15Business Essentials For UtilityEngineers By: Richard Brown Textbook

16 PJM Rate Request Moodle NCSU

17 Investopediahttp://www.investopedia.com/#axzz2CgcSoFFM

18 Morningstar Financialshttp://quote.morningstar.com/stock/s.aspx?t=DOM

19Visualizing the U.S. ElectricGrid: NPR

http://www.npr.org/templates/story/story.php?storyId=110997398

20Dominion IR Reference Book,March 2012

http://investors.dom.com/phoenix.zhtml?c=110481&p=irol-irhome

21 Income Statement 2012

https://docs.google.com/a/ncsu.edu/spreadsheet/ccc?key=0AvXEDpcM6kFbdDdHMm9Bel9qN3V

22operating income fromElectricity Generation

https://docs.google.com/a/ncsu.edu/spreadsheet/ccc?key=0AvXEDpcM6kFbdExPX2FjRC03X0U4

23 Balance sheet

https://docs.google.com/a/ncsu.edu/spreadsheet/ccc?key=0AqWIUhCkLuNydHZFOFh4LWRFVnc

24 Dividend infohttps://www.dom.com/investors/stock-information/dividend-information.jsp

25 cost of electricity

http://www.eia.gov/electricity/monthly/epm_table_grapher.cfm?t=epmt_5_04_a

26 smart meters

https://www.dom.com/about/conservation/about-smartmeters.jsp

27 vehicle management

https://www.dom.

com/about/environment/hybrid-vehicles.jsp

REFERENCE

rate request filing

Documents