ThOll1a..~ r. \'\'ohlfarth 

'i,:njO( Vj~·,,-, P".:_,itk-m 

R<:pd,HII!;' :\I"i:l1rs 

Dominion Itnuun:t" SCfyk('). INC 

121) 'rr~'dc~,!r Str<_''':L !{idmlUJIJ, VA .U21 '} 

.\bilin!! ;\ddrL'~': P.O, Box 2(,').'2 

[(i,,:hl1l:nH!. VA 2321 I) 

dom.com 

August 29, 2014 

Joel H. Peck, Clerk 

Virginia State Corporation Commission 

c/o Document Control Ccnter 

1300 E. Main Street 

Richmond, VA 23219 

Re: Case No. PUE-2014-00087 

Dear Mr. Peck: 

Dominion Virginia Power ("the Company" or "Dominion") is pleased to submit its 2014 Integrated 

Resource Plan ("the 2014 Plan" or "the Plan") for the period 2015-2029. The Plan is submitted as an 

update in accordance with the guidelines issued by this Commission on December 23, 2008. 

Simultaneously, it is being filed in North Carolina, where the Company does business as Dominion 

North Carolina Power, in accordance with the requirements of § 62-2 of the North Carolina General 

Statutes and Rule R8-60 of the Rules and Regulations of the NOith Carolina Utilities Commission 

("NCUC"). 

Consistent with the Company's previous Integrated Resource Plan ("IRP") filings, the 2014 Plan 

continues Dominion's longstanding commitment to maintaining a balanced blend of cost-effective 

supply-side and demand-side resources to meet the growing energy needs of its customers. Such 

diversity has been a key factor in our ability to offer highly reliable service at reasonable rates. The 

commitment is also consistent with V A § 56-598.3, which directs utilities to develop IRPs that "reflect a 

diversity of electric generation supply and cost-effective demand reduction contracts so as to reduce the 

risks associated with an over-reliance on any particular fuel or type of generation demand and supply 

reSO\lrces .... " 

To develop the 2014 Plan, the Company evaluated a wide range of options for meeting customer 

demand in a highly uncertain energy policy and regulatory environment, most recently influenced by the 

June 2014 issuance of the U.S. Environmental Protection Agency's ("EPA") draft Rule I 11 (d), or 

"Clean Power Plan," that would require a significant reduction in carbon emissions from existing 
sOurces of power generation and impose binding carbon intensity targets on each state's electric 

generation fleet. The draft rule calls for sharp reductions in carbon intensity (the average amount of 

carbon dioxide ("C02") released per megawatt-hour of electric generation) in both Virginia and North 

Carolina, with Virginia's final goal (effective in 2030) 38 percent below the EPA-calculated carbon 

intensity level for 2012, and North Carolina's final goal 40 percent below the 2012 level. In terms of 

absolute carbon intensity targets, Virginia and North Carolina have the two strictest targets in the MidAtlantic region and among the strictest in the Southeast. The Company has also taken significant steps 

to reduce its emissions in the past decade, making further emissions reductions all the more challenging. 

These include the decision to close or convert seven coal plants, the addition of substantial new 

renewable energy assets, cost-effective demand side management programs, uprates to existing nuclear 

stations, and advanced combined cycle natural gas generation units. 

Rule III (d) is now in draft form and the EPA is expected to issue a final rule in June 2015. States must 

submit implementation plans to thq EPA beginning in 2016, with individual utilities then responsible for 

complying with the state plans. Given the Clean Power Plan's tight timelines for compliance and the 

complexities and potential effect on our customers, the Company believes it is prudent to begin planning 

now for implementation of a final rule that is substantially similar to the proposed rule. Accordingly, 

this IRP filing contains an alternative scenario, not included in prior Plans or in the 2014 Plan itselt~ 

based on a plausible compliance strategy for the draft rule. This alternative scenario is benchmarked on 

the draft Clean Power Plan's Virginia carbon intensity reduction targets averaging 884 pounds pcr 

megawatt-hour of CO2 for the period 2020-2029 and 810 pounds of CO2 per megawatt-hour for each 

year beginning in 2030 as well as North Carolina's slightly higher reduction target. The alternative 

scenario includes additional coal unit retirements and additional low or zero-carbon resources beyond 

those included in the 2014 Plan. 

In developing the 2014 Plan, the Company also recognized and made usc ofthe very attractive features 

of natural gas as a generation resource, given its environmental performance, abundant supply and low 

cost. However, the record cold during early 2014, including the "Polar Vortex" events, demonstrated 

that even with the abundant domestic reserves of natural gas that the United States possesses, natural gas 

infrastructure can become constrained and prices can spike to many times their normal levels during 

periods of extreme demand for the fuel, particularly given the current transmission pipeline constraints 

in the region. The Company therefore recognizes the continuing importance of fuel diversity in 

supplying future energy needs and is also cognizant of the need for additional natural gas infrastructure 

to serve Virginia and North Carolina so that this important resource can be used to the benefit of 

customers while minimizing risks of supply and price disruption. 

With those factors in mind, the 2014 Plan presents two paths forward for resource expansion: a Base 

Plan, designed using least-cost planning methods and consistent with the requirements of Rule R8-60 for 

utility plans to provide "reliable electric utility service at least cost over the planning period;" and a Fuel 

Diversity Plan, which includes a broader array of low or zero-emissions options. While the Fuel 

2 
Diversity Plan cnrrently represents a higher cost option at today's current and projected commodity 

prices, its resource mix provides the impOltant benefits of greater fuel diversity and lower carbon 

intensity. Therefore, the Company will continue reasonable development of the more diverse and lower 

carbon intensive options in the Fuel Diversity Plan and will be ready to implement them as conditions 

warrant. 

This two-path approach, called "the Plan" or the "2014 Plan" in the attached document, is also 

consistent with the strategy presented by the Company in its 2013 Integrated Resource Plan, which was 

required by statute to be filed with this Commission in August 2013 and was simultaneously submitted 

as an update to the NCUC. 

Both the Base Plan and the Fuel Diversity Plan share many common elements. For example: 

• Both plans invest in new natural gas-powered generation, taking advantage of the superior 

environmental aspects of the fuel as well as an abundant domestic supply and favorable pricing. 

• Both plans include completion of the Company's Warren County and Brunswick Power Stations 

in Virginia. The facilities will use advanced, energy efficient combined-cycle technology. 

• Both plans also call for an additional station using combined-cycle technology, to begin 

operation in 2019. 

• Both plans continue to use the PJM capacity and energy markets when it is in the best interests of 

customers to do so. 

• Both plans include cost-effective demand-side management (DSM) programs that will reduce the 

system's peak summer demand by 583 megawatts by 2029, an amount of electricity 

approximately equivalent to the capacity of a medium-sized combined-cycle facility. 

• Both plans take steps to comply with increasingly stringent environmental standards for 

emissions of traditionally regulated pollutants (apart from the new carbon regulation regime) 

through the closure of six coal-fired units at Chesapeake Energy Center and Yorktown Power 

Station, as well as installation of advanced environmental controls on large oil-powered units at 

Yorktown and Possum Point Power Stations. These tluee stations are located in Virginia. 

• Both plans also call for increased use of renewable energy, including an additional 200 

megawatts of solar photovoltaic capacity, to be built by one or more non-utility generators, and 

continuation of the company's Solar Partnership Program, through which Company-owned solar 

arrays are installed on rooftops and other space leased from customers through its Virginia 

service area. 

However, especially over the longer term, the plans diverge. For example, the Base Plan relies almost 

exclusively on natural gas as a fuel source for new supply and calls for another combined-cycle natural 

gas-powered station to come online by 2029, beyond the 2019 unit included in both plans. 

3 
The Fuel Diversity Plan places a greater reliance on generation sources with little or no carbon 

emissions and is less reliant on natural gas. While following the resource expansion scenario in the 

least-cost Base Plan, the Company will continue evaluation and reasonable development efforts for the 

following projects identified in the Fuel Diversity Plan. These include: 

• Continued development of a third nuclear reactor at North Anna Power Station, using reactor 

tecllllology supplied by GE-Hitachi Nuclear Energy Americas LLC. While the Company has 

made no final commitment to building this unit, it recognizes the many operational and 

environmental benefits of nuclear power and continues to actively develop the project. Our 

customers have benefitted from the existing nuclear fleet for many years now, and they will 

continue to benefit from the existing fleet for many years in the future. A final decision on 

constmction ofNOIih Anna Unit 3 will not be made until after the Company receives a 

Combined Operating License or COL from the U.S. Nuclear Regulatory Commission, now 

expected in2016. The Fuel Diversity Plan includes the addition of North Anna Unit3's 1,453 

megawatts of zero-emissions generation by 2028. If constructed, the project would provide a 

dramatic boost to the regional economy. 

• Additional reliance on renewable energy, including 247 megawatts of onshore wind capacity at 

sites in western Virginia and a 12 megawatt offshore wind demonstration project by 2018. 

• An additional 559 megawatts of nameplate solar capacity, including several new Companyowned photovoltaic CPV) installations. Solar PV costs have declined significantly in recent years, 

making utility-scale solar much more cost-effective than distributed solar, and continuing 

technological development, in which the Company is participating, may allow it to become a 

more cost-effective source of intermittent generation in the future. 

In closing, the Company believes the 2014 Plan presents several effective pathways to meeting the necds 

of its customers; thcse needs continue to grow at a rate exceeding almost every other region within 

PJM's service territory in the East and Midwest. At the same time, we believe the 2014 Plan continues 

the Company's consistent commitment to resource diversity and provides it with considerable 

flexibility. 

Sincerely, 

T,?-!.,IIv(6"v.> f· !A.J ("J/4~ 

Thomas P. Wohlfarth 

4 
Dominion® 

Dominion North 

Carolina Power's and 

Dominion Virginia 

Power's Report of Its 

Integrated Resource Plan 

Before the North Carolina 

Utilities Commission and the 

Virginia State Corporation 

Commission 

PUBLIC VERSION 

Docket No. E-100, Sub 141 

Case No. PUE-2014-00087 

Filed: August 29, 2014 
i

LIST OF ACRONYMS .................................................................................................................................viii

INTRODUCTION ...........................................................................................................................................xi

CHAPTER 1 – EXECUTIVE SUMMARY .....................................................................................................1

1.1 Integrated Resource Plan Overview......................................................................................1

1.2 Company Description ..............................................................................................................2

1.3 2014 Integrated Resource Planning Process .........................................................................2

Figure 1.3.1 ‐ Current Company Capacity Position (2015 – 2029)............3

Figure 1.3.2 ‐ Current Company Energy Position (2015 – 2029)...............4

1.4 2014 Plan .....................................................................................................................................4

Figure 1.4.1(a) ‐ 2014 Base Plan.....................................................................6

Figure 1.4.1(b) ‐ 2014 Fuel Diversity Plan....................................................6

Figure 1.4.2 ‐ New Renewable Resources....................................................9

Figure 1.4.3(a) ‐ Plan A: Base Plan – Capacity (2015 ‐ 2029) ...................10

Figure 1.4.3(b) ‐ Plan B: Fuel Diversity Plan – Capacity (2015 – 2029) ..10

Figure 1.4.4(a) ‐ Plan A: Base Plan – Energy (2015 – 2029)......................11

Figure 1.4.4(b) ‐ Plan B: Fuel Diversity Plan – Energy (2015 – 2029) .....11

Figure 1.4.5(a) ‐ Changes between the 2013‐2014 Base Plan...................14

Figure 1.4.5(b) ‐ Changes between the 2013‐2014 Fuel Diversity Plan..15

CHAPTER 2 – LOAD FORECAST...............................................................................................................16

2.1 Forecast Methods ....................................................................................................................16

2.2 History & Forecast by Customer Class & Assumptions ..................................................17

Figure 2.2.1 ‐ DOM Zone Peak Load..........................................................17

Figure 2.2.2 ‐ DOM Zone Annual Energy .................................................18

Figure 2.2.3 ‐ Summary of Energy Sales & Peak Load Forecast.............18

Figure 2.2.4 ‐ DOM Zone Peak Load Comparison...................................19

Figure 2.2.5 ‐ DOM Zone Annual Energy Comparison...........................19

Figure 2.2.6 ‐ Major Assumptions for the Energy Model........................20

2.3 Summer & Winter Peak Demand & Annual Energy........................................................21

2.4 Economic Development Rates ..............................................................................................21

CHAPTER 3 – EXISTING & PROPOSED RESOURCES ........................................................................22

3.1 Supply‐Side Resources ..........................................................................................................22

3.1.1 Existing Generation ........................................................................................22

Figure 3.1.1.1 ‐ Existing Generation Resources.........................................22

Figure 3.1.1.2 ‐ Generation Fleet Demographics.......................................23
ii

Figure 3.1.1.3 ‐ 2014 Capacity Resource Mix by Unit Type.....................24

Figure 3.1.1.4 ‐ 2013 Actual Capacity Mix .................................................25

Figure 3.1.1.5 ‐ 2013 Actual Energy Mix ....................................................25

3.1.2 Existing Renewable Resources .....................................................................25

3.1.3 Changes to Existing Generation...................................................................26

Figure 3.1.3.1 ‐ EPA Regulations as of June 30, 2014................................27

3.1.4 Generation Retirements/Blackstart..............................................................28

3.1.5 Generation under Construction....................................................................29

Figure 3.1.5.1 ‐ Generation under Construction .......................................30

3.1.6 Non‐Utility Generation..................................................................................30

3.1.7 Wholesale & Purchased Power.....................................................................30

3.1.8 Request for Proposal.......................................................................................31

3.2 Demand‐Side Resources........................................................................................................31

Figure 3.2.1 ‐ DSM Tariffs & Programs......................................................32

3.2.1 DSM Program Definitions ............................................................................33

3.2.2 Current DSM Tariffs ......................................................................................34

Figure 3.2.2.1 ‐ Estimated Load Response Data........................................35

3.2.3 Current & Completed DSM Pilots & Demonstrations ............................35

3.2.4 Current Consumer Education Programs .....................................................37

3.2.5 Approved DSM Programs .............................................................................39

3.2.6 Proposed DSM Programs...............................................................................40

3.2.7 Evaluation, Measurement & Verification...................................................41

3.3 Transmission Resources ........................................................................................................41

3.3.1 Existing Transmission Resources.................................................................41

3.3.2 Existing Transmission & Distribution Lines .............................................41

3.3.3 Transmission Projects under Construction................................................41

CHAPTER 4 – PLANNING ASSUMPTIONS ...........................................................................................42

4.1 Planning Assumptions Introduction...................................................................................42

4.2 PJM Capacity Planning Process & Reserve Requirements .............................................42

4.2.1 Short‐Term Capacity Planning Process – RPM .........................................42

4.2.2 Long‐Term Capacity Planning Process – Reserve Requirements ..........42

Figure 4.2.2.1 ‐ Peak Load Forecast & Reserve Requirements................44

4.3 Renewable Energy ..................................................................................................................45

4.3.1 North Carolina REPS Plan.............................................................................45

Figure 4.3.1.1 ‐ North Carolina REPS Requirements ...............................45

Figure 4.3.1.2 ‐ North Carolina Solar Requirements ................................46

Figure 4.3.1.3 ‐ North Carolina Swine Waste Requirements ..................46
iii

Figure 4.3.1.4 ‐ North Carolina Poultry Waste Requirements ................47

4.3.2   Virginia RPS Plan ..........................................................................................47

Figure 4.3.2.1 ‐ Virginia RPS Goals.............................................................47

Figure 4.3.2.2 ‐ Renewable Energy Requirements....................................48

4.4 Commodity Price Assumptions............................................................................................48

4.4.1 Basecase Commodity Forecast......................................................................49

Figure 4.4.1.1 ‐ Fuel Price Forecasts ‐ Natural Gas...................................49

Figure 4.4.1.2 ‐ Fuel Price Forecasts ‐ Coal ................................................50

Figure 4.4.1.3 ‐ Fuel Price Forecasts ‐ Oil...................................................50

Figure 4.4.1.4 ‐ Price Forecasts – SO2 & NOX.............................................51

Figure 4.4.1.5 ‐ Price Forecasts ‐ CO2..........................................................51

Figure 4.4.1.6 ‐ Power Price Forecasts ........................................................52

Figure 4.4.1.7 ‐ PJM RTO Capacity Price Forecasts ..................................52

Figure 4.4.1.8 ‐ 2013 to 2014 Plan Fuel & Power Price Comparison.......53

4.4.2 Alternative Scenario Commodity Prices.....................................................53

Figure 4.4.2.1 ‐ 2014 Plan Scenarios Fuel & Price Comparison...............55

4.5 Development of DSM Program Assumptions...................................................................55

4.6 Transmission Planning..........................................................................................................56

4.6.1 Regional Transmission Planning & System Adequacy...........................56

4.6.2 Substation Security.........................................................................................56

4.6.3 Transmission Interconnections ....................................................................57

Figure 4.6.3.1 ‐ PJM Interconnection Request Process .............................57

4.7 Gas Supply, Adequacy and Reliability.......................................................58

CHAPTER 5 – FUTURE RESOURCES........................................................................................................61

5.1 Future Supply‐Side Resources .............................................................................................61

5.1.1 Dispatchable Resources .................................................................................61

5.1.2 Non‐Dispatchable Resources........................................................................64

Figure 5.1.2.1 ‐ Onshore Wind Resources..................................................65

Figure 5.1.2.2 ‐ Offshore Wind Resources .................................................65

Figure 5.1.2.3 ‐ National PV Resources of the United States...................67

5.1.3 Assessment of Supply‐Side Resource Alternatives..................................67

Figure 5.1.3.1 ‐ Alternative Supply‐Side Resources .................................68

5.2 Levelized Busbar Costs ..........................................................................................................68

Figure 5.2.1 ‐ Dispatchable Levelized Busbar Costs ................................69

Figure 5.2.2 ‐ Non‐Dispatchable Levelized Busbar Costs .......................69

Figure 5.2.3 ‐ Renewable Capacity Summary ...........................................70

Figure 5.2.4 ‐ Resources by Capacity and Annual Energy......................71
iv

5.3 Generation under Development ..........................................................................................71

Figure 5.3.1 ‐ Generation under Development .........................................73

5.4 Emerging and Renewable Energy Technology Development........................................73

Figure 5.4.1 ‐ Virginia Wind Energy Area.................................................75

Figure 5.4.2 ‐ Project Overview...................................................................76

Figure 5.4.3 ‐ AMI Infrastructure in North Carolina ...............................78

5.5 Future DSM Initiatives ..........................................................................................................79

5.5.1 Standard DSM Tests.......................................................................................80

5.5.2 Future DSM Programs....................................................................................80

5.5.3 Future DSM Programs’ Cost‐Effectiveness Results..................................81

Figure 5.5.3.1 ‐ Future DSM Individual Cost‐Effectiveness Results ......81

Figure 5.5.3.2 ‐ Future DSM Portfolio Cost‐Effectiveness Results .........81

5.5.4 Rejected DSM Programs................................................................................81

Figure 5.5.4.1‐ IRP Rejected DSM Programs .............................................82

5.5.5 Rejected DSM Programs’ Cost‐Effectiveness Results..............................83

Figure 5.5.5.1 ‐ Curtailable Service Program.............................................84

5.5.6 New Consumer Education Programs...........................................................84

5.5.7 Assessment of Overall Demand‐Side Options..........................................84

Figure 5.5.7.1 ‐ DSM Energy Reductions ...................................................84

Figure 5.5.7.2 ‐ DSM Demand Reductions ................................................85

5.5.8   Load Duration Curves ...................................................................................85

Figure 5.5.8.1 ‐ Load Duration Curve 2015................................................86

Figure 5.5.8.2 ‐ Load Duration Curve 2019................................................86

Figure 5.5.8.3 ‐ Load Duration Curve 2029................................................87

5.6 Future Transmission Projects ...............................................................................................87

CHAPTER 6 – DEVELOPMENT OF THE INTEGRATED RESOURCE PLAN ..................................88

6.1   IRP Process ...............................................................................................................................88

6.2 Capacity & Energy Needs......................................................................................................89

Figure 6.2.1 ‐ Current Company Capacity Position (2015 – 2029)..........90

Figure 6.2.2 ‐ Actual Reserve Margin.........................................................91

Figure 6.2.3 ‐ Current Company Energy Position (2015 – 2029).............92

6.3 Modeling Processes & Techniques......................................................................................92

Figure 6.3.1 ‐ Supply‐Side Resources Available in Strategist .................93

Figure 6.3.2 ‐ Plan Development Process ..................................................94

6.4   Alternative Plans.....................................................................................................................95

Figure 6.4.1 ‐ Alternative Plans...................................................................98

6.5 Basecase, Scenarios & Sensitivities .....................................................................................99
v

Figure 6.5.1 ‐ Summary of High Load and Low Load Sensitivities.....100

Figure 6.5.2 ‐ Summary of Net Metering Sensitivity .............................101

Figure 6.5.3 ‐ Summary of Electric Vehicle Sensitivity..........................102

6.6   Alternative Plan NPV Comparison....................................................................................102

Figure 6.6.1 ‐ Alternative Plan Comparison............................................103

6.6.1 Portfolio Evaluation Scorecard...................................................................103

Figure 6.6.1.1 – Portfolio Evaluation Scorecard......................................105

Figure 6.6.1.2 – Portfolio Evaluation Scorecard with Scores.................105

6.7 2014 Plan .................................................................................................................................105

Figure 6.7.1 ‐ Mass Hub Power Prices......................................................107

Figure 6.7.2(a) ‐ Plan A: Base Plan............................................................108

Figure 6.7.2(b) ‐ Plan B: Fuel Diversity Plan ...........................................108

Figure 6.7.3(a) ‐ Plan A: Base Plan ‐ Capacity (2015 ‐ 2029)..................110

Figure 6.7.3(b) ‐ Plan B: Fuel Diversity Plan ‐ Capacity (2015 ‐ 2029)..110

Figure 6.7.4(a) ‐ Plan A: Base Plan ‐ Energy (2015 – 2029) ....................111

Figure 6.7.4(b) ‐ Plan B: Fuel Diversity Plan ‐ Energy (2015 – 2029)....111

Figure 6.7.6 ‐ Energy by Source (Base Plan)............................................113

Figure 6.7.7 ‐ Energy by Source (Fuel Diversity Plan)...........................113

6.8 Conclusions............................................................................................................................114

Figure 6.8.1 ‐ Summary of the 2014 Base Plan ........................................114

Figure 6.8.2 ‐ Additional Resources from the Fuel Diversity Plan.......114

CHAPTER 7 – SHORT‐TERM ACTION PLAN......................................................................................115

7.1 Current Actions (2014)..........................................................................................................115

7.2 Future Actions (2015 – 2019)................................................................................................117

Figure 7.2.1 ‐ DSM Projected Savings by 2019 ........................................118

Figure 7.2.2 ‐ Generation under Construction ........................................118

Figure 7.2.3 ‐ Generation under Development .......................................118

Figure 7.2.4 ‐ Changes to Existing Generation........................................119

Figure 7.2.5 ‐ Generation Retirements......................................................119

Figure 7.2.6 ‐ Planned Transmission Additions .....................................120

Figure 7.2.7 ‐ Future Renewable Resources.............................................121
vi

APPENDIX................................................................................................................................................AP ‐ 1

Appendix 2A ‐ Total Sales by Customer Class...................................................................................AP ‐ 2

Appendix 2B ‐ North Carolina Sales by Customer Class .................................................................AP ‐ 3

Appendix 2C ‐ Virginia Sales by Customer Class .............................................................................AP ‐ 4

Appendix 2D ‐ Total Customer Count.................................................................................................AP ‐ 5

Appendix 2E ‐ North Carolina Customer Count................................................................................AP ‐ 6

Appendix 2F ‐ Virginia Customer Count ............................................................................................AP ‐ 7

Appendix 2G ‐ Summer & Winter Peaks.............................................................................................AP ‐ 8

Appendix 2H ‐ Projected Summer & Winter Peak Load & Energy Forecast ................................AP ‐ 9

Appendix 2I ‐ Required Reserve Margin...........................................................................................AP ‐ 10

Appendix 2J ‐ Economic Assumptions used in the Sales and Hourly Budget Model..............AP ‐ 11

Appendix 3A ‐ Existing Generation Units in Service .....................................................................AP ‐ 12

Appendix 3B ‐ Other Generation Units .............................................................................................AP ‐ 14

Appendix 3C ‐ Equivalent Availability Factor  ................................................................................AP ‐ 22

Appendix 3D ‐ Net Capacity Factor....................................................................................................AP ‐ 24

Appendix 3E ‐ Heat Rates.....................................................................................................................AP ‐ 26

Appendix 3F ‐ Existing Capacity.........................................................................................................AP ‐ 30

Appendix 3G ‐ Energy Generation by Type .....................................................................................AP ‐ 31

Appendix 3H ‐ Actual Energy Generation by Type ........................................................................AP ‐ 32

Appendix 3I ‐ Planned Changes to Existing Generation Units.....................................................AP ‐ 33

Appendix 3J ‐ Potential Unit Retirements.........................................................................................AP ‐ 36

Appendix 3K ‐ Planned Generation under Construction...............................................................AP ‐ 37

Appendix 3L ‐ Wholesale Power Sales Contracts ............................................................................AP ‐ 38

Appendix 3M ‐ Description of Approved DSM Programs ............................................................AP ‐ 39

Appendix 3N ‐ Approved Programs Non‐Coincidental Peak Savings ........................................AP ‐ 45

Appendix 3O ‐ Approved Programs Coincidental Peak Savings .................................................AP ‐ 46

Appendix 3P ‐ Approved Programs Energy Savings.......................................................................AP ‐ 47

Appendix 3Q ‐ Approved Programs Penetrations ...........................................................................AP ‐ 48

Appendix 3R ‐ Proposed Programs Non‐Coincidental Peak Savings..........................................AP ‐ 49

Appendix 3S ‐ Proposed Programs Coincidental Peak Savings....................................................AP ‐ 50

Appendix 3T ‐ Proposed Programs Energy Savings........................................................................AP ‐ 51

Appendix 3U ‐ Proposed Programs Penetrations.............................................................................AP ‐ 52

Appendix 3V ‐ Generation Interconnection Projects under Construction..................................AP ‐ 53

Appendix 3W ‐ List of Transmission Lines under Construction ..................................................AP ‐ 54
vii

Appendix 4A ‐ ICF Commodity Price Forecasts for Dominion Virginia Power........................AP ‐ 55

Appendix 4B ‐ Delivered Fuel Data....................................................................................................AP ‐ 71

Appendix 5A ‐ Tabular Results of Busbar ........................................................................................AP ‐ 72

Appendix 5B ‐ Busbar Assumptions ..................................................................................................AP ‐ 73

Appendix 5C ‐ Planned Generation under Development..............................................................AP ‐ 74

Appendix 5D ‐ Standard DSM Test Descriptions ...........................................................................AP ‐ 75

Appendix 5E ‐ DSM Programs Energy Savings ...............................................................................AP ‐ 76

Appendix 5F ‐ Description of Future DSM Programs.....................................................................AP ‐ 77

Appendix 5G ‐ Future Programs Non‐Coincidental Peak Savings...............................................AP ‐ 79

Appendix 5H ‐ Future Programs Coincidental Peak Savings........................................................AP ‐ 80

Appendix 5I ‐ Future Programs Energy Savings ..............................................................................AP ‐ 81

Appendix 5J ‐ Future Programs Penetrations ...................................................................................AP ‐ 82

Appendix 5K ‐ Planned Generation Interconnection Projects ......................................................AP ‐ 83

Appendix 5L ‐ List of Planned Transmission Lines ........................................................................AP ‐ 84

Appendix 6A ‐ Renewable Resources ................................................................................................AP ‐ 85

Appendix 6B ‐ Potential Supply‐Side Resources.............................................................................AP ‐ 86

Appendix 6C ‐ Summer Capacity Position........................................................................................AP ‐ 87

Appendix 6D ‐ Construction Forecast................................................................................................AP ‐ 88

Appendix 6E ‐ Capacity Position.........................................................................................................AP ‐ 89
viii

LIST OF ACRONYMS 

Acronym Meaning

2013 Plan 2013 Integrated Resource Plan

2014 Plan 2014 Integrated Resource Plan

AC Alternating Current

AMI Advanced Metering Infrastructure

ATC Available Transfer Capability

BOEM Bureau of Ocean Energy Management

BTMG Behind‐the‐Meter Generation

Btu British Thermal Unit

CAP Presidentʹs Climate Action Plan

CAPP Central Appalachian

CC Combined Cycle

CCS Carbon Capture and Sequestration

CDG Commercial Distributed Generation  

CFB Circulating Fluidized Bed

CFL Compact Florescent Light

CO2 Carbon Dioxide

COD Commercial Operation Date

COL Combined Construction Permit and Operating License

Company Virginia Electric and Power Company d/b/a Dominion North Carolina Power and Dominion Virginia Power

CPCN Certificate of Public Convenience and Necessity

CS Curtailable Service

CSP Concentrating Solar Power

CT Combustion Turbine

DC Direct Current

DG Distributed Generation

DMME Department of Mines, Minerals and Energy

DOE Department of Energy

DOM LSE Dominion Load Serving Entity

DOM Zone Dominion Zone within the PJM Interconnection, L.L.C. Regional Transmission Organization

DSI Dry Sorbent Injection

DSM Demand‐Side Management

EM&V Evaluation, Measurement, and Verification

EPA Environmental Protection Agency

EPRI Electric Power Research Institute

ESBWR Economic Simplified Boiling Water Reactor

EV Electric Vehicle

FERC Federal Energy Regulatory Commission
ix

Acronym Meaning

Fluor Fluor Enterprises, Inc.

GEH GE‐Hitachi Nuclear Energy Americas LLC

GHG Greenhouse Gas

GSP Gross State Product

GWh Gigawatt Hour(s)

Hg Mercury

HVAC Heating, Ventilating, and Air Conditioning

IBGS Inward Battered Guide Structures

ICF ICF International, Inc.

IDR Interval Data Recorder

IGCC Integrated‐Gasification Combined‐Cycle

IRM Installed Reserve Margin

IRP Integrated Resource Planning

KBR Kellogg, Brown and Root

kV Kilovolt(s)

kW Kilowatt(s)

kWh Kilowatt Hour

LMP Locational Marginal Pricing

LOLE Loss of Load Expectation

LSE Load Serving Entity

MW Megawatt(s)

MWh Megawatt Hour(s)

NCGS North Carolina General Statute

NCUC North Carolina Utilities Commission

NERC North American Electric Reliability Corporation

NNS Newport News Shipbuilding

North Anna 3 North Anna Unit 3

NOx Nitrogen Oxide

NPV Net Present Value

NRC Nuclear Regulatory Commission

NREL The National Renewable Energy Laboratory

NSPS New Source Performance Standards

NUG Non‐Utility Generation or Non‐Utility Generator

O&M Operation and Maintenance

ODEC Old Dominion Electric Cooperative

ODU Old Dominion University

OEM Original Equipment Manufacturers
x

Acronym Meaning

PC Pulverized Coal

PHEV Plug‐in Hybrid Electric Vehicle

PJM PJM Interconnection, L.L.C.

Plan 2014 Integrated Resource Plan

PTC Production Tax Credit

PURPA Public Utility Regulatory Policies Act of 1978

PV Photovoltaic

REC Renewable Energy Certificate

REPS Renewable Energy and Energy Efficiency Portfolio Standard (NC)

RFC Reliability First Corporation

RFP Request for Proposals

RIM Ratepayer Impact Measure

RPM Reliability Pricing Model

RPS Renewable Energy Portfolio Standard (VA)

RTEP Regional Transmission Expansion Plan

RTO Regional Transmission Organization

SCC Virginia State Corporation Commission

SCPC Super Critical Pulverized Coal

SCR Selective Catalytic Reduction

SG Standby Generation

SMR Small Modular Reactors

SNCR Selective Non‐Catalytic Reduction

SO2 Sulfur Dioxide

SPP Solar Partnership Program

SRP Stakeholder Review Process

STAP Short‐Term Action Plan

Strategist Strategist Model

T&D Transmission and Distribution

TRC Total Resource Cost

UCT Utility Cost Test

Va. Code 56‐599 of the Code of Virginia

VACAR Virginia‐Carolinas Reliability Agreement

VCHEC Virginia City Hybrid Energy Center

VOW Virginia Offshore Wind Coalition

VOWDA Virginia Offshore Wind Development Authority

VOWTAP Virginia Offshore Wind Technology Advancement Project

WEA Wind Energy Area
xi

INTRODUCTION 

Virginia Electric and Power Company d/b/a Dominion North Carolina Power and Dominion

Virginia Power (collectively, the “Company”) files its 2014 Integrated Resource Plan (“2014 Plan” or

“Plan”) in accordance with § 62‐2 of the North Carolina General Statutes (“NCGS”) and Rule R8‐60

of the North Carolina Utilities Commission’s (“NCUC”) Rules and Regulations, as well as § 56‐599

of the Code of Virginia (“Va. Code”) and the Virginia State Corporation Commission’s (“SCC”)

guidelines issued on December 23, 2008.

The 2014 Plan is consistent with the Company’s longstanding belief that a balanced blend of cost‐

effective supply‐ and demand‐side resources is the most effective way to meet its customers’ needs,

which continue to grow in its North Carolina and Virginia service territories, while complying with

an evolving environmental regulatory landscape.  The Company’s long‐range forecast indicates that

customer demand for energy in the Dominion Load Serving Entity (“DOM LSE”) load area, the area

served by the Company in two states, will continue to grow during the Planning Period, with peak

demand and overall energy use increasing by average annual rates of 1.4% and 1.3%, respectively.  

Also, the regional transmission operator of which the Company is a member, PJM Interconnection,

L.L.C. (“PJM”), forecasts that summer peak demand in the DOM LSE is projected to grow at a faster

rate than any other part of its 13‐state control area during the period 2014 ‐ 2024.  

A balanced approach will help the Company meet this growing demand while protecting customers

from a variety of potentially negative impacts and challenges.  These include changing regulatory

requirements, particularly regulation of carbon dioxide (“CO2”) emissions from new and existing

electric generation by the U.S. Environmental Protection Agency (“EPA”) and commodity price

volatility and reliability concerns based on excessive reliance on any single fuel source.  This

approach reflects the legislative and regulatory mandates of both North Carolina and Virginia.  Rule

R8‐60 of the NCUC directs that the integrated resource plan contain “a comprehensive analysis of all

resource options (supply‐ and demand‐side).”  Similarly, Va. Code § 56‐598(3) requires that the

integrated resource plan “reflect a diversity of electric generation supply and cost‐effective demand

reduction contracts....”   

The 2014 Plan reflects the Company’s most current planning assumptions regarding factors such as

fuel prices, load growth, economic conditions, fuel diversity, and equipment costs.  To assess the

uncertainties and risks presented by external market, regulatory and environmental factors, the

Company developed six alternative plans (“Alternative Plans”) representing plausible future paths

for meeting customer needs, and subjected them to 15 different scenarios and sensitivities.  

In recognition of the uncertainties going forward and the corresponding complexity these

uncertainties present for planning, as well as the Company’s strong belief in the customer benefits of

fuel diversity, the Company developed a Portfolio Evaluation Scorecard.  This Scorecard provides a

quantitative and qualitative measurement system to assess the different alternatives, using criteria

that include cost, rate stability, greenhouse gas emissions and reliance on a single fuel source,

natural gas.  The Scorecard allows additional evaluation of the Alternative Plans compared to the

Base Plan, which is the least‐cost alternative and relies primarily on natural gas‐fired generation to
xii

meet new capacity and energy needs.  The Portfolio Evaluation Scorecard is presented in Section

6.6.1.   

The evaluations of the Alternative Plans and the Scorecard were used in determining the 2014 Plan.  

Additionally, as with other integrated resource plans, the 2014 Plan is not a request for approval of

any particular resource, nor is it a commitment to any particular resource.

Options Presented in the 2014 Plan

As noted above, through the integrated resource planning (“IRP”) process, the Company has

assessed a range of options for meeting customer demand in an environment that presents

considerable uncertainty, including fuel prices, federal regulation of greenhouse gas (“GHG”)

emissions from new and existing electric generating sources, and other potential regulatory

requirements.  Based on these assessments, the Company recommends a strategic path forward that

continues to follow the resource expansion of the Base Plan, designed using least‐cost planning

methods, and concurrently a Fuel Diversity Plan that continues forward with reasonable

development efforts for a broader array of low or zero‐emission resources, including nuclear, wind,

and increased amounts of solar technologies.  Collectively, this recommended path forward is the

2014 Plan, presented in this document.   

Under current planning assumptions, the resources included in the Fuel Diversity Plan lead to its

higher cost compared to the Base Plan.  However, the Company believes the low or zero‐emission

components combined with reducing reliance on a single fuel for future expansion addressed in the

Fuel Diversity Plan will likely be needed, by both the Company and its customers, to address future

uncertainties, which includes the EPA’s proposed rules regarding GHGs from new and existing

generation sources.   

The importance of generation emitting little or no carbon was reinforced on June 2 of this year, with

the EPA’s issuance of its proposed EPA GHG regulations.  The proposed EPA GHG regulations,

known as the Clean Power Plan or Rule 111(d), would significantly reduce carbon emissions from

existing electric generating units and achieve this goal by mandating substantial reductions in

carbon intensity (the average amount of CO2 released for each megawatt‐hour (“MWh”) of

electricity production.)  The proposed EPA GHG regulations include ambitious carbon intensity

reduction targets for the statewide electric generation fleets in North Carolina, Virginia and West

Virginia, the states in which the Company owns generating capacity.  Virginia and North Carolina

have the two most aggressive carbon intensity goals in the Mid‐Atlantic region.  Measured against

base year 2012 levels calculated by EPA, the draft rule would require a 40% reduction in average

fleet‐wide carbon intensity for North Carolina, a 38% reduction for Virginia, and a 20% reduction for

West Virginia, all by 2030.  Under the EPA’s proposed schedule, the final rule would be

promulgated in June 2015, with implementation plans from the individual states due starting in

2016.

In order to meet the EPA’s proposed CO2 intensity target for Virginia averaging 884 lb/MWh for the

years between 2020 and 2029, and 810 lb/MWh for 2030 and beyond, this document includes Plan F:

EPA GHG Plan.  To comply with these stringent emission levels, Plan F models coal retirements, as

well as additional solar, wind and nuclear resources.  Plan F is included in this planning document
xiii

to provide one potential scenario of how the Company could meet the 2030 EPA proposed targets.  

Although EPA’s GHG regulations are now in draft form, with issuance of a final rule scheduled for

June 2015, the Company believes it is prudent to begin planning now for implementation of a final

rule substantially similar to the June 2014 proposal, given the rule’s complexities and tight timelines

for compliance.

Avoiding overreliance on any single fuel type also remains an important objective of the Company’s

IRP process.  Although non‐storable, natural gas is clean, abundant and available typically at

relatively low prices.  However, the interstate transmission pipeline network can face severe

constraints, particularly in the Company’s service territory, leading to extremely high prices and

possible regional supply shortages during periods of intense demand, such as the Polar Vortex

events during the winter of 2014.  For example, average gas prices on one of the primary hubs

serving Virginia rose by more than 500%, from $10.78 per MMBtu to $72.62 per MMBtu, from

January 6 to January 7, 2014.  Later in the month, on January 22, spot prices on this hub surged to

$118.10 per MMBtu during another outbreak of extreme cold.  However, by July 20, 2014, prices

were back down to $3.80 per MMBtu.  The Company recognizes that the natural gas industry is in a

transition period, and transportation solutions are under development to address these economic

and supply concerns.  These investments will be an important part of ensuring both reliability and

cost effectiveness of electricity supply, but this should not be interpreted as a commitment to

overreliance on natural gas.     

In light of these developments and other uncertainties, the Company strongly recommends that it

continue to evaluate and develop the broader array of resources presented in the Fuel Diversity

Plan.

New Renewable Resources common to both the Base Plan and the Fuel Diversity Plan

The Base and Fuel Diversity Plans have many elements in common, including the addition of energy

and capacity from renewable resources to the Company’s generation portfolio, building on the

Company’s successful history of prudently integrating cost‐effective renewable options into its

overall fuel mix.

Both the Base Plan and the Fuel Diversity Plan include 200 MW (nameplate) of solar generation to be

provided by one or more Non‐Utility Generators (“NUG”) under long‐term contract to the

Company by 2016, as well as 13 MW (nameplate) (15 MW Direct Current (“DC”)) from the first

phase of the Company’s Solar Partnership Program (“SPP”).  This initiative installs Company‐

owned solar arrays on rooftops and other spaces rented from customers at sites throughout the

service area.  

The Base Plan  

The Base Plan represents the least‐cost path forward for the Company, using current assumptions,

the current commodity forecast, and the current regulatory environment, without consideration of

proposed or pending regulations that have not yet taken effect.   Additionally:

 The Base Plan calls for the Company to continue to take advantage of the economical

supplies of power available to it in the wholesale market operated by PJM, with net market
xiv

purchases averaging 319 MW of capacity and 8% of energy supplied to customers annually

during the Planning Period (2015 ‐ 2029).

 The Base Plan also includes two major combined‐cycle (“CC”) natural gas generation

projects under construction, including the 1,337 MW Warren County Power Station,

scheduled to be operational by 2015, and the 1,375 MW Brunswick County Power Station,

scheduled to be operational in 2016.   

 The Base Plan incorporates the retirements of 901 MW of coal‐fired capacity at Chesapeake

Energy Center and Yorktown Power Station.  The Company determined that continued

operation of the Chesapeake and Yorktown coal units would have required expensive

environmental compliance controls that would not be cost‐effective for the Company’s

customers.  The coal units at Chesapeake and Yorktown are currently scheduled for

shutdown by 2015 and in 2016, respectively.  

 The Base Plan includes demand‐side management programs that are expected to reduce the

system summer peak demand for electricity by 583 MW by 2029.

 For major future generation projects, the Base Plan makes almost exclusive use of one fuel

source: natural gas.  It includes two additional CCs, with a total capacity of 3,132 MW, and

two additional banks of combustion turbines (“CTs”), with a total capacity of 914 MW.  

These facilities, to be built at yet‐undesignated sites, would begin operation from 2019 to

2029.

The Fuel Diversity Plan  

As noted, the Fuel Diversity Plan has many elements in common with the Base Plan, including cost‐

effective demand‐side management programs that will reduce 2029 summer peak demand by 583

MW and net market purchases of economical power, from the wholesale market operated by PJM,

averaging 309 MW of capacity and 7% of energy supplied to customers over the 2015 – 2029

Planning Period.

However, the Fuel Diversity Plan provides additional alternatives over the Planning Period for

meeting future customer needs and reduces the Company’s reliance on natural gas as the fuel source

for expansion of the generation fleet.   

While the Base Plan selects two additional CCs beyond the Warren and Brunswick County Power

Stations, the Fuel Diversity Plan includes significantly greater levels of new generation fueled by

alternatives to natural gas compared to the Base Plan.  The Fuel Diversity Plan has the potential to

meet the proposed EPA targets with additional renewable resources and coal retirements, similar to

Plan F: EPA GHG Plan.

While the Base Plan outlines a plausible, least‐cost path forward for dealing with the increasing

demand for electricity, the Company will, at a minimum, continue to evaluate and develop

additional alternatives for renewable energy and nuclear‐powered generation described in the Fuel

Diversity Plan.  Some of the differing characteristics of this plan are detailed below.  
xv

Solar

The Fuel Diversity Plan includes additional solar resources with capacity of approximately 559 MW

(nameplate) by 2029.  This includes several new Company‐owned photovoltaic (“PV”) installations.  

Solar PV costs have declined substantially in recent years, provide a valuable source of fuel diversity

and produce emissions free energy for customers.  Continuing technological development, in which

the Company is now participating, may allow solar resources to become a more reliable resource in

the future.  Due to the highly variable nature of the resource, solar facilities may not be available to

meet peak demands.  They also generally make capacity contributions at much lower levels than

their nameplate ratings.

Wind

The Company’s Fuel Diversity Plan includes three onshore wind facilities and a demonstration

facility off the Virginia coast.  While onshore wind resources are limited in the Mid‐Atlantic area, the

Company has identified three sites in Virginia for potential wind development, with a combined

capacity of 247 MW (nameplate) that would enter service from 2020 to 2022.   

In North Carolina and Virginia, offshore wind is widely recognized as a resource with great

potential.  The technology currently faces significant cost barriers, due to complex and costly

installation and maintenance requirements in a marine environment.  However, the Company is

leading efforts to prudently develop offshore wind and overcome these barriers.  A 12 MW

(nameplate) Offshore Wind Demonstration Project, the Virginia Offshore Wind Technology

Advancement Project (“VOWTAP”), is included in the Fuel Diversity Plan, with the first full year of

operation anticipated in 2018.  The Company and several industry and government partners are

collaborating on the project, which would involve construction of two 6 MW turbines at a test site

off the Virginia coast upon receipt of regulatory approvals.  The Company‐led project received a $4

million U.S. Department of Energy (“DOE”) grant for initial design, engineering and permitting in

December 2012, and an additional federal grant for up to $47 million in May 2014.  The project is

currently undergoing detailed engineering and design activities to support construction and

operation.

In September 2013, the Company was awarded the lease of a 112,800‐acre area approximately 27

miles off the Virginia coast for wind energy development through an auction conducted by the U.S.

Bureau of Ocean Energy Management (“BOEM”).  Initial estimates indicate the area could

accommodate up to 2,000 MW of wind‐powered capacity.  The Company continues to develop

commercial scale alternatives and to pursue technological, installation and supply chain advances

that would reduce costs to make a commercial scale development a prudent investment for

ratepayers.  

Nuclear Energy

The Company believes that nuclear energy, capable of producing large amounts of clean baseload

power around the clock with little or no GHG emissions, will continue to play a significant role in its

generation mix throughout the Planning Period and beyond.  Nuclear construction remains time‐

consuming, with various permits for design, location and operation required by government

agencies.  Once operational, however, nuclear facilities have the lowest fuel cost of any dispatchable

baseload generation option.
xvi

Therefore, the Fuel Diversity Plan reflects the Company’s continued development activities that

preserve the ability to construct a third reactor at its North Anna Power Station in Virginia.  North

Anna Unit 3 (“North Anna 3”) would have a generating capacity of approximately 1,453 MW and be

powered by Economic Simplified Boiling Water Reactor (“ESBWR”) technology developed by GE‐

Hitachi Nuclear Energy Americas L.L.C. (“GEH”).  

While the Company has not committed to building this unit, it believes that new nuclear is likely to

be an important part of state efforts to comply with the proposed EPA GHG regulations or any

substantially similar regulation.  As a result, the Company continues to develop the project and is

pursuing receipt of all necessary regulatory approvals.  A final decision is expected following receipt

of a Combined Operating License (“COL”), anticipated in 2016, for the project from the U.S. Nuclear

Regulatory Commission (“NRC”).  If the Company decides to proceed, the Fuel Diversity Plan

anticipates the unit’s first full year of availability would be 2028, with the earliest commercial

operation date (“COD”) occurring in September 2027.  

Conclusions  

The Company’s 2014 Plan meets expected customer demand growth and reserve requirements in a

cost‐effective manner.  The 2014 Plan includes a Base Plan that, given current conditions, represents

the least‐cost alternative for addressing increasing demand but relies almost exclusively on natural

gas for major expansions of generating capacity in the future.  The 2014 Plan also presents a Fuel

Diversity Plan, which contains additional zero and low‐emission options that may become necessary

during the Planning Period given proposed federal regulation of GHG and the Company’s own

planning objective of avoiding overreliance on any single fuel.  The Fuel Diversity Plan both reduces

the Company’s carbon intensity and its reliance on natural gas as a source of future generation.  The

Company, therefore, will follow the resource expansion of the Base Plan and concurrently continue

forward with reasonable development efforts of the additional resources of the Fuel Diversity Plan.  

These continued development activities, particularly for nuclear and renewable energy, will

preserve the Company’s flexibility to implement the best plan as future uncertainties become more

clear.
1

CHAPTER 1 – EXECUTIVE SUMMARY 

1.1 INTEGRATED RESOURCE PLAN OVERVIEW  

On August 30, 2013, the Company filed its 2013 Integrated Resource Plan (“2013 Plan”) as an update

with the NCUC (Docket No. E‐100, Sub 137) and with the SCC (Case No. PUE‐2013‐00088).  On June

30, 2014, the NCUC issued its Order Approving Integrated Resource Plan Annual Update Reports

and REPS Compliance Plans.  The SCC entered its Final Order on August 27, 2014.   

The 2014 Plan was prepared for the DOM LSE, and represents the Company’s service territories in

North Carolina and the Commonwealth of Virginia, which are part of the PJM Regional

Transmission Organization (“RTO”).  

The Company’s objective in developing the 2014 Plan was to identify the mix of resources necessary

to meet its customers’ projected energy and capacity needs in an efficient and reliable manner at the

lowest reasonable cost, while considering future uncertainties.  The Company’s options for meeting

these future needs are: i) supply‐side resources, ii) demand‐side resources, and iii) market

purchases.

The 2014 Plan is a long‐term planning document and should be viewed in that context.  It should be

noted that provisions of North Carolina and Virginia law result in the Company preparing an

integrated resource plan every year.

Inclusion of a project in any given year’s plan is not a commitment to construct a particular project

or a request for approval of a particular project.  Conversely, not including a specific project in a

given year’s plan does not preclude the Company from including that project in subsequent

regulatory filings.  

The Company used the Strategist model (“Strategist”), a utility modeling and resource optimization

tool, to develop its 2014 Plan over a 25‐year period, beginning in 2015 and continuing through 2039

(“Study Period”), using 2014 as the base year.  For purposes of this Plan, the Company displays text,

numbers, and appendices for a 15‐year period from 2015 to 2029 (“Planning Period”).  The 2014 Plan

is based on the Company’s current assumptions regarding load growth, commodity price

projections, Demand‐Side Management (“DSM”) programs, and many other regulatory and market

developments that may occur during the Study Period.

The 2014 Plan includes sections on load forecasting (Chapter 2), existing and proposed resources

(Chapter 3), planning assumptions (Chapter 4), and future resources (Chapter 5).  Additionally, the

2014 Plan includes Chapter 6, titled “Development of the Integrated Resource Plan,” which defines

the IRP process, outlines several Alternative Plans that were compared by weighing the costs of

those plans using a variety of sensitivities, and scenarios and other non‐cost factors, and describes

the Portfolio Evaluation Scorecard process.  This analysis allowed the Company to examine alternate

plans given industry uncertainties, such as commodity and construction prices, environmental

regulations and resource mix.  The 2014 Plan also contains a Short‐Term Action Plan (“STAP”)

(Chapter 7), which discusses the Company’s specific actions currently underway to support the 2014

Plan over the next five years (2015 ‐ 2019).
2

Starting in 2010, the Company initiated its Stakeholder Review Process (“SRP”), which is a forum to

inform stakeholders about the IRP process and to provide more specific information about the

Company’s planning process, including IRP and DSM initiatives, and to receive stakeholder input.  

The SCC also directed the Company to coordinate with interested parties in sharing DSM program

Evaluation, Measurement and Verification (“EM&V”) results and in developing future DSM

program proposals.  Several SRP suggestions have been incorporated into the Company’s new

Virginia DSM Program approval filing made coincident with the 2014 Plan in Case No.  

PUE‐2014‐00071.  In addition, this Plan includes 559 MW generic solar as suggested through a

previous SRP meeting and incorporates additional evaluation of the costs, benefits and risks

associated with the value of increased fuel diversity through the Portfolio Evaluation Scorecard.  The

Company is committed to continuing the SRP and expects the next SRP meeting to occur in the fall

of 2014.

1.2 COMPANY DESCRIPTION

The Company, headquartered in Richmond, Virginia, currently serves approximately 2.4 million

electric customers located in approximately 30,000 square miles in North Carolina and Virginia.  The

Companyʹs regulated electric portfolio consists of 19,424 MW of generation capacity, including

approximately 1,747 MW of NUG resources, over 6,400 miles of transmission lines at voltages

ranging from 69 kilovolts (“kV”) to 500 kV, and more than 57,000 miles of distribution lines at

voltages ranging from 4 kV to 46 kV in North Carolina, Virginia and West Virginia.  In May 2005,

the Company became a member of PJM, the operator of the wholesale electric grid in the Mid‐

Atlantic region of the United States.  As a result, the Company transferred operational control of its

transmission assets to PJM.  

The Company has a diverse mix of generating resources consisting of Company‐owned nuclear,

fossil, hydro, pumped storage, biomass and solar facilities.  Additionally, the Company purchases

capacity and energy from NUGs and the PJM market.

1.3 2014 INTEGRATED RESOURCE PLANNING PROCESS

In order to meet future customer needs at the lowest reasonable cost while maintaining reliability

and flexibility, the Company must take into consideration the uncertainties and risks associated with

the energy industry.  Uncertainties assessed in the 2014 Plan include:

 load growth in the Company’s service territory;

 effective and anticipated EPA regulations concerning air, water, and solid waste constituents

(as shown in Figure 3.1.3.1), particularly the proposed EPA GHG regulations regarding CO2

emissions from new and existing electric generating units;   

 fuel prices;

 cost and performance of energy technologies;

 retirements of non‐Company controlled units that may impact available purchase power

volumes;  

 renewable energy requirements.
3

The Company has developed a 2014 Plan resulting from the evaluation of various supply‐ and

demand‐side alternatives, considering acceptable levels of risk that maintains the option to develop

a diverse mix of resources for the benefit of its customers.  Various planning groups throughout the

Company provided input and insight into evaluating all viable options, including existing

generation, DSM programs, and new (both traditional and alternative) resources to meet the

growing demand in the Company’s service territory.  The IRP process began with the development

of the Company’s long‐term load forecast, which indicates that over the Planning Period, the DOM

LSE is expected to have annual increases in future peak and energy requirements of 1.4% and 1.3%,

respectively.  Growth in both states within the Company’s regulated service territory remains

among the highest in PJM.  Collectively, these elements assisted in determining updated capacity

and energy requirements as illustrated in Figure 1.3.1 and Figure 1.3.2.  

Figure 1.3.1 ‐ Current Company Capacity Position (2015 – 2029)

 

Note: The values in the boxes represent total capacity in 2029.  

1) Accounts for unit retirements and rating changes to existing units in the Plan, and reflects summer ratings.

2) See Section 4.2.2.

NUGs

10,000

12,000

14,000

16,000

18,000

20,000

22,000

24,000

26,000

MW

Existing Generation1

Capacity

Gap

Generation

UnderConstruction

Approved DSM

16,519

2,716

3,570

36

425
4

Figure 1.3.2 ‐ Current Company Energy Position (2015 – 2029)  

 

Note: The values in the boxes represent total energy in 2029.  

1) Accounts for unit retirements and rating changes to existing units in the Plan.

1.4 2014 PLAN  

To assess the uncertainty and risks associated with external market and environmental factors, the

Company developed six Alternative Plans representing plausible future paths the Company could

follow to meet the future electric power needs of its customers.  The Company evaluated the six

Alternative Plans using 15 scenarios and sensitivities, as discussed in Chapter 6.  In addition, the

Company performed a Portfolio Evaluation Scorecard analysis with respect to each of the

Alternative Plans, described in greater detail in Section 6.6.1.  Based on this analysis, the Company

selects a going‐forward strategic plan that contains an optimal mix of supply‐ and demand‐side

options to meet expected future customer needs at the lowest reasonable cost.  As with any strategic

plan, the Company will update its future plans to incorporate new information as it becomes

known.

For this 2014 Plan, the Company recommends a path forward that continues to follow an expansion

consistent with Plan A: Base Plan, which follows least‐cost methodology given current assumptions,

and concurrently continues forward with reasonable development efforts of the additional resources

identified in Plan B: Fuel Diversity Plan (Plan A and B are specified in Chapter 6).  Collectively, this

recommended path forward is the 2014 Plan.

The electric power industry has been, and continues to be, dynamic in nature with rapidly changing

developments and regulatory challenges.  The Company expects that these dynamics will continue

into the future and will be further complicated by larger scale societal trends including national

NUGs

40,000

50,000

60,000

70,000

80,000

90,000

100,000

110,000

120,000 GWh

Generation Under

Construction

Existing Generation1

Energy

Gap

Approved DSM

33,196

58,647

12,521

693

176
5

security considerations (which include infrastructure security), climate change regulation, and

customer preferences.  Therefore, it is prudent for the Company to preserve reasonable development

options available to it in order to be able to respond to the future market, regulatory, and industry

changes that are likely to occur in some form, but are difficult to predict at the present time.  

Consequently, the Company recommends (and plans for), at a minimum, continued development of

the additional supply‐side resources included in Plan B: Fuel Diversity Plan identified in Chapter 6.  

The Company will also continue with reasonable development of other emerging technologies.  

Plan A: Base Plan, in addition to traditional supply‐ and demand‐side options, includes 200 MW

(nameplate) solar, to be provided through purchase power agreements (referenced as “solar NUG”)

and 13 MW (nameplate) (15 MW DC) of solar capacity from the SPP (approved by the SCC in Case

No. PUE‐2011‐00117).    

In addition to the resources identified in the Base Plan, Plan B: Fuel Diversity Plan provides the most

reliable baseload, near emissions‐free energy over the long‐term by including an additional nuclear

unit with a net generating capacity of 1,453 MW at the Company’s North Anna Power Station.  

Additionally, the Fuel Diversity Plan includes 247 MW (nameplate) of onshore wind, 39 MW

(nameplate) of brownfield (i.e. connecting at existing and future potential power generating

facilities) solar development (“solar tag”); 520 MW (nameplate) of additional solar development,

and the 12 MW (nameplate) Offshore Wind Demonstration Project during the Planning Period.  

Nuclear units, despite their high upfront capital costs, have low long‐term fuel costs (with little

correlation to fossil fuel commodity prices), little to no air emissions, and a long track record of

delivering reliable baseload energy and improving fleet diversity.  The Company’s customers today

benefit substantially from the Company’s prior investments in the four nuclear units, at North Anna

and Surry.  Accordingly, the Company continues to develop an additional nuclear unit at North

Anna and to examine options for extending the licensed life of its existing four nuclear units.

Both Plan A: Base Plan and Plan B: Fuel Diversity Plan are displayed in Figures 1.4.1(a) and 1.4.1(b),

respectively.  
6

Figure 1.4.1(a) ‐ 2014 Base Plan

 

Figure 1.4.1(b) ‐ 2014 Fuel Diversity Plan

Key: Retrofit: Additional environmental control reduction equipment; Repower: Convert fuel to biomass or repower by natural gas; Retire:

Remove a unit from service; Brunswick: Brunswick County Power Station; CEC: Chesapeake Energy Center Unit; CC: Combined‐Cycle; CT:

Combustion Turbine (2 units); OFFD: Offshore Wind Demonstration Project; North Anna 3: North Anna Unit 3; PP5: Possum Point Unit 5;

SNCR: Selective Non‐Catalytic Reduction; SLR: Generic Solar (40 MW); SLR NUG: Solar NUG; SLR TAG: Solar Tag; SPP: Solar Partnership

Program; Warren: Warren County Power Station; WND: Onshore Wind; YT: Yorktown Unit.

Note: 1) DSM capacity savings continue to increase throughout the Planning Period.

2) Earliest possible in‐service date for North Anna 3 is September 2027, which is reflected as a 2028 capacity resource.

3) SPP and SLR NUG started in 2014.

New

Conventional

New            

Renew able Retrofit Repow er Retire

2015 Warren SLR NUG/SPP3     CEC 1‐4   

2016 Brunswick SLR NUG/SPP3 YT 1‐2

2017

2018

PP5 – SNCR

YT3 – SNCR

2019 CC

2020

2021

2022 CT

2023 CT

2024

2025

2026

2027

2028

2029 CC

Approved DSM

Proposed & Future

DSM                  

583 MW by 2029

3,063 GWh by 2029

Demand‐side

Resources1 Year

Supply‐side Resources

New

Conventional

New           

Renew able Retrofit Repow er Retire

2015 Warren SLR NUG/SPP3     CEC 1‐4   

2016 Brunswick SLR NUG/SPP3 YT 1‐2

2017 SLR TAG/SLR

2018 OFFD/SLR

PP5 – SNCR

YT3 – SNCR

2019 CC SLR

2020 WND/SLR

TAG/SLR

2021 WND/SLR

2022 CT WND/SLR

2023 SLR

2024 SLR

2025 SLR

2026 SLR

2027 SLR

2028 North Anna 32 SLR

2029 SLR

Year

Supply‐side Resources

Approved DSM

Proposed & Future

DSM                  

583 MW by 2029

3,063 GWh by 2029

Demand‐side

Resources1
7

Plan A: Base Plan includes:

Demand‐Side Resources (currently evaluated):

 approved DSM programs reaching approximately 425 MW by 2029;  

 proposed and future DSM programs reaching approximately 158 MW by 2029;  

Generation under Construction:

 Warren County Power Station, of approximately 1,337 MW of natural gas‐fired CC capacity

by 2015;

 Brunswick County Power Station, of approximately 1,375 MW of natural gas‐fired CC

capacity in 2016;

 Solar Partnership Program, consisting of 4 MW of firm capacity (13 MW nameplate) of solar

distributed generation by 2016;

Generation under Development:

 conventional generation resources including one combined‐cycle (“CC”) totaling

approximately 1,566 MW;

Potential Generation:

 conventional generation resources including one CC unit, totaling approximately 1,566 MW

and two CT1 plants totaling approximately 914 MW;

NUG and Market Purchases:

 76 MW firm capacity (200 MW nameplate) solar NUGs by 2016; and

 PJM net market purchases, which average approximately 319 MW of capacity and 8% of

energy annually over the Planning Period.

Plan B: Fuel Diversity Plan includes:

Demand‐Side Resources (currently evaluated):

 approved DSM programs reaching approximately 425 MW by 2029;  

 proposed and future DSM programs reaching approximately 158 MW by 2029;

Generation under Construction:

 Warren County Power Station, of approximately 1,337 MW of natural gas‐fired CC capacity

by 2015;

 Brunswick County Power Station, of approximately 1,375 MW of natural‐gas fired CC

capacity in 2016;

 Solar Partnership Program, consisting of 4 MW of firm capacity (13 MW nameplate) of solar

distributed generation by 2016;

                                                       

1 All references regarding new CT units throughout this document refer to installation of a bank of two CT units.
8

Generation under Development:

 North Anna 3 (nuclear), of approximately 1,453 MW by 2028 (earliest possible in‐service date

for North Anna 3 is September 2027, which is reflected as a 2028 capacity resource);

 Offshore Wind Demonstration Project, which totals 2 MW firm capacity (12 MW nameplate)

by 2018;

 conventional generation resources including one CC totaling approximately 1,566 MW;

 renewable resources of onshore wind providing 32 MW firm capacity (247 MW nameplate)

by 2022, 2 MW firm capacity (4 MW nameplate) solar tag by 2017 and a 13 MW firm capacity

(35 MW nameplate) solar tag by 2020, and 197 MW (520 MW nameplate) solar by 2029;  

Potential Generation:

 conventional generation resources including one CT, totaling approximately 457 MW;

NUG and Market Purchases:

 76 MW firm capacity (200 MW nameplate) solar NUGs by 2016; and

 PJM net market purchases, which average approximately 309 MW of capacity and 7% of

energy annually over the Planning Period.

The Fuel Diversity Plan incorporates a significant amount of renewable generation.  The following

table identifies the renewable resources included in the Base and Fuel Diversity Plans:
9

Figure 1.4.2 ‐ New Renewable Resources  

Key: A: Plan A: Base Plan; B: Plan B: Fuel Diversity.

To meet the projected demand of electric customers and annual reserve requirements throughout

the Planning Period, the Company has identified additional resources utilizing a balanced mix of

supply‐ and demand‐side resources and market purchases to fill the capacity gap shown in Figure

1.3.1.  These resources are illustrated in Figures 1.4.3(a), 1.4.3(b), 1.4.4(a) and 1.4.4(b).  

Resource Name Year Type

Nameplate 

Capacity 

(MW)

Firm 

Capacity 

(MW)

Plan

Solar NUG 2014 Solar 100 38 A, B

Solar Partnership Program 2014 Distributed Solar 0 63 0 18 A, B

Solar NUG 2015 Solar 50 19 A, B

Solar Partnership Program 2015 Distributed Solar 7 4 2 1 A, B

Solar NUG 2016 Solar 50 19 A, B

Solar Partnership Program 2016 Distributed Solar 4 9 1 4 A, B

Solar 2017 Solar 40 15 B

Solar Tag 2017 Solar 4 2 B

Solar 2018 Solar 40 15 B

Offshore Wind Demonstration Project 2018 Wind 12 2 B

Solar 2019 Solar 40 15 B

Solar 2020 Solar 40 15 B

Solar Tag 2020 Solar 35 13 B

Wind 1 2020 Wind 119 6 16 B

Solar 2021 Solar 40 15 B

Wind 2 2021 Wind 80 5 10 B

Solar 2022 Solar 40 15 B

Wind 3 2022 Wind 46 6 B

Solar 2023 Solar 40 15 B

Solar 2024 Solar 40 15 B

Solar 2025 Solar 40 15 B

Solar 2026 Solar 40 15 B

Solar 2027 Solar 40 15 B

Solar 2028 Solar 40 15 B

Solar 2029 Solar 40 15 B

Total 1,030.43 323.56
10

Figure 1.4.3(a) ‐ Plan A: Base Plan – Capacity (2015 ‐ 2029)

 

Figure 1.4.3(b) ‐ Plan B: Fuel Diversity Plan – Capacity (2015 – 2029)

Note: 1) Accounts for unit retirements and rating changes to existing units in the Plan, and reflects summer ratings.

2) See Section 4.2.2.

NUGs

10,000

12,000

14,000

16,000

18,000

20,000

22,000

24,000

26,000

MW

Generation

Under Construction

Potential Generation

Existing Generation1

Approved DSM

Proposed and Future DSM

Market Purchases

Generation Under

Development

16,519

1,566

2,480

2,716

158

36

425

NUGs

10,000

12,000

14,000

16,000

18,000

20,000

22,000

24,000

26,000

MW

Generation

Under Construction

Potential Generation

Existing Generation1

Approved DSM

Proposed and Future DSM

Market Purchases

Generation Under

Development

16,519

3,265

457

2,716

158

36

425
11

Figure 1.4.4(a) ‐ Plan A: Base Plan – Energy Projection (2015 – 2029)

 

Figure 1.4.4(b) ‐ Plan B: Fuel Diversity Plan – Energy Projection (2015 – 2029)

Note: 1) Accounts for unit retirements and rating changes to existing units in the Plan.

NUGs

40,000

50,000

60,000

70,000

80,000

90,000

100,000

110,000

120,000 GWh

Generation Under

Construction

Potential Generation

Existing Generation1

Generation

Under Development

Approved DSM

Proposed and Future DSM

Market Purchases

12,052

9,129

9,470

58,647

12,521

693

176

2,370

NUGs

40,000

50,000

60,000

70,000

80,000

90,000

100,000

110,000

120,000 GWh

Generation Under

Construction

Potential Generation

Existing Generation1

Generation

Under Development

Approved DSM

Proposed and Future DSM

Market Purchases

8,052

191

22,873

58,004

12,697

693

176

2,370
12

The 2014 Plan balances the Company’s commitment to operate in an environmentally responsible

manner with its obligation to provide reliable and reasonably‐priced electric service.  The Company

has established a strong track record of environmental protection and stewardship and has spent

more than $1.8 billion since 1998 to make environmental improvements to its generation fleet.  These

improvements are projected to reduce the emissions intensity of key pollutants by 85% for Nitrogen

Oxide (“NOx”), 95% for mercury (“Hg”), and 94% for Sulfur Dioxide (“SO2”) by 2015.  

Since numerous EPA regulations are effective and anticipated (as further shown in Figure 3.1.3.1),

various alternatives were analyzed with respect to the Company’s units.  Coal‐fired and/or oil‐fired

units that have limited environmental controls are considered at risk units.  Coal‐fired units that are

environmentally controlled will continue to operate with relatively few additional expenses.  

Environmental compliance offers three options for units: 1) retrofitting with additional

environmental control reduction equipment, 2) repowering to biomass or natural gas, or 3) retiring

the unit.  On June 2, 2014, the EPA issued proposed rules to mitigate future CO2 emissions from

existing electric generation sources (i.e., the proposed EPA GHG regulations).  Final rules from the

EPA are not expected until mid‐2015, and as such, the Company anticipates that these proposed

rules will be revised once comments from stakeholders are received and reviewed by the EPA.   

With the background explained above, the retrofit, repower, and retire units included in the 2014

Plan are as follows:

Retrofit

 1,576 MW of heavy oil‐fired generation installed with new Selective Non‐Catalytic

Reduction (“SNCR”) controls at Possum Point Unit 5 and Yorktown Unit 3 by 2018.

Retire

 901 MW of coal‐fired generation at Chesapeake Energy Center Units 1 ‐ 4 and Yorktown

Units 1 and 2 to be retired by 2015 and in 2016, respectively.

The 2014 Plan positions the Company to address uncertainties associated with potential changes in

market conditions and environmental regulations, while meeting future demand effectively through

a balanced portfolio.   

The Company has established an internal group tasked with developing alternative energy solutions

for customers and is continually evaluating new technologies and new opportunities with existing

technologies.  The Company is cognizant of solar energy technologies and continues to evaluate

different solar options.  Plan B: Fuel Diversity Plan includes 559 MW (nameplate) of solar, as listed

in Figure 1.4.2.  The Company has identified three onshore wind projects that have the potential to

generate a total of 247 MW (nameplate) with no direct fuel costs.  The significant potential for

offshore wind adjacent to the Company’s service territory is a major focus of this group’s current

efforts.  These are described in more detail in Section 5.4.  The Company has also included 200 MW

(nameplate) solar to be provided by one or more NUGs in Plan A: Base Plan and Plan B: Fuel

Diversity Plan.  In addition, the Offshore Wind Demonstration Project, onshore wind and solar are

included as part of Plan B: Fuel Diversity Plan.  
13

While the Planning Period is a 15‐year outlook, the Company is mindful of the scheduled license

expirations of Company‐owned nuclear units: Surry Unit 1 (838 MW) and Surry Unit 2 (838 MW) in

2032 and 2033, respectively, and North Anna Unit 1 (838 MW) and North Anna Unit 2 (834 MW) in

2038 and 2040, respectively.  While this may seem to be in the distant future, the expirations begin to

occur within the Study Period, and the scale of these near emissions‐free baseload retirements, the

potential impact on fuel diversity, and the long lead time associated with developing replacement

nuclear generation demand attention when performing long‐term planning.  Furthermore, the loss

of these existing nuclear units without any additional nuclear units will make it very difficult for the

Company and its customers to comply with the proposed EPA GHG regulations in the decade

beginning in 2030.  Therefore, the Company remains committed to pursuing the development of

resources that meet the needs of customers, while supporting the fuel diversity needed to minimize

risks associated with changing market conditions, industry regulations, and societal megatrends.  As

described in Chapter 6, Plan B: Fuel Diversity Plan, under current planning assumptions, costs more

than Plan A: Base Plan, which relies almost exclusively on new natural gas‐fired generation over the

Study Period.  While natural gas is a critical component of the Company’s fuel mix, nuclear, coal,

DSM, and renewable generation are also central components to achieve the Company’s objective of

long‐term fuel diversity, and thus providing price stability and system reliability in an

environmentally‐responsible manner.  Therefore it is prudent for the Company to pursue a path

forward that follows an expansion consistent with Plan A: Base Plan, while concurrently continuing

forward with reasonable development efforts of the additional resources identified in Plan B: Fuel

Diversity Plan.  Collectively, this recommended path forward is the 2014 Plan.   

Figure 1.4.5(a) and (b) displays the differences between the 2013 Base Plan and the 2014 Base Plan

and the 2013 Fuel Diversity Plan and the 2014 Fuel Diversity Plan, respectively.  
14

Figure 1.4.5(a) ‐ Changes between the 2013 and 2014 Base Plans

 

Key: Retrofit: Additional environmental control reduction equipment; Repower: Convert fuel to biomass or natural gas; Retire: Remove a

unit from service; AV: Altavista; BR: Bremo; Brunswick: Brunswick County Power Station; CEC: Chesapeake Energy  

Center Unit; CC: Combined‐Cycle; CT: Combustion Turbine (2 units); EEP: Energy Extraction Partners; EP&S: Economic Power & Steam

Generation, LLC; HW: Hopewell; MSW: Municipal Solid Waste; North Anna 3: North Anna Unit 3; OFFD: Offshore Wind Demonstration

Project; PP5: Possum Point Unit 5; SH: Southampton; SNCR: Selective Non‐Catalytic Reduction; SLR: Generic Solar (40 MW); SLR NUG:

Solar NUG; SLR TAG: Solar Tag; SPP: Solar Partnership Program; Warren: Warren County Power Station; WND: Onshore Wind; YT:

Yorktown Unit.

Color Key: Blue: Updated resource since 2013 Plan; Red with Strike: 2013 Plan Resource Placement; Black Circle with Arrow: Resource year

movement from 2013 Plan to 2014 Plan.

Note: 1) DSM capacity savings continue to increase throughout the Planning Period.

New

Conventional

New            

Renew able Retrofit Repow er Retire

2013 SPP AV, HW, SH –

Biomass

2014 SPP/SLR NUG

BR3 – Gas    

BR4 – Gas

2015 Warren SPP/EEP            

SLR NUG/EP&S

CEC 1‐4

YT1, YT2

2016 Brunswick SLR NUG/SPP

2017

2018

PP5 – SNCR    

YT3 – SNCR

2019 CC

2020

2021 CT

2022 CT

2023 CT

2024

2025

2026

2027 CC

2028

2029 CC

Approved DSM

Proposed & Future

DSM

Year

Supply‐side Resources

Demand‐side

Resources1
15

Figure 1.4.5(b) ‐ Changes between the 2013 and 2014 Fuel Diversity Plans

Key: Retrofit: Additional environmental control reduction equipment; Repower: Convert fuel to biomass or natural gas; Retire: Remove a

unit from service; AV: Altavista; BR: Bremo; Brunswick: Brunswick County Power Station; CEC: Chesapeake Energy  

Center Unit; CC: Combined‐Cycle; CT: Combustion Turbine (2 units); EEP: Energy Extraction Partners; EP&S: Economic Power & Steam

Generation, LLC; HW: Hopewell; MSW: Municipal Solid Waste; North Anna 3: North Anna Unit 3; OFFD: Offshore Wind Demonstration

Project; PP5: Possum Point Unit 5; SH: Southampton; SNCR: Selective Non‐Catalytic Reduction; SLR: Generic Solar (40 MW); SLR NUG:

Solar NUG; SLR TAG: Solar Tag; SPP: Solar Partnership Program; Warren: Warren County Power Station; WND: Onshore Wind; YT:

Yorktown Unit.

Color Key: Blue: Updated resource since 2013 Plan; Red with Strike: 2013 Plan Resource Placement; Black Circle with Arrow: Resource year

movement from 2013 Plan to 2014 Plan.

Note: 1) DSM capacity savings continue to increase throughout the Planning Period.

New

Conventional

New           

Renewable Retrofit Repow er Retire

2013 SPP AV, HW, SH –

Biomass

2014 SPP/SLR NUG

BR3 – Gas    

BR4 – Gas

2015 Warren SPP/EEP           

SLR NUG/EP&S

CEC 1‐4

YT1, YT2

2016 Brunswick SLR NUG/SPP

2017 SLR TAG/SLR

2018 OFFD/SLR

PP5 – SNCR    

YT3 – SNCR

2019 CC SLR

2020 SLR TAG/SLR

2021 SLR

2022 CT WND   /SLR

2023 WND  /SLR

2024 WND   /SLR

2025 North Anna 3 SLR

2026 SLR

2027 CT SLR

2028 CT SLR

2029 SLR

Approved DSM

Proposed & Future

DSM

Year

Supply‐side Resources

Demand‐side

Resources1
16

CHAPTER 2 – LOAD FORECAST 

2.1 FORECAST METHODS

The Company uses two econometric models with an end‐use orientation to forecast energy sales.  

The first is a customer class level model (“sales model”) and the second is an hourly load system

level model (“system model”).  The models used to produce the Company’s load forecast have been

developed, enhanced, and re‐estimated annually for over 20 years.  There is no change in forecasting

methods used in this 2014 Plan.

The sales model incorporates separate monthly sales equations for residential, commercial,

industrial, public authority, street and traffic lighting, and wholesale customers, as well as other

Load Serving Entities (“LSEs”) in the Dominion Zone (“DOM Zone”), all of which are in the PJM

RTO load.  The monthly sales equations are specified in a manner that produces estimates of heating

load, cooling load, and non‐weather sensitive load.

Variables included in the monthly sales equations are as follows:

 Residential Sales equation: Income, electric prices, unemployment rate, number of

customers, appliance saturations, building permits, weather, billing days, and calendar

month variables to capture seasonal impacts.

 Commercial Sales equation: Virginia Gross State Product (“GSP”), electric prices, natural

gas prices, number of customers, weather, billing days, and calendar month variables to

capture seasonal impacts.

 Industrial Sales equation: Employment in manufacturing, electric prices, weather, billing

days, and calendar month variables to capture seasonal impacts.

 Public Authorities Sales equation: Employment for Public Authority, number of customers,

weather, billing days, and calendar month variables to capture seasonal impacts.

 Street and Traffic Lighting Sales equation: Number of residential customers and calendar

month variables to capture seasonal impacts.

 Wholesale Customers and Other LSEs Sales equations: A measure of non‐weather sensitive

load derived from the residential equation, heating and air‐conditioning appliance stocks,

number of days in the month, weather, and calendar month variables to capture seasonal

and other effects.

The system model utilizes hourly DOM Zone load data and is estimated in two stages.  In the first

stage, the DOM Zone load is modeled as a function of time trend variables and a detailed

specification of weather involving interactions between both current and lagged values of

temperature, humidity, wind speed, sky cover, and precipitation for five weather stations.  The

parameter estimates from the first stage are used to construct two composite weather variables, one

to capture heating load and one to capture cooling load.  In addition to the two weather concepts

derived from the first stage, the second stage equation uses estimates of non‐weather sensitive load

derived from the sales model and residential heating and cooling appliance stocks as explanatory

variables.  The hourly model also uses calendar month variables to capture time of day, day of week,
17

holiday, other seasonal effects and unusual events such as hurricanes.  Separate equations are

estimated for each hour of the day.

Hourly models for wholesale customers and other LSEs within the DOM Zone are also modeled as a

function of the DOM Zone load since they face similar weather and economic activity.  The DOM

LSE load is derived by subtracting the other LSEs from the DOM Zone load.  DOM LSE load and

firm contractual obligations are used as the total load obligation for the purpose of this 2014 Plan.

Forecasts are produced by simulating the model over actual weather data from the past 20 years

along with projected economic conditions.  Sales estimates from the sales model and energy output

estimates from the system model are compared and reconciled appropriately in the development of

the final sales, energy, and peak demand forecast that is utilized in the 2014 Plan.

2.2 HISTORY & FORECAST BY CUSTOMER CLASS & ASSUMPTIONS

The Company is typically a summer peaking system with historical DOM Zone summer peak

growth averaging about 1.3% annually over 1999 ‐ 2013.  The annual average energy growth rate

over the same period is approximately 1.3%.  Historical DOM Zone peak load and annual energy

output along with a 15‐year forecast are shown in Figure 2.2.1 and Figure 2.2.2.  Figure 2.2.1 also

reflects the actual winter peak demand set in January 2014.  DOM LSE peak and energy

requirements are estimated to grow at approximately 1.4% and 1.3% annually throughout the

Planning Period.  Additionally, a 10‐year history and 15‐year forecast of sales and customer count at

the system level, as well as a breakdown of North Carolina and Virginia are provided in Appendices

2A to 2F.  Appendix 2G provides a summary of the summer and winter peaks used in the

development of the 2014 Plan.  Finally, the three‐year historical load and 15‐year projected load for

wholesale customers are provided in Appendix 3L.  

Figure 2.2.1 ‐ DOM Zone Peak Load

10,000

12,000

14,000

16,000

18,000

20,000

22,000

24,000

26,000

1999200020012002200320042005200620072008200920102011201220132014201520162017201820192020202120222023202420252026202720282029

PEAK DEMAND (MW)

SUMMER

PEAK

WINTER

PEAK

HISTORY FORECAST

2014 Actual Winter Peak has

been included.
18

Figure 2.2.2 ‐ DOM Zone Annual Energy

Figure 2.2.3 summarizes the final forecast of energy sales and peak load over the next 15 years.  The

Company’s wholesale and retail customer energy sales are estimated to grow at annual rates of

approximately 1.1% and 1.3%, respectively, over the Planning Period as shown in Figure 2.2.3.  The

difference in these growth rates primarily reflects the growth of the commercial class as a result of

data center additions.  Historical and projected growth rates can diverge for a number of reasons,

including weather and economic conditions.

Figure 2.2.3 ‐ Summary of Energy Sales & Peak Load Forecast

Note: All sales and peak load have not been reduced for the impact of DSM.

50,000

60,000

70,000

80,000

90,000

100,000

110,000

120,000

130,000

1999200020012002200320042005200620072008200920102011201220132014201520162017201820192020202120222023202420252026202720282029

ANNUAL ENERGY (GWh)

HISTORY FORECAST

2015 2029

Compound

Annual Grow th

Rate (%)         

2015‐2029

DOMINION LSE

TOTAL ENERGY SALES (GWh) 84,712                                        101,282 1.3%

Retail                     82,772                     99,011 1.3%

Residential 30,717                                          37,353 1.4%

Commercial 32,224                                          42,146 1.9%

Industrial 8,751                                                 ‐ 8,050 0.6%

Public Authorities 10,780                                          11,103 0.2%

Street and Traffic Lighting 301                                                      360 1.3%

Wholesale (Resale)                        1,940                        2,271 1.1%

SEASONAL PEAK (MW )

Summer 17,670                                          21,331 1.4%

Winter 14,930                                          17,568 1.2%

ENERGY OUTPUT (GWh) 88,174                                        105,467 1.3%

DOMINION ZONE

SEASONAL PEAK (MW )

Summer 20,157                                          24,333 1.4%

Winter 17,284                                          20,338 1.2%

ENERGY OUTPUT (GWh) 100,209                                      120,064 1.3%
19

Figures 2.2.4 and 2.2.5 provide a comparison of DOM Zone summer peak load and energy forecasts

included in the 2013 Plan, 2014 Plan, and PJM’s load forecast for the DOM Zone from its 2013 and

2014 Load Forecast Reports.2

Figure 2.2.4 ‐ DOM Zone Peak Load Comparison

Figure 2.2.5 ‐ DOM Zone Annual Energy Comparison

The economic and demographic assumptions that were used in the Company’s load forecasting

models were supplied by Moody’s Economy.com, prepared in April 2014, and are included as

                                                       

2 See www.pjm.com/documents/~/media/documents/reports/2013‐pjm‐load‐report.ashx; see also

  www.pjm.com/~/media/documents/reports/2014‐load‐forecast‐report.ashx.

10000

12000

14000

16000

18000

20000

22000

24000

26000

28000

1999200020012002200320042005200620072008200920102011201220132014201520162017201820192020202120222023202420252026202720282029

PEAK DEMAND (MW)

2013 IRP

2014 IRP

2014 PJM

2013 PJM

HISTORY FORECAST

50000

60000

70000

80000

90000

100000

110000

120000

130000

140000

1999200020012002200320042005200620072008200920102011201220132014201520162017201820192020202120222023202420252026202720282029

ANNUAL ENERGY (GWh)

2013 IRP

2014 IRP

2014 PJM

2013 PJM

HISTORY FORECAST
20

Appendix 2J.  Figure 2.2.6 summarizes the economic variables used to develop the sales and peak

load forecasts used in the 2014 Plan.

Figure 2.2.6 ‐ Major Assumptions for the Energy Sales & Peak Demand Model  

The forecast for the Virginia economy is a key driver in the Company’s energy sales and load

forecasts.  Although Virginia has been impacted by the recession, the Commonwealth fared well

compared to the nation in terms of job losses.  As of May 2014, the seasonally adjusted

unemployment rate in Virginia approached 5.3%, approximately 1.0% below the national

unemployment rate.   

Housing starts and associated new homes are a significant contributor to electric sales growth in the

Company’s service territory.  The sector saw significant year‐over‐year declines in the construction

of new homes from 2006 through 2010 and began showing improvements in 2012.  As such, Virginia

is expected to show significant improvement in housing starts in 2014 through 2020, which is

reflected as new customers in the load forecast.  Near‐term housings starts are forecast to expand

quickly and then revert back to the long‐run average after 2020, when supply and demand become

balanced.   

Another driver of energy sales and load forecasts in the Company’s service territory is new and

existing data centers.  The Company has seen significant interest in data centers locating in Virginia

because of its proximity to fiber optic networks as well as low‐cost, reliable power sources.  The

Company expects new and existing data center demand to increase to approximately 1,100 MW by

2018.   

2015 2029

Compound Annual

Grow th Rate (%)

2015 ‐ 2029

DEMOGRAPHIC:

Customers (000)

Residential 2,261          2,638 1.11%

Commercial 241                276 0.97%

Population (000) 8,404          9,412 0.81%

ECONOMIC:

Employment (000)

State & Local Government 548                560 0.16%

Manufacturing 231                 ‐ 210 0.69%

Government 712                721 0.09%

Income ($)

Per Capita Real disposable 39,983 47,984 1.31%

Price Index

Consumer Price (1982‐84=100) 242                325 2.12%

VA Gross State Product (GSP) 423                544 1.81%
21

On a long‐term basis, the economic outlook for Virginia is positive.  Over the next 15 years, real per‐

capita income in the state is expected to grow about 1.3% per year on average, while real GSP is

projected to grow more than 1.8% per year on average.  During the same period, the Virginia

population is expected to grow steadily at an average rate of approximately 0.8% per year.

2.3 SUMMER & WINTER PEAK DEMAND & ANNUAL ENERGY

The three‐year actual and 15‐year forecast of summer and winter peak, annual energy, DSM peak

and energy, and system capacity are shown in Appendix 2H.  Additionally, Appendix 2I provides

the reserve margins for a three‐year actual and 15‐year forecast.  

2.4 ECONOMIC DEVELOPMENT RATES

As of August 1, 2014, the Company has four customers in Virginia receiving service under economic

development rates.  The total load associated with these rates is approximately 19 MW as of August

1, 2014.   There are no customers under a self‐generation deferral rate.

On March 30, 2012, the Company filed an application with the NCUC requesting authority to adjust

and increase its rates for retail electric service in North Carolina.  The application included a

proposal for a special Economic Development Rate, Rider EDR.  On December 21, 2012, the NCUC

issued its Order Granting General Rate Increase (Docket No. E‐22, Sub 479) finding, among other

things, that Rider EDR should be approved subject to the condition that the discount shall be

adjusted should the revenues produced by the Rider not cover the marginal costs of providing

service.  
22

CHAPTER 3 – EXISTING & PROPOSED RESOURCES 

3.1 SUPPLY‐SIDE RESOURCES

3.1.1 EXISTING GENERATION

The Company’s existing generating resources are located at multiple sites distributed throughout its

service territory, as shown in Figure 3.1.1.1.  This diverse fleet of 102 generation units includes 4

nuclear, 18 coal, 4 natural gas‐steam, 8 CCs, 41 CTs, 4 biomass, 2 heavy oil, 6 pumped storage, 1

solar, and 14 hydro units with a total summer capacity of approximately 17,677 MW.3  The

Company’s continuing operational goal is to manage this fleet in a manner that provides reliable,

cost‐effective service under varying load conditions.   

Figure 3.1.1.1 ‐ Existing Generation Resources

The Company owns a variety of generation resources that operate using a diverse set of fuels.  The

largest proportion of the Company’s generation resources has operated for 40 to 50 years, followed

by a large number of units that have operated for 20 to 30 years and 30 to 40 years.  Figure 3.1.1.2

shows the demographics of the entire existing generation fleet.

                                                       

3 All references to MW in Chapter 3 refer to summer capacity unless otherwise noted.  Winter capacities for Company‐owned generation

units are listed in Appendix 3A.
23

Figure 3.1.1.2 ‐ Generation Fleet Demographics

Note: Renewable resources Altavista, Hopewell and Southampton, shown in the 20‐30 unit age category, are recent biomass conversions of

existing units.

Figure 3.1.1.3 illustrates that the Company’s existing generation fleet is comprised of a mix of

approximately 17,677 MW of resources with varying operating characteristics and fueling

requirements.  The Company also has contracted 1,747 MW of NUGs, as of January 2014, which

provide firm capacity as well as associated energy and ancillary services to meet the Company’s

load requirements.  An important aspect of the 2014 Plan is the Company’s continued use of diverse

capacity and energy resources to meet its customers’ needs.  

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

<10 10‐20 20‐30 30‐40 40‐50 >50

Renewable

Oil

Pumped Storage

Natural Gas

Nuclear

Coal

UNIT AGE

TOTAL CAPACITY (MW)
24

Figure 3.1.1.3 ‐ 2014 Capacity Resource Mix by Unit Type

 

Due to differences in the operating and fuel costs of various types of units and PJM system

conditions, the Company’s energy mix is not equivalent to its capacity mix.  The Company’s

generation fleet is economically dispatched by PJM within its larger footprint, ensuring that

customers in the Company’s service area receive the benefit from all resources in the PJM power

pool regardless of whether the source of electricity is Company‐owned, contracted, or third‐party

units.  PJM dispatches resources within the DOM Zone from the lowest bid units to the highest bid

units, while maintaining its mandated reliability standards.  Figures 3.1.1.4 and 3.1.1.5 provide the

Company’s 2013 actual capacity and energy mix with percentages.  

                         4,964 24.9%

                         3,349 16.8%

                         5,154 25.9%

                         1,802 9.1%

                         1,833 9.2%

                            575 2.9%

                            743 3.7%

                            942 4.7%

                               63 0.3%

                         1,747 8.8%

                       17,677 88.8%

                       19,424 97.6%

                            473 2.4%

                       19,898 100.0%

Pumped Storage

Oil

Generation Resource Type

Net Summer

Capacity (MW)

Purchases

Renewable

NUG ‐ Coal

NUG ‐ Natural Gas Turbine

NUG ‐ Renewable

NUG Contracted

Company Owned

Percentage

(%)

Coal

Nuclear

Natural Gas

Total

Company Owned and NUG Contracted
25

Figure 3.1.1.4 ‐ 2013 Actual Capacity Mix

Figure 3.1.1.5 ‐ 2013 Actual Energy Mix1

Note: 1) Pumped storage is not shown because it is net negative to the Company’s energy mix.   

Appendices 3A, 3C, 3D, and 3E provide basic unit specifications and operating characteristics of the

Company’s supply‐side resources, both owned and contracted.  Additionally, Appendix 3F provides

a summary of the existing capacity, including NUGs, by fuel class.  Appendices 3G and 3H provide

energy generation by type as well as the system output mix.  Appendix 3B provides a listing of other

generation units including NUGs, behind‐the‐meter generation (“BTMG”), and customer‐owned

generation units.  

3.1.2 EXISTING RENEWABLE RESOURCES  

The Company currently owns and operates 575 MW of renewable resources including Pittsylvania

Power Station (83 MW), one of the largest biomass facilities in the United States.  The Company also

owns and operates four hydro facilities: Gaston Hydro Station (220 MW), Roanoke Rapids Hydro

Station (98 MW), Cushaw Hydro Station (2 MW), and North Anna Hydro Station (1 MW).  The
26

Company completed the conversion of Altavista (51 MW) on July 12, 2013, Hopewell (51 MW) on

October 18, 2013, and Southampton (51 MW) on November 28, 2013 from coal to biomass fuel.  The

Company also completed the first installations of its SPP in 2014.  Further, the Virginia City Hybrid

Energy Center (“VCHEC”) (610 MW) is expected to consume renewable biomass fuel of up to 3% in

2014 and gradually increase that level to 10% by July 2020.

The 2014 Plan continues to include a renewable municipal solid waste NUG facility at Covanta

Fairfax that provided approximately 63 MW of firm capacity in 2013.

Rate Schedule RG  

In response to customer requests and to further promote the development of renewable energy, the

Company filed an application with the SCC on December 20, 2012 to establish a Renewable

Generation Pilot Program (“RG Pilot Program”) whereby large non‐residential customers in Virginia

would have the ability to meet a portion of their energy requirements with renewable energy.  The

SCC approved the RG Pilot Program in December 2013.  The Program is only available as a

voluntary companion rate to non‐residential customers (1) with demands greater than 500 kilowatt

(“kW”) that are served under Rate Schedule GS‐3 or GS‐4; and (2) with individual account purchases

between 1,000,000 kWh and 24,000,000 kWh annually.  The purchase price under Rate Schedule RG

represents energy and its associated renewable attributes only, with each participating customer

continuing to purchase capacity and the remaining portion of its energy needs under Rate Schedule

GS‐3 or GS‐4.  Schedule RG is available to eligible customers for an enrollment period of three years

or until the RG Pilot Program cap of 240,000,000 kWh or 100 customers is met.  Under the Program,

the renewable energy resource may be located outside of the Company’s service territory, but it

must be within the geographic scope of the PJM wholesale market.  More information regarding the

RG Pilot Program can be found on the SCC website under Case No. PUE‐2012‐00142.

3.1.3 CHANGES TO EXISTING GENERATION

The Company is fully committed to meeting its customersʹ energy needs in a manner consistent with

a clean environment and supports the establishment of a comprehensive national energy and

environmental policy that balances the country’s needs for reliable and affordable energy with

reasonable minimization of environmental impacts.  The Company has a mixed portfolio of

generating units, including low‐emissions nuclear and hydro, that has a lower carbon intensity

compared to the generation fleet of most other energy companies in the country.   

The conversion of Bremo Units 3 (71 MW) and 4 (156 MW) from coal to natural gas was completed

on May 1, 2014 and June 23, 2014, respectively.  

Uprates and Derates

Efficiency, generation output, and environmental characteristics of plants are reviewed as part of the

Company’s normal course of business.  Many of the uprates and derates discussed in this section

occur during routine maintenance cycles or are associated with standard refurbishment.  However,

several plant ratings have been and will continue to be adjusted in accordance with PJM market

rules and environmental regulations.
27

The Company continues to evaluate opportunities for existing unit uprates as a cost‐effective means

of increasing generating capacity and improving system reliability.  Since 2011, the Company’s

investment in its existing generation fleet has yielded net capacity uprates of 97 MW.  Appendix 3I

provides a list of historical and planned uprates and derates to the Company’s existing generation

fleet.  

EPA Regulations

There are a significant number of effective and anticipated EPA regulations that will affect certain

units in the Company’s current fleet of generation resources.  As shown in Figure 3.1.3.1, these

regulations are designed to regulate air, solid waste, and water constituents.  

Figure 3.1.3.1 ‐ EPA Regulations as of June 30, 2014

Key: Constituent: Hg: Mercury; HAPS: Hazardous Air Pollutants; SO2: Sulfur Dioxide; NOx: Nitrogen Oxide; CO2: Carbon Dioxide; GHG:

Greenhouse Gas; Water 316b: Clean Water Act § 316(b) Cooling Water Intake Structures;

Regulation: MATS: Mercury & Air Toxics Standards; CAIR: Clean Air Interstate Rule; CAP: President’s Climate Action Plan; CSAPR: Cross‐

State Air Pollution Rule; GHG PSD: Greenhouse Gas Prevention of Significant Deterioration; SO2 NAAQS: Sulfur Dioxide National Ambient

Air Quality Standards; Ozone Std Rev PPB: Parts per Billion; EGU NSPS: Electric Generating Units New Source Performance Standard; CCB:

Coal Combustion Byproducts.

*EPA may replace both the CAIR and CSAPR rules.

Compliance with effective and anticipated environmental regulations is an important part of the

Company’s planning process and a key corporate focus.  The majority of the Company’s coal

generators are equipped with SO2 and NOx controls; however, the remaining small coal‐fired units

are without sufficient emission compliance controls to comply with soon to be effective and

Key Regulation Final/Expected

Final Rule

CAIR* ‐ Current & 2015 June‐05

CSAPR* July‐11

SO2 NAAQS June‐10

Ozone Std Rev (75 ppb) May 2012

Ozone Standard Rev (60‐70 ppb) October‐15

CAIR* ‐ Current & 2015 June‐05

CSAPR* July‐11

GHG PSD Rule May‐10

EGU NSPS (New) Jan 2015

EGU NSPS (Existing) June 2015

EGU NSPS (Modified &

Reconstructed) Jan 2015

Federal CO2 Program Uncertain

Constituent AIR

Hg/HAPS Mercury & Air Toxics Standards

(MATS)

SO2

NOx

CO2

WASTE

ASH CCBʹs December‐14

December‐11

WATER

Water

316(b)

316b Impingement &           

Entrainment May‐14

Water

Effluent

Effluent Discharges September‐15
28

anticipated regulatory requirements.  The Company’s coal‐fired units at the Chesterfield, Mt. Storm,

Clover, Mecklenburg and VCHEC facilities have flue gas desulfurization environmental controls to

control SO2 emissions.  The Company’s Chesterfield Units 4, 5 and 6, Mt. Storm, Clover, Chesapeake

Units 3 and 4, and VCHEC coal‐fired generation units also have selective catalytic reduction (“SCR”)

or SNCR technology to control NOx emissions.  

As part of its IRP process, the Company monitors compliance options with respect to the Company’s

coal and oil‐fired units and potentially uneconomic capital investments with soon to be effective and

anticipated environmental regulations.  In 2012, the Company conducted a comprehensive review

that analyzed the costs to retrofit units with new environmental control equipment, repower units to

natural gas, convert units to burn biomass as a fuel source, or retire the units from service.  This

analysis sought to determine the optimal solution, while considering costs and the goal of

maintaining system reliability.  Since then, the EPA has finalized the 316(b) rules regarding cooling

water intake structures.  Until the states implement this requirement, it is not known whether

controls beyond those contemplated in this Plan could be required.

The analysis resulted in the Company’s decision to retire Chesapeake and Yorktown Units 1 and 2,

along with the decision to install SNCR controls on Yorktown Unit 3 and Possum Point Unit 5,

which are currently expected to be online in 2018.

Extension of Nuclear Licensing

The Company is currently evaluating 20‐year license extensions, from 60 to 80 years, for its existing

nuclear units, with Surry Power Station the first to reach its license expiration.  The Company’s plan

is to gather technical data to assess feasibility, determine the necessary upgrades to operate an

additional 20 years and implement upgrades consistent with risk benefits.   

3.1.4 GENERATION RETIREMENTS/BLACKSTART

Retirements

Based on the effective and anticipated environmental regulations along with current market

conditions, the 2014 Plan includes the following impacts to the Company’s existing generating

resources in terms of retirements.  There are several units in the 2014 Plan that will be retired.  These

units include the Chesapeake Energy Center Units 1 (111 MW), 2 (111 MW), 3 (149 MW), and 4 (207

MW) that will retire by 2015 and Yorktown Units 1 (159 MW) and 2 (164 MW) that will retire in

2016.  Appendix 3J lists the planned retirements included in the 2014 Plan.

Blackstart

Blackstart generators are generating units that are able to start without an outside electrical supply

or are able to remain operating at reduced levels when automatically disconnected from the grid.  

The North American Electric Reliability Corporation (“NERC”) Reliability Standard EOP‐005

requires the RTO to have a plan that allows for restoring its system following a complete shutdown

(i.e., blackout).  As the RTO, PJM performs an analysis to verify all requirements are met and

coordinates this analysis with the Company in its role as the Transmission Owner.  The Company

and other PJM members recently worked with PJM to implement a new, long‐term, RTO‐wide

strategy for procuring blackstart resources.  This strategy ensures a resilient and robust ability to

meet blackstart and restoration requirements.  It is described in detail in Section 10 of PJM Manual
29

14D – Generator Operational Requirements.  PJM will issue an RTO‐wide Request for Proposals

(“RFP”) for blackstart generation every five years, which will be open to all existing and potential

new blackstart units on a voluntary basis.  Resources are selected based upon the individual needs

of each transmission zone.  The first five‐year selection process was initiated in 2014 and resulted in

blackstart solutions totaling 286 MW in the DOM Zone.  These solutions will be effective as of April

1, 2015 (135 MW) and April 1, 2016 (151 MW).  Blackstart solutions from subsequent five‐year

selection processes will be effective on April 1, beginning in 2020 and continuing every five years

thereafter.  For incremental changes in resource needs or availability that may arise between the

five‐year solicitations, the strategy includes an incremental RFP process.  

3.1.5 GENERATION UNDER CONSTRUCTION

To meet expected load growth, the Company filed for a certificate of public convenience and

necessity (“CPCN”) with the SCC to construct and operate Warren County Power Station, a 1,337

MW natural gas‐powered electric generation facility located in Warren County, Virginia.  On

February 2, 2012, the SCC granted the CPCN in Case No. PUE‐2011‐00042, and on February 27, 2012,

the Company officially began construction of the station.  The station is targeted for commercial

operation by 2015.

Pursuant to Chapter 771 of the 2011 Virginia Acts of Assembly (House Bill 1686) the Company

obtained a CPCN from the SCC in November 2012 (Case No. PUE‐2011‐00117) for the SPP to install

up to 24 MW AC (30 MW DC) of solar PV distributed generation (“DG”) by 2015 in its Virginia

service territory.  Additionally, the SCC ruling included a cost cap for the Program of $80 million

including; but not limited to, capital, financing and operation and maintenance costs.  Installations

will be placed on existing structures (e.g., customers’ rooftops) and previously developed properties

(e.g., ground‐mounted solar arrays) to assess the potential impacts and benefits on its distribution

system.   

Two large rooftop installations were recently dedicated, the first at Canon Environmental

Technologies on April 22, for a 500 kW AC solar facility and the second at Old Dominion University

on July 8 for a 125 kW AC solar facility.  The Company also announced a 736 kW AC rooftop

installation at Prologis‐Concorde Executive Center in Sterling, which will be completed by the end

of 2014.  Additional projects are underway in various stages of development, and based on the

experience of Phase 1 of the Solar Partnership Program, the financial constraint of $80 million will

allow for the installation of approximately 13 MW of solar DG, which is below the approved CPCN

level of 24 MW.   

On November 2, 2012, the Company filed an application for a CPCN with the SCC to construct and

operate Brunswick County Power Station, a 1,375 MW natural gas powered electric generation

facility located in Brunswick County, Virginia, and associated facilities.  On August 2, 2013, the SCC

issued an order granting the CPCN, in Case No. PUE‐2012‐00128.  The station is targeted for

commercial operation by May 2016.

Figure 3.1.5.1 and Appendix 3K provide a summary of the generation under construction along with

the forecasted in‐service date and summer/winter capacity.
30

Figure 3.1.5.1 ‐ Generation under Construction

Note: 1) Commercial Operation Date.

3.1.6 NON‐UTILITY GENERATION

A portion of the Company’s load and energy requirements is supplemented with contracted NUG

units and market purchases.  The Company has existing contracts with NUGs for capacity of 1,747

MW, of which 63 MW are from renewable sources.  These NUGs are considered firm capacity

resources and are included in the 2014 Plan.   

Each of the NUG facilities listed as a capacity resource in Appendix 3B is under contract to supply

capacity and energy to the Company.  NUG units are obligated to provide firm capacity and energy

at the contracted terms during the life of the contract.  The firm capacity from NUGs is included as a

resource in meeting the reserve requirements.  The remaining NUG contracts expire at different

times during the Planning Period, with the last contract expiring in 2021.  

For modeling purposes, the Company assumed that its NUG capacity will be available as a firm

resource in accordance with current contractual terms.  These NUG units also provide energy to the

Company according to their contractual arrangements.  At the expiration of these NUG contracts,

these units will no longer be modeled as a firm capacity resource.  The Company assumed that

NUGs or any other non‐Company owned resource without a contract with the Company are

available to the Company at market prices; therefore, the Company’s optimization model may select

these resources in lieu of other Company‐owned/sponsored supply‐ or demand‐side resources

should the market economics dictate.  Although this is a reasonable planning assumption, parties

may elect to enter into future bilateral contracts on mutually agreeable terms.  For potential bilateral

contracts not known at this time, the market price is the best proxy to use for planning purposes.  

Additionally, the Company is currently estimating the development of a number of potential solar

qualifying facilities.  All the plans include a total of 200 MW (nameplate) of solar, by 2016, which

includes 94 MW of power purchase agreements (“PPAs”) that have been signed as of July 2014.  The

Company is continually evaluating NUG opportunities as they arise to determine if they are in the

best interest of customers.

3.1.7 WHOLESALE & PURCHASED POWER

Purchased Power

Except for the NUG contracts discussed in Section 3.1.6, the Company does not have any bilateral

contractual obligations with wholesale power suppliers or power marketers.  As a member of PJM,

the Company has the option to self‐schedule or buy capacity through the Reliability Pricing Model

(“RPM”) auction (“RPM auction”) process.  The Company has procured its capacity obligation from

the RPM market through May 31, 2018.  However, other utilities’ decisions to meet proposed EPA

Summer Winter

2015 Warren County Power Station Warren County, VA Natural Gas Intermediate/ Baseload 1,337 1,437

2015 Solar Partnership Program VA Solar Intermittent 8 8

2016 Solar Partnership Program VA Solar Intermittent 5 5

2016 Brunswick County Power Station Brunswick, VA Natural Gas Intermediate/ Baseload 1,375 1,509

Capacity (Net MW) Location Primary Fuel Unit TypeForecasted

COD1 Unit Name
31

GHG targets in neighboring states could adversely affect future price and/or availability of purchase

power.  In Plan A: Base Plan, the Company annually makes net purchases on average of 319 MW of

capacity and 8% of its total energy over the Planning Period from the PJM market.  In Plan B: Fuel

Diversity Plan, the Company annually makes net purchases on average of 309 MW of capacity and

7% of its total energy over the Planning Period from the PJM market.   

Wholesale Power Sales

The Company currently provides full requirements wholesale power sales to three entities, which

are included in the Company’s load forecast.  These entities are Craig Botetourt Electric Cooperative;

the Virginia Municipal Electric Association No.1; and the Town of Windsor in North Carolina.  

Additionally, the Company has partial requirements contracts to supply the supplemental power

needs of the North Carolina Electric Membership Cooperative.  Appendix 3L provides a listing of

wholesale power sales contracts with parties whom the Company has either committed, or expects

to sell power during the Planning Period.  

Behind‐the‐Meter Generation

BTMG occurs on the customer’s side of the meter.  The Company purchases all output from the

customer and services all of the customer’s capacity and energy requirements.  The unit descriptions

are provided in Appendix 3B.

3.1.8 REQUEST FOR PROPOSAL

At this time, the Company does not have any RFPs outstanding to procure supply‐side resources.  

3.2 DEMAND‐SIDE RESOURCES  

The Commonwealth of Virginia has an energy reduction target for 2022 of reducing the

consumption of electric energy by retail customers by an amount equal to 10% of the amount of

electric energy consumed by retail customers in 2006, as applied to the Company’s 2006

jurisdictional retail sales.  The Company has expressed its commitment to helping Virginia reach this

goal.  Related to and consistent with the goal, DSM Programs are an important part of the

Company’s portfolio available to meet customers’ growing need for electricity along with supply‐

side resources.  

The Company generally defines DSM as all activities or programs undertaken to influence the

amount and timing of electricity use.  Demand‐side resources encourage the more efficient use of

existing resources and delay or eliminate the need for new supply‐side infrastructure.  The

Company’s DSM tariffs provide customers with price signals to curtail load at times when system

load or marginal cost is high.  Additionally, the Company’s DSM programs are designed to provide

customers the opportunity to manage their electricity usage.  In the 2014 Plan, five categories of

DSM programs are addressed: i) those approved by the NCUC and SCC; ii) those proposed by the

Company in Docket Nos. E‐22, Subs 507, 508 and 509, for which the Company is requesting

approval of in North Carolina; iii) those proposed by the Company in Case No. PUE‐2014‐00071, for

which the Company is requesting approval of in Virginia; iv) those considered future programs that

are not currently filed with either Commission for approval, but have been evaluated and are

potential DSM resources; and v) those programs currently rejected from further consideration at this
32

time.  System‐wide DSM programs were designed and evaluated using a system‐level analysis.  For

reference purposes, Figure 3.2.1 provides a graphical representation of the approved, proposed,

future, and rejected programs described in Chapters 3 and 5.

Figure 3.2.1 ‐ DSM Tariffs & Programs

 

Note: * Alternative Redesigned Program under consideration.

Voltage Conservation Program Status (VA/NC)

Standby Generator Tariff

Curtailable Service Tariff

Program Status (VA/NC)

Air Conditioner Cycling Program

Residential Low Income Program

Residential Lighting Program Completed/Completed

Commercial Lighting Program

Commercial HVAC Upgrade

Non‐Residential Distributed Generation Program Approved/Rejected

Non‐Residential Energy Audit Program

Non‐Residential Duct Testing & Sealing Program

Residential Bundle Program

Residential Home Energy Check‐Up Program

Residential Duct Sealing Program

Residential Heat Pump Tune Up Program

Residential Heat Pump Upgrade Program

Non‐Residential Window Film Program

Non‐Residential Lighting Systems & Controls Program

Non‐Residential Heating and Cooling Efficiency Program

Income & Age Qualifying Home Improvement Program

Residential Appliance Recycling Program

Qualifying Small Business Improvement Program

Voltage Conservation Program

Non Residential Custom Incentive

Non‐Residential HVAC Tune‐Up Program

Energy Management System Program

ENERGY STAR® New Homes Program

Geo‐Thermal Heat Pump Program

Home Energy Comparison Program

Home Performance with ENERGY STAR® Program

In‐Home Energy Display Program

Premium Efficiency Motors Program

Programmable Thermostat Program

Residential Refrigerator Turn‐In Program*

Residential Solar Water Heating Program

Residential Water Heater Cycling Program

Residential Comprehensive Energy Audit Program

Residential Radiant Barrier Program

Residential Lighting (Phase II) Program

Non‐Residential Refrigeration Program

Cool Roof Program

Non‐Residential Data Centers Program

Non‐Residential Re‐commissioning

Non‐Residential Curtailable Service Program

Rejected and Currently Not

Under Consideration

Approved/Proposed

Future/Future

Approved/Approved

Approved/Approved

Closed/Pending Closure

Approved/Approved

Approved/Approved

Proposed/Future
33

3.2.1 DSM PROGRAM DEFINITIONS

For purposes of its DSM programs in North Carolina, the Company applies the definitions set forth

in NCGS § 62‐133.8 (a) (2) and (4) for DSM and energy efficiency measures as defined below.  

 Demand‐Side Management: Activities, programs, or initiatives undertaken by an electric

power supplier or its customers to shift the timing of electricity use from peak to non‐peak

demand periods.  DSM includes, but is not limited to, load management, electric system

equipment and operating controls, direct load control, and interruptible load.

 Energy Efficiency Measure: Equipment, physical, or program change implemented after

January 1, 2007, that results in less energy used to perform the same function.  “Energy

efficiency measure” includes, but is not limited to, energy produced from a combined heat

and power system that uses nonrenewable energy resources.  “Energy efficiency measure”

does not include DSM.

For purposes of its DSM programs in Virginia, the Company applies the Virginia definitions set

forth in Va. Code § 56‐576 as provided below.  

 Demand Response – Measures aimed at shifting time of use of electricity from peak‐use

periods to times of lower demand by inducing retail customers to curtail electricity usage

during periods of congestion and higher prices in the electrical grid.  

 Energy Efficiency Program – A program that reduces the total amount of electricity that is

required for the same process or activity implemented after the expiration of capped rates.  

Energy efficiency programs include equipment, physical, or program change designed to

produce measured and verified reductions in the amount of electricity required to perform

the same function and produce the same or a similar outcome.  Energy efficiency programs

may include, but are not limited to, i) programs that result in improvements in lighting

design, heating, ventilation, and air conditioning systems, appliances, building envelopes,

and industrial and commercial processes; ii) measures, such as, but not limited to, the

installation of advanced meters, implemented or installed by utilities, that reduce fuel use or

losses of electricity and otherwise improve internal operating efficiency in generation,

transmission, and distribution systems; and (iii) customer engagement programs that result

in measurable and verifiable energy savings that lead to efficient use patterns and practices.  

Energy efficiency programs include demand response, combined heat and power and waste

heat recovery, curtailment, or other programs that are designed to reduce electricity

consumption, so long as they reduce the total amount of electricity that is required for the

same process or activity.  Utilities are authorized to install and operate such advanced

metering technology and equipment on a customerʹs premises; however, nothing in Chapter

23 of Title 56 establishes a requirement that an energy efficiency program be implemented

on a customer’s premises and be connected to a customer’s wiring on the customer’s side of

the inter‐connection without the customer’s expressed consent.  

 Peak‐Shaving – Measures aimed solely at shifting time of use of electricity from peak‐use

periods to times of lower demand by inducing retail customers to curtail electricity usage

during periods of congestion and higher prices in the electrical grid.
34

3.2.2 CURRENT DSM TARIFFS

The Company modeled existing DSM pricing tariffs over the Study Period, based on historical data

from the Company’s Customer Information System.  These projections were modeled with

diminishing returns assuming new DSM programs will offer more cost‐effective choices in the

future.  No active DSM pricing tariffs have been discontinued since the Company’s 2013 Plan.

STANDBY GENERATION & CURTAILABLE SERVICE TARIFFS

Program Type:    Energy Efficiency ‐ Demand Response

Target Class:     Commercial & Industrial  

Participants: 5 customers on Standby Generation in Virginia

1 customer on Curtailable Service in Virginia

Capacity Available: See Figure 3.2.2.1

The Company currently offers two DSM pricing tariffs including Standby Generation (“SG”) rate

schedules in Virginia and a Curtailable Service (“CS”) rate schedule in Virginia.  These tariffs

provide incentive payments for dispatchable load reductions that can be called on by the Company

when capacity is needed.  

The SG rate schedules provide a direct means of implementing load reduction during peak periods

by transferring load normally served by the Company to a customer’s standby generator.  The

customer receives a bill credit based on a contracted capacity level or average capacity generated

during a billing month when SG is requested.  The CS rate schedule requires the participating

customer to reduce its electric demand to a contracted firm demand level when requested by the

Company in return for a rate reduction credit.  Failure to comply with the Company’s request to

reduce demand to the firm level results in a penalty, based on a demand charge that is

approximately four times the per kilowatt (“kW”) credit, on the customer’s bill.  To receive the rate

credit, customers commit to participate in the curtailment upon at least two hours’ notice.  The tariff

is primarily aimed at customers with the operational flexibility to store inventory or to curtail or

reschedule production.  

During a load reduction event, a customer receiving service under the SG rate schedule is required

to transfer a contracted level of load to its dedicated on‐site backup generator, while the customer

receiving service under the CS rate schedule is required to reduce load to a contracted firm demand

level.  At the Company’s request, the customer may be asked to reduce load on the Company’s

system 19 times during the summer (May 16 – September 30) and 13 times during the winter

(December 1 – March 31).  Additional jurisdictional rate schedule information is available on the

Company’s website at www.dom.com.  
35

Figure 3.2.2.1 ‐ Estimated Load Response Data  

3.2.3 CURRENT & COMPLETED DSM PILOTS & DEMONSTRATIONS

Pilots

The Commission approved nine pilot DSM programs in Case No. PUE‐2007‐00089.  Of the nine

pilots, all have concluded except the Distributed Generation Pilot, which is scheduled to end in

December 2014.  The Company has received SCC approval for implementation of additional pilots

and they are described below:

Dynamic Pricing Tariffs Pilot

State:     Virginia

Target Class:   Residential and Non‐Residential

Pilot Type:    Peak‐Shaving

Pilot Duration: Enrollment closes on November 30, 2014

Pilot is currently scheduled to conclude January 31, 2016.

Description: 

On September 30, 2010, the Company filed an application with the SCC (Case No.  

PUE‐2010‐00135) proposing to offer three experimental and voluntary dynamic pricing tariffs to

prepare for a potential system‐wide offering in the future.  The filing was in response to the SCC’s

directive to the Company to establish a pilot program under which eligible customers volunteering

to participate would be provided the ability to purchase electricity from the Company at dynamic

rates.  On March 22, 2013, the Company filed a Petition to Extend, Expand, and Modify the Pilot,

which was approved on July 12, 2013.  The Pilot is scheduled to end on January 31, 2016.

A dynamic pricing schedule allows the Company to apply different prices as system production

costs change.  The basic premise is that if customers are willing to modify behavior and use less

electricity during high price periods, they will have the opportunity to save money, and the

Company in turn will be able to reduce the amount of energy it would otherwise have to generate or

purchase during peak periods.  

Specifically, the Pilot is limited to 3,000 participants consisting of up to 2,000 residential customers

taking service under experimental dynamic pricing tariff DP‐R and 1,000 commercial/general

customers taking service under dynamic pricing tariffs DP‐1 and DP‐2.  Participation in the pilot

requires either an Advanced Metering Infrastructure (“AMI”) meter or an existing Interval Data

Recorder (“IDR”) meter at the customer location.  The meter records energy usage every 30 minutes,

which enables the Company to offer pricing that varies based on the time of day.  In addition, the

pricing varies based on the season, the classification for the day, and the customer’s demand.  

Number of

Events

Estimated MW

Reduction

Number of

Events

Estimated

MW

Standby Generation 13 3 1 2

Curtailable Service 4 3 4 2

Tariff

Summer 2013 Winter 2013
36

Therefore, the AMI or IDR meter coupled with the dynamic pricing schedules allows customers to

manage their energy costs based on the time of day.

Additional information regarding the Pilot is available at http://www.dom.com/smartprice.   

Status:

The Dynamic Pricing Pilot program was approved by the SCC’s Order Establishing Pilot Program

issued on April 8, 2011.  The Company launched this Pilot program on July 1, 2011.  As of July, 2014,

there were 642 customers taking service under the residential DP‐R tariff; 34 customers taking

service under the commercial DP‐1 tariff; and 75 customers taking service under the commercial DP‐

2 tariff.

Electric Vehicle (“EV”) Pilot

State:     Virginia

Target Class:   Residential

Pilot Type:    Peak‐Shaving

Pilot Duration: Enrollment began October 3, 2011

     Enrollment concludes December 1, 2015

Pilot concludes November 30, 2016

Description:  

On January 31, 2011, the Company filed an application with the SCC (Case No.  

PUE‐2011‐00014) proposing a pilot program to offer experimental and voluntary EV rate options to

encourage residential customers who purchase or lease EVs to charge them during off‐peak periods.  

The Pilot program provides two rate options.  One rate option, a “Whole House” rate, allows

customers to apply the time‐of‐use rate to their entire service, including their premises and vehicle.  

The other rate option, an “EV Only” rate, allows customers to remain on their existing standard rate

for their premises and subscribe to the time‐of‐use rate only for their vehicle.  The program is open

to up to 1,500 residential customers, with up to 750 in each of the two experimental rates.  

Additional information regarding the Company’s EV Pilot Program is available in the Company’s

application and in the SCC’s Order Granting Approval.

Status:

The SCC approved the Pilot in July 2011.  In November 2013, the SCC approved the extension of the

Pilot for two additional years.  The Company began the Pilot enrollment on October 3, 2011, and will

conclude the Pilot by November 30, 2016.  As of July 2014, 275 customers were enrolled on the

whole‐house EV rate while 81 customers were enrolled on the EV‐only rate.  

Additional information regarding the Pilot is available at

https://www.dom.com/about/environment/electric‐vehicles.jsp.
37

AMI Upgrades

State:     Virginia

Target Class:   All‐Classes

Type:     Energy Efficiency

Duration:    Ongoing

Description:

The Company continues to upgrade meters to Advanced Metering Infrastructure, also referred to as

smart meters.   

Status:

To date, the Company has installed over 260,000 smart meters in areas throughout Virginia.  The

AMI meter upgrades are part of an on‐going project that will help the Company further evaluate the

effectiveness of AMI meters in achieving voltage conservation, remotely turning off and on electric

service, power outage, restoration detection and reporting, remote daily meter readings and offering

dynamic rates.  Additional information about smart meter technology is available at

www.dom.com/smartmeter and in Section 5.4.

3.2.4 CURRENT CONSUMER EDUCATION PROGRAMS

The Company’s consumer education initiatives include providing demand and energy usage

information, educational opportunities, and online customer support options to assist customers in

managing their energy consumption.  The Company’s website has a section dedicated to energy

conservation.  This section contains helpful information for both residential and non‐residential

customers, including information about the Company’s DSM programs.  Through consumer

education, the Company is working to encourage the adoption of energy‐efficient technologies in

residences and businesses in North Carolina and Virginia.  Examples of how the Company increases

customer awareness include:  

Customer Connection Newsletter

State: North Carolina and Virginia  

The Customer Connection newsletter is sent to customers as an insert to their monthly power bill six

times per year.  It contains news on topics such as DSM programs, how to save money or manage

electric bills, helping the environment, service issues, and safety recommendations, in addition to

many other relevant subjects.  For those who receive their electric bills by e‐mail, the newsletter is

available online.  Articles from the most recent North Carolina Customer Connection Newsletter are

located on the Company’s website at: http://www.dom.com/dominion‐north‐carolina‐

power/customer‐service/your‐bill/customer‐connection.jsp.  Articles from the most recent Virginia

Customer Connection Newsletter are located on the Company’s website at

http://www.dom.com/dominion‐virginia‐power/customer‐service/your‐bill/customer‐

connection.jsp.   
38

Twitter ® and Facebook

State: North Carolina and Virginia  

The Company uses the social media channels of Twitter® and Facebook to provide real‐time

updates on energy‐related topics, promote Company messages, and provide two‐way

communication with customers.

The Twitter® account is available online at: www.twitter.com/DomVAPower.  

The Facebook account is available online at: http://www.facebook.com/dominionvirginiapower.

“Every Day”

State: Virginia

The Company advertises the “Every Day” campaign, which is a series of commercial and print ads

that address various energy issues.  These advertisements, along with the Company’s other

advertisements, are available at: http://www.dom.com/about/advertising/index.jsp.

News Releases

State: North Carolina and Virginia  

The Company prepares news releases and reports on the latest developments regarding its DSM

initiatives and provides updates on Company offerings and recommendations for saving energy as

new information becomes available.  Current and archived news releases can be viewed at:

http://www.dom.com/news/index.jsp.

Online Energy Calculators

State: North Carolina and Virginia  

Home and business energy calculators are provided on the Company’s website to estimate electrical

usage for homes and business facilities.  The calculators can help customers understand specific

energy use by location and discover new means to reduce usage and save money.  An appliance

energy usage calculator and holiday lighting calculator are also available to customers.  The energy

calculators are available at:  

http://www.dom.com/about/conservation/energy‐calculators‐help‐find‐energy‐savings.jsp.

Community Outreach ‐ Trade Shows, Exhibits and Speaking Engagements

State: North Carolina and Virginia  

The Company conducts outreach seminars and speaking engagements in order to share relevant

energy conservation program information to both internal and external audiences.  The Company

also participates in various trade shows and exhibits at energy‐related events to educate customers

on the Company’s DSM programs and inform customers and communities about the importance of

implementing energy‐saving measures in homes and businesses.  Additionally, Company

representatives positively impact the communities served through presentations to elementary,

middle, and high school students about programs, using energy wisely and environmental

stewardship.  

The Company also provides helpful materials for students to share with their families.  For example,

Project Plant It! is an innovative community program available to elementary school students in

North Carolina, Virginia, Connecticut, Maryland, Pennsylvania, and New York that teaches students
39

about the importance of trees and how to protect the environment.  This program includes

interactive classroom lessons and provides students with tree seedlings to plant at home or at

school.  The Company offers Project Plant It! free of charge throughout the Company’s service

territory and has distributed 257,288 seedlings through the program since 2007.  

DSM Program Communications

The Company uses numerous methods to make customers aware of its DSM Programs.  These

methods include direct mail, communications through contractor networks, e‐mail, radio ads, social

media, and outreach events.  

Energy Conservation Blog

State: North Carolina and Virginia

The Company discontinued its Energy Conservation Blog but continues to communicate with

customers through its website, direct mail, email, and social media channels.  The Company also has

tips for saving energy on its website.

3.2.5 APPROVED DSM PROGRAMS

In North Carolina, in Docket Nos. E‐22, Subs 495, 496, 497, 498, 499, and 500, the Company filed for

NCUC approval of six new DSM Programs.  These Programs are the same Phase II DSM Programs

that were approved in Virginia in Case No. PUE‐2011‐00093, with the exception of the CDG

Program, which had been denied approval in North Carolina in 2011.  Additionally, in Docket Nos.

E‐22, Sub 467 and 469, respectively, the Company filed for NCUC approval to reinitiate the

Commercial HVAC Upgrade and Commercial Lighting Programs on a North Carolina‐only basis.

On December 16, 2013, the NCUC approved the six new DSM Programs as well as the two NC‐only

Programs.   

On August 30, 2013, the Company filed for SCC approval in Case No. PUE‐2013‐00072 for three

Non‐Residential Programs and modifications to the approved Non‐Residential Energy Audit

Program.  The three proposed Programs were the: i) Non‐Residential Heating and Cooling

Efficiency Program, ii) Non‐Residential Lighting Systems and Controls Program, and iii) the Non‐

Residential Window Film Program.  On April 29, 2014, the SCC approved the three Programs and

the modifications to the Non‐Residential Energy Audit Program.  

Appendix 3M provides program descriptions for the currently approved DSM Programs.  Included

in the descriptions are the branded names used for customer communications and marketing plans

that the Company is employing and plans to achieve each Program’s penetration goals.  Appendices

3N, 3O, 3P and 3Q provide the system‐level non‐coincidental peak savings, coincidental peak

savings, energy savings, and penetrations for each approved Program.

For the Air Conditioner Cycling and Distributed Generation Programs, each has utilization

parameters such as number of implementation calls per season or year, advanced notice required to

implement the load reduction, hours per initiation, and total hours of use per season or year.  The

rate structures of the Programs essentially pay for the use parameters and are considered fixed costs,

which do not affect individual Program implementation calls.  As such, the Company targets full

utilization of the Programs to the extent that there are opportunities to reduce demand during peak
40

load situations or during periods when activation would otherwise be cost‐effective and not unduly

burdensome to participating customers.

While the Company targets full utilization of the Air Conditioner Cycling Program, it is important to

consider the participating customers’ comfort and overall satisfaction with the Program as well.  The

Company recognizes the value of the Air Conditioner Cycling Program and continues to monitor

customer retention with respect to program activation.  

Over the past few years, the Company has refined its approach to activation of the programs.  Our

experience indicates that it is important to use a combination of factors to determine when a

program should be activated.  These factors include load forecasts, activation costs, system

conditions, and PJM LMPs of energy.  By including consideration of LMPs in the decision‐making

process relative to program activation costs, the cost of fuel is implicitly accounted for but is not

treated as the sole determinant for dispatching a program.

The Company assumes there is a relationship between the number of hours the Program is

dispatched and the number of hours needed to reduce load during critical peak periods.  It is

assumed that there is a relationship between the incentive amount and the number of hours a

customer is controlled.  As the number of control hours increases, the incentive amount would also

have to increase in order to maintain the same amount of customers, potentially rendering the

Program not cost‐effective.  The Company continues to make every effort to balance the need to

achieve peak load reduction against program cost and customer experience.

3.2.6 PROPOSED DSM PROGRAMS

On June 30, 2014, the Company filed in North Carolina for approval of the three Programs approved

in Virginia in Case No. PUE‐2013‐00072.  The Program Applications were filed in Docket No. E‐22,

Subs 507, 508 and 509.   

As part of the Company’s request for approval of the Non‐Residential Heating and Cooling

Efficiency Program and Non‐Residential Lighting Systems and Controls Program in North Carolina,

the Company filed to close the Commercial Lighting and Commercial HVAC Upgrade Programs in

North Carolina to new participants on September 30, 2014.  On August 13, 2014, the NCUC

approved the Company’s request to close those programs (Docket No. E‐22, Subs 467, 469).  The

Company has until December 31, 2014 to process pending applications.  Additionally, the Company

has filed to amend the Low Income Program to a North Carolina‐only Program for 2015, due to

closure of that Program in Virginia as of December 31, 2014.  The request is pending before the

NCUC.

On August 29, 2014, the Company filed for SCC approval of three new programs including Income

and Age Qualifying Home Improvement; Residential Appliance Recycling; and Qualifying Small

Business Improvement in Case No. PUE‐2014‐00071.  A Commission ruling on the proposal is not

expected until April 2015.  

Appendices 3R, 3S, 3T and 3U provide the system‐level non‐coincidental peak savings, coincidental

peak savings, energy savings, and penetrations for each of the Virginia Proposed Programs.
41

3.2.7 EVALUATION, MEASUREMENT & VERIFICATION

The Company has implemented EM&V plans to quantify the level of energy and demand savings

for approved Programs in North Carolina and Virginia.  As required by the NCUC and SCC, the

Company provides annual EM&V reports that include: i) the actual EM&V data; ii) the cumulative

results for each Program in comparison to forecasted annual projections; and iii) any

recommendations or observations following the analysis of the EM&V data.  These annual reports

will be filed on April 1 in each jurisdiction and will provide information through the prior calendar

year.  DNV GL (formerly DNV KEMA Energy & Sustainability), a third‐party vendor, continues to

be responsible for developing, executing, and reporting the EM&V results for the Company’s

currently approved DSM Programs.  

3.3 TRANSMISSION RESOURCES

3.3.1 EXISTING TRANSMISSION RESOURCES

The Company has over 6,400 miles of transmission lines in North Carolina, Virginia and West

Virginia at voltages ranging from 69 kV to 500 kV. These facilities are integrated into PJM.  

3.3.2 EXISTING TRANSMISSION & DISTRIBUTION LINES

North Carolina Plan Addendum 2 contains the list of Company’s existing transmission and

distribution lines listed in pages 422, 423, 424, 425, 426 and 427, respectively, of the Company’s most

recently filed Federal Energy Regulatory Commission (“FERC”) Form 1.

3.3.3 TRANSMISSION PROJECTS UNDER CONSTRUCTION

The Company currently has two transmission interconnection projects under construction which

may be found in Appendix 3V.  A list of the Company’s transmission lines and associated facilities

that are under construction may be found in Appendix 3W.
42

CHAPTER 4 – PLANNING ASSUMPTIONS 

4.1 PLANNING ASSUMPTIONS INTRODUCTION

The Company’s 2014 Plan relies upon a number of assumptions including requirements from PJM.  

This Chapter discusses a diverse set of these assumptions and requirements related to capacity

needs, reserve requirements, renewable energy requirements, commodity price assumptions, and

transmission assumptions.  The Company updates its IRP assumptions annually to maintain a

current view of relevant markets, the economy, and regulatory drivers.  

4.2 PJM CAPACITY PLANNING PROCESS & RESERVE REQUIREMENTS

The Company participates in the PJM capacity planning processes for short‐ and long‐term capacity

planning.  A brief discussion of these processes and the Company’s participation in them is

provided in the following subsections.

4.2.1 SHORT‐TERM CAPACITY PLANNING PROCESS – RPM

As a PJM member, the Company is a signatory to PJM’s Reliability Assurance Agreement, which

obligates the Company to own or procure sufficient capacity to maintain overall system reliability.  

PJM determines these obligations for each zone through its annual load forecast and reserve margin

guidelines.  PJM then conducts a capacity auction through its Short‐Term Capacity Planning Process

(i.e., the RPM auction) for meeting these requirements three years into the future.  This auction

process determines the reserve margin and the capacity price for each zone for the delivery year that

is three years in the future (e.g., 2014 auction procured capacity for the delivery year 2017/2018).  

The Company, as a generation provider, bids its capacity resources, including owned and contracted

generation and DSM programs, into this auction.  The Company, as an LSE, is obligated to obtain

enough capacity to cover its PJM‐determined capacity requirements either from the RPM auction, or

through any bilateral trades.  Figure 4.2.2.1 provides the Company’s estimated 2015 to 2017 capacity

positions and associated reserve margins based on PJM’s January 2014 Load Forecast and RPM

auctions that have already been conducted.  

4.2.2 LONG‐TERM CAPACITY PLANNING PROCESS – RESERVE REQUIREMENTS

The Company uses PJM’s reserve margin guidelines in conjunction with its own load forecast

discussed in Chapter 2 to determine its long‐term capacity requirement.  PJM conducts an annual

Reserve Requirement Study to determine an adequate level of capacity in its footprint to meet the

target level of reliability measured with a Loss of Load Expectation (“LOLE”) equivalent to one day

of outage in 10 years.  PJM’s 2013 Reserve Requirement Study4 for delivery year 2017/2018,

recommends using a reserve margin of 15.7% to satisfy the NERC/Reliability First Corporation

(“RFC”) Adequacy Standard BAL‐502‐RFC‐02, Planning Resource Adequacy Analysis, Assessment

and Documentation.

                                                       

4 PJM’s current and historical reserve margins are available at: http://www.pjm.com/sitecore%20modules/web/~/media/planning/res‐

adeg/historical‐pjm‐installed‐reserve‐margin.ashx.  See also http://www.pjm.com/~/media/committees‐

groups/committees/mrc/20131024/20131024‐item‐04‐irm‐study.ashx for PJM’s 2013 Reserve Requirement Study.
43

PJM develops reserve margin estimates for planning years (referred to as delivery in RPM) rather

than calendar years.  Specifically, PJM’s planning year occurs from June 1st of one year to May 31st of

the following year.  Since the Company and PJM are both historically summer peaking entities, and

since the summer period of PJM’s planning year coincides with the calendar year summer period,

calendar and planning year reserve requirement estimates are determined based on the identical

summer time‐period.  For example, the Company uses PJM’s 2017/2018 delivery year assumptions

for the 2017 calendar year in its 2014 Plan because both represent the expected peak load during the

summer of 2017.

Two assumptions were made by the Company when applying the PJM reserve margin to the

Company’s modeling efforts.  First, since PJM uses a shorter Planning Period than the Company, the

Company used the most recent PJM reserve requirements study and assumed the reserve margin

value for delivery year 2017/18 would continue throughout the Study Period.   

The second assumption pertains to the coincident factor between the DOM Zone coincidental and

non‐coincidental peak load.  The Company is obligated to maintain a reserve margin for its portion

of the PJM coincidental peak load.  Since the Company’s peak load (non‐coincidental) has not

historically occurred during the same hour as PJM’s peak load (coincidental), a smaller reserve

margin is needed to meet reliability targets and is based on a coincidence factor.  To determine the

coincidence factor used in the 2014 Plan, the Company used a four‐year (2014 ‐ 2017) average of the

coincidence factor between the DOM Zone coincidental and non‐coincidental peak load.  The

coincidence factor for the Company’s load is approximately 96.1% as calculated using PJM’s January

2014 Load Forecast.  In 2017, applying the PJM Installed Reserve Margin (“IRM”) requirement of

15.7% with the Company’s coincidence factor of 96.1% resulted in an effective reserve margin of

11.2% as shown in Figure 4.2.2.1.  This effective reserve margin was then used for each year for the

remainder of the Planning Period.

As a member of PJM, the Company participates in the annual RPM capacity markets.  PJM’s RPM

construct has historically resulted in a clearing reserve margin in excess of the planned reserve

margin requirement.  The average PJM RPM clearing reserve margin is 20.2% over the past five

years.5  Using the same analysis approach described above, this equates to an approximate 15.48%

effective reserve requirement.  With the RPM clearing capacity in excess of its target level, the

Company has purchased reserves in excess of the 11.2% planning reserve margin as reflected in

Figure 4.2.2.1.  Given this history, Figures 1.4.3(a) and (b) and 6.8.3(a) and (b), display a second

capacity requirement target that includes an additional 5% reserve requirement target (16.2% reserve

margin) that is commensurate with the upper bound where the RPM market has historically cleared;

however, the Company’s planning reserve margin minimum target remains at the 11.2% average

clearing level.  The upper bound reserve margin reflects the reserve margin that the Company may

be required to meet in the future.

                                                       

5 See http://www.pjm.com/~/media/markets‐ops/rpm/rpm‐auction‐info/2017‐2018‐base‐residual‐auction‐report.ashx.
44

Figure 4.2.2.1 ‐ Peak Load Forecast & Reserve Requirements

 

Notes: 1) 2015 – 2017 values reflect the Company’s position following RPM base residual auctions that have cleared.  

2) Does not include conservation/efficiency adjustments.  

3) Includes wholesale obligations.

In Figure 4.2.2.1, the total resource requirement column provides the total amount of peak capacity

including the reserve margin used in the 2014 Plan.  This represents the Company’s total resource

need that must be met through existing resources, construction of new resources, DSM programs,

and market capacity purchases.  Actual reserve margins in each year may vary based upon the

outcome of the forward RPM auctions and annually updated load and reserve requirements.  

Appendix 2I provides a summary of projected PJM reserve margins for summer peak demand.

Finally, the industryʹs compliance with effective and anticipated EPA regulations concerning air,

water, and solid waste constituents influenced the retirement decision of numerous coal plants,

which are scheduled to retire over the next several years.  In June 2014, EPA proposed regulations

for carbon emissions that will most likely apply additional financial pressure on fossil fuel‐fired

generation, particularly coal units, which may lead to incremental retirement of additional fossil

fuel‐fired generation.  Considering the large number of announced retirements and the potential for

additional plant retirements along with the long lead times required to develop replacement

generation, a period of uncertainty as to the availability of power from outside the service territory

may develop.  Therefore, the Company maintains that it is prudent to plan for a higher capacity

reserve margin during this period of uncertainty and not expose its customers to an overreliance on

market purchases during this uncertain period of time.  

PJM Installed

Reserve Margin

Requirements1

DVP Effective

Reserve Margin

Total System

Summer

Peak2

Reserve

Requirement

Total Resource

Requirement3

% % MW MW MW

2015 ‐ 15.7%                   17,670                     2,777                           20,447

2016 ‐ 17.4%                   17,999                     3,131                           21,130

2017 ‐ 14.9%                   18,347                     2,741                           21,088

2018 15.7% 11.2%                   18,635                     2,087                           20,722

2019 15.7% 11.2%                   18,898                     2,140                           21,038

2020 15.7% 11.2%                   19,114                     2,169                           21,283

2021 15.7% 11.2%                   19,369                     2,196                           21,565

2022 15.7% 11.2%                   19,615                     2,224                           21,839

2023 15.7% 11.2%                   19,863                     2,250                           22,113

2024 15.7% 11.2%                   20,099                     2,277                           22,376

2025 15.7% 11.2%                   20,336                     2,304                           22,640

2026 15.7% 11.2%                   20,578                     2,333                           22,911

2027 15.7% 11.2%                   20,838                     2,361                           23,198

2028 15.7% 11.2%                   21,085                     2,388                           23,473

2029 15.7% 11.2%                   21,331                     2,388                           23,719

Year
45

4.3 RENEWABLE ENERGY  

4.3.1 NORTH CAROLINA REPS PLAN  

NCGS § 62‐133.8 requires the Company to comply with the state’s Renewable Energy and Energy

Efficiency Portfolio Standard (“REPS”) Plan requirement.  The REPS requirements can be met by

generating renewable energy, energy efficiency measures (capped at 25% of the REPS requirements

through 2020 and up to 40% thereafter), purchasing renewable energy, purchasing renewable energy

certificates (“RECs”), or a combination of options as permitted by NCGS § 62‐133.8 (b) (2).  The

Company plans to meet a portion of the general REPS requirements using the approved energy

efficiency programs discussed in Chapters 3 and 6 of this Plan.  The Company achieved compliance

with its 2013 North Carolina REPS requirements by using banked RECs and purchasing additional

qualified RECs.  In addition, the Company purchased sufficient RECs to comply with the poultry

waste requirement.  However, on March 26, 2014, in response to the Amended Joint Motion to

Delay, the NCUC delayed the 2013 swine waste requirement and poultry waste requirement for a

one‐year period.  More information regarding the Company’s plans is available in its North Carolina

REPS Compliance Plan filed in North Carolina with this 2014 Plan as North Carolina IRP

Addendum 1.  Figure 4.3.1.1 displays North Carolina’s overall REPS requirements.

Figure 4.3.1.1 ‐ North Carolina REPS Requirements

Note: 1) Annual GWh is an estimate only based on the latest forecast sales. The Company intends to comply with the North Carolina REPS

requirements, including the set‐asides for energy derived from solar, poultry litter, and swine waste through the purchase of RECs and/or

purchased energy, as applicable. These set aside requirements represent approximately 0.03% of system load by 2024 and will not materially

alter the 2014 Plan.

As part of the total REPS requirements, North Carolina requires certain renewable set‐aside

provisions for solar energy, swine waste, and poultry waste resources, as shown in Figure 4.3.1.2,

Figure 4.3.1.3, and Figure 4.3.1.4.  

Year Percent of REPS Annual GWh1

2012 3% of 2011 DNCP Retail Sales 125

2013 3% of 2012 DNCP Retail Sales 123

2014 3% of 2013 DNCP Retail Sales 129

2015 6% of 2014 DNCP Retail Sales 248

2016 6% of 2015 DNCP Retail Sales 252

2017 6% of 2016 DNCP Retail Sales 256

2018 10% of 2017 DNCP Retail Sales 429

2019 10% of 2018 DNCP Retail Sales 431

2020 10% of 2019 DNCP Retail Sales 434

2021 12.5% of 2020 DNCP Retail Sales 547
46

Figure 4.3.1.2 ‐ North Carolina Solar Requirements

Notes: 1) Annual GWh is an estimate based on latest forecast sales.  

2) The Company achieved compliance with the 2010 ‐ 2013 NC Solar targets.

3) The Company has purchased solar RECs necessary to satisfy the North Carolina 2014 solar goal of 2.92 GWh.  

Figure 4.3.1.3 ‐ North Carolina Swine Waste Requirements

Note: 1) Annual GWh is an estimate based on the latest forecast sales.

Year Requirement Target (%) Annual GWh1

2010 0.02% of 2009 DNCP Retail Sales 0.812

2011 0.02% of 2010 DNCP Retail Sales 0.872

2012 0.07% of 2011 DNCP Retail Sales 2.932

2013 0.07% of 2012 DNCP Retail Sales 2.883

2014 0.07% of 2013 DNCP Retail Sales 3.02

2015 0.14% of 2014 DNCP Retail Sales 5.79

2016 0.14% of 2015 DNCP Retail Sales 5.89

2017 0.14% of 2016 DNCP Retail Sales 5.96

2018 0.20% of 2017 DNCP Retail Sales 8.58

2019 0.20% of 2018 DNCP Retail Sales 8.62

2020 0.20% of 2019 DNCP Retail Sales 8.67

2021 0.20% of 2020 DNCP Retail Sales 8.75

Year Target Dominion Market

Share (Est.)

Annual

GWh1

2012 Eliminated 3.19%

2013 Requirement Delayed 3.22%

2014 0.07% of 2013 NC Retail Sales 2.91% 3.02

2015 0.07% of 2014 NC Retail Sales 2.90% 2.90

2016 0.14% of 2015 NC Retail Sales 2.90% 5.89

2017 0.14% of 2016 NC Retail Sales 2.88% 5.96

2018 0.14% of 2017 NC Retail Sales 2.84% 6.01

2019 0.20% of 2018 NC Retail Sales 2.82% 8.62

2020 0.20% of 2019 NC Retail Sales 2.80% 8.67

2021 0.20% of 2020 NC Retail Sales 2.80% 8.75
47

Figure 4.3.1.4 ‐ North Carolina Poultry Waste Requirements

Note: 1) For purposes of this filing, the Poultry Waste Resource requirement is calculated as an aggregate target for NC electric suppliers

distributed based on market share.

4.3.2   VIRGINIA RPS PLAN

On May 18, 2010, the SCC issued its Final Order granting the Company’s July 28, 2009 application to

participate in Virginia’s voluntary Renewable Energy Portfolio Standards (“RPS”) program finding

that “the Company has demonstrated that it has a reasonable expectation of achieving 12 percent of

its base year electric energy sales from renewable energy sources during calendar year 2022, and 15

percent of its base year electric energy sales from renewable energy sources during calendar year

2025” (Case No. PUE‐2009‐00082, May 18, 2010 Final Order at 7).  The RPS guidelines state that a

certain percent of the Company’s energy is to be obtained from renewable resources.  The Company

can meet Virginia’s RPS program guidelines through the generation of renewable energy, purchase

of renewable energy, purchase of RECs, or a combination of the three options.  The Company

achieved its 2013 Virginia RPS Goal.  Figure 4.3.2.1 displays Virginia’s RPS goals.  

Figure 4.3.2.1 ‐ Virginia RPS Goals  

Note: 1) Base year sales are equal to 2007 Virginia jurisdictional retail sales, minus 2004 to 2006 average nuclear generation. Actual goals are

based on MWh.

The Company has included renewable resources as an option in Strategist, taking into consideration

the economics and RPS requirements. VCHEC is expected to provide up to 60 MW of renewable

generation by 2020.  Plan B: Fuel Diversity Plan also identifies 247 MW (nameplate) of onshore wind,

Year Target1

(GWh)

Dominion Market

Share (Est.)

Annual

GWh1

2012 Requirement Delayed 3.19%

2013 Requirement Delayed 3.22%

2014 170 2.91% 4.95

2015 700 2.90% 20.28

2016 900 2.90% 26.09

2017 900 2.88% 25.93

2018 900 2.84% 25.58

2019 900 2.82% 25.35

2020 900 2.80% 25.22

2021 900 2.80% 25.18

Year Percent of RPS Annual GWh1

2010 4% of Base Year Sales 1,733

2011‐2015 Average of 4% of Base Year Sales 1,733

2016 7% of Base Year Sales 3,032

2017‐2021 Average of 7% of Base Year Sales 3,032

2022 12% of Base Year Sales 5,198

2023‐2024 Average of 12% of Base Year Sales 5,198

2025 15% of Base Year Sales 6,497
48

520 MW (nameplate) of solar capacity and 39 MW (nameplate) solar tag during the Planning Period.  

The Company reiterates its intent to meet Virginia’s RPS guidelines at a reasonable cost and in a

prudent manner by: i) applying renewable energy from existing generating facilities including

NUGs; ii) purchasing cost‐effective RECs (including optimizing RECs produced by Company‐

owned generation when these higher priced RECs are sold into the market and less expensive RECs

are purchased and applied to the Company’s RPS goals); and iii) constructing new renewable

resources when and where feasible.  Commercial development of offshore wind is ongoing and is

proceeding in tandem with the Company’s offshore wind pilot, which is focused on reducing the

cost of offshore wind development to make commercial development feasible.

The renewable energy requirements for North Carolina and Virginia and their totals are shown in

Figure 4.3.2.2.

Figure 4.3.2.2 ‐ Renewable Energy Requirements

4.4 COMMODITY PRICE ASSUMPTIONS  

The Company utilizes a single source to provide multiple scenarios for the commodity price forecast

to ensure consistency in methodologies and assumptions.  The Company performed the analysis for

the 2014 Plan using energy and commodity price forecasts provided by ICF International, Inc.

(“ICF”), a global energy consulting firm, in all periods except the first 36 months of the Study Period.  

The forecast used forward market prices, as of May 30, 2014, for natural gas, coal, and power prices

for the first 18 months and then blended forward prices with ICF estimates for the next 18 months.  

Beyond the first 36 months, the Company used the ICF commodity price forecast exclusively.  The

forecast used for capacity prices, CO2, NOx, and SO2 allowance prices are provided by ICF for all

years forecast in this year’s Plan.  The capacity prices are provided on a calendar year basis and

reflect the results of the PJM RPM auction through the 2017/2018 delivery year, thereafter

transitioning to the ICF capacity forecast beginning with the 2018/2019 delivery year.  The CO2 price

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029

GWh

VA RPS

NC REPS

Total RPS
49

forecast begins in 2020, (began in 2023 in 2013 Plan) to reflect the increasing potential for regulations

or legislation covering CO2 emissions from the power sector.  

 

4.4.1 BASECASE COMMODITY FORECAST  

The basecase commodity forecast represents the Company’s views of the most likely outcome for

commodity prices given current market conditions and ICF’s independent internal views of key

market drivers.  Key drivers include market structure and policy elements that shape allowance, fuel

and power markets, ranging from expected capacity and pollution control installations,

environmental regulations, and fuel supply‐side issues.  The basecase commodity forecast provides

a forecast of prices for fuel, energy, capacity, emission allowances and RECs.  The methodology used

to develop the forecast relies on an integrated, internally consistent, fundamentals‐based analysis.  

The development process assesses the impact of environmental regulations on the power and fuel

markets and incorporates ICF’s latest views on the outcome of new regulatory initiatives.

A summary of the basecase fuel price forecast is provided in the charts below including comparison

to the prices used in the 2013 Plan.  Appendix 4B provides delivered fuel prices and primary fuel

expense from the Strategist model output using the basecase forecast.  Figures 4.4.1.1, 4.4.1.2, and

4.4.1.3 display the basecase fuel price forecasts, while Figures 4.4.1.4 and 4.4.1.5 display the

forecasted price for SO2, NOx, and CO2 emissions allowances on a dollar per ton basis.  Figure 4.4.1.6

presents the forecasted market clearing power prices for the PJM DOM Zone.  The forecast of PJM

RTO capacity price is presented in Figure 4.4.1.7.  

Figure 4.4.1.1 ‐ Fuel Price Forecasts ‐ Natural Gas

 

$0

$1

$2

$3

$4

$5

$6

$7

$8

$9

Nominal $/MMbtu

DOM Zn 2014 Henry Hub 2014 DOM Zn 2013 Henry Hub 2013
50

Figure 4.4.1.2 ‐ Fuel Price Forecasts ‐ Coal

Figure 4.4.1.3 ‐ Fuel Price Forecasts ‐ Oil

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

4.50

5.00

Nominal $/MMbtu

CAPP CSX 12,500 1% FOB (2014) CAPP CSX 12,500 1% FOB (2013)

$0

$5

$10

$15

$20

$25

$30

Nominal $/MMbtu

No 2 NYMEX (2014) Resid (6 Oil) NYH 1% (2014)

No 2 NYMEX (2013) Resid (6 Oil) NYH 1% (2013)
51

Figure 4.4.1.4 ‐ Price Forecasts – SO2 & NOX

Figure 4.4.1.5 ‐ Price Forecasts ‐ CO2

$0

$10

$20

$30

$40

$50

$60

Nominal $/Ton

CAIR/CSAPR SO2 Group 1 (2014) CAIR/CSAPR NOX (2014)

CAIR SO2 Group 1 (2013) CAIR NOX (2013)

$0

$2

$4

$6

$8

$10

$12

$14

$16

$18

$20

Nominal $/Ton

Carbon (2014) Carbon (2013)
52

Figure 4.4.1.6 ‐ Power Price Forecasts

Figure 4.4.1.7 ‐ PJM RTO Capacity Price Forecasts

As seen in the above Figures, there are multiple differences in the 2014 basecase forecast used in this

Plan compared to the basecase forecast used in 2013 Plan.  In general, the forecast prices are lower

$0

$10

$20

$30

$40

$50

$60

$70

$80

$90

Nominal $/MWh

DOM Zn VP On Peak (2014) DOM Zn VP Off Peak (2014)

DOM Zn VP On Peak (2013) DOM Zn VP Off Peak (2013)

$0

$20

$40

$60

$80

$100

$120

$140

Nominal $/KW‐Year

RTO Capacity Price (2014) RTO Capacity Price (2013)
53

relative to the 2013 Plan.  The primary changes include lower natural gas prices delivered to DOM

Zone along with lower coal prices and updated environmental assumptions reflecting ICF’s latest

views on final and proposed environmental rules.  The lower power prices are primarily due to

lower fuel cost.  Over the long‐term, the lower price outlook for natural gas is a result of continued

increases in production of Marcellus and Utica shale gas in North America.  The outlook for coal

prices are lower based on significantly lower Central Appalachian (“CAPP”) demand than predicted

in last year’s forecast due to coal plant retirements, reduced dispatch as a result of lower natural gas

prices and coal plants switching to lower quality, lower cost coals.  Figure 4.4.1.8 presents a

comparison of average fuel, electric, and REC prices used in the 2013 Plan relative to those used in

the 2014 Plan.

The capacity price outlook in this year’s forecast prior to 2023 is higher, reflecting the most recent

capacity auction results and lower beginning in 2023 due to lower assumed cost for new capacity,

particularly new CC units.  The lower cost assumption for new capacity more than offsets the loss of

revenue associated with lower energy prices in the 2014 forecast which would otherwise drive

capacity prices higher.  ICF’s capacity forecast also reflects the retirement of resources and the

tightening of demand‐side participation rules in the PJM capacity market.

Figure 4.4.1.8 ‐ 2013 to 2014 Plan Fuel & Power Price Comparison

 

Note: 1) DOM Zone natural gas price used in plan analysis. Henry Hub prices are shown to provide market reference.

2) Capacity price represents actual clearing price from PJM RPM Base Residual Auction results through power year 2016/2017 for 2013 Plan

and 2017/2018 for 2014 Plan.

3) 2013 Planning Period 2014 – 2028, 2014 Planning Period 2015 – 2029.

4.4.2 ALTERNATIVE SCENARIO COMMODITY PRICES  

The alternative commodity price forecast scenarios represent reasonable outcomes for future

commodity prices based on alternate views of key fundamental drivers of commodity prices.  

However, as with all forecasts, there remain multiple possible outcomes for future prices that fall

outside of the commodity price scenarios developed for this year’s Plan.  History has shown that

unforeseen events can result in significant change in market fundamentals.  These events were not

contemplated five or 10 years before such an occurrence.  Several recent examples include the shale

gas revolution that is transforming the pricing structure of natural gas, a commodity that as recently

Fuel Price

Henry Hub Natural Gas1 ($/MMbtu) 5.94                                                          6.02

DOM Zone Delivered Natural Gas1 ($/MMbtu) 6.15                                                          6.01

CAPP CSX: 12,500 1%S  FOB ($/MMbtu) 3.29                                                          2.86

No. 2 Oil ($/MMbtu) 21.82                                                     22.43

1% No. 6 Oil ($/Mmbtu) 14.81                                                     15.24

Electric and REC Prices

PJM‐DOM On‐Peak ($/MWh) 67.02                                                     63.26

PJM‐DOM Off‐Peak ($/MWh) 53.04                                                     54.38

PJM Tier 1 REC Prices ($/MWh) 12.88                                                     18.16

RTO Capacity Prices2 ($/KW‐yr) 73.86                                                     76.20

Planning Period Comparison   

Average Value (Nominal $)

2013 Plan   

Basecase 3

2014 Plan   

Basecase 3
54

as 2008 was priced at historically high levels.  Another recent example is the scheduled retirement of

numerous generation units, fueled primarily by coal, in response to low gas prices, an aging coal

fleet, and environmental compliance cost.  The effects of unforeseen events should be considered

when evaluating the viability of long term planning objectives.  The commodity price forecast

scenarios analyzed for the Plan present reasonably likely outcomes given the current understanding

of market fundamentals, but not all possible outcomes.  The Company preserves its supply‐side

development options, including renewable and nuclear, as a necessary tool in a prudent long‐term

planning process because of unforeseen events among other reasons.    

The Company performed analysis using three alternative pricing scenarios.  The methodology of

using scenarios in IRP process is further explained in Section 6.6 herein.  The scenarios used in the

analysis include (1) High Fuel Cost, (2) Low Fuel Cost, and (3) No CO2 Cost.  These scenarios are

intended to represent a reasonably likely range of prices around the basecase, not the absolute

boundaries of higher or lower prices.

The High Fuel Cost scenario represents possible future market conditions where key market drivers

create upward pressure on commodity and energy prices during the Planning Period.  This scenario

reflects a correlated increase in commodity prices which, when compared to the basecase, provides

an average increase of approximately 15% for natural gas, 10% for coal, and 10% for PJM‐DOM Zone

peak energy prices during the Planning Period.  The drivers behind higher natural gas prices could

include lower incremental production growth from shale gas reservoirs, higher costs to locate and

produce natural gas, and increased demand.  Higher prices for coal result from increasing

production costs due to increased safety requirements, more difficult geology, and higher stripping

ratios.   

The Low Fuel Cost scenario represents possible future market conditions where key market drivers

create downward pressure on commodity and energy prices during the Planning Period.  This

scenario reflects a correlated price decrease in natural gas that averages approximately 11%, coal

price drops by approximately 9%, and PJM‐DOM Zone peak energy prices are lower by

approximately 6% across the Planning Period when compared to the basecase.  The drivers behind

lower natural gas prices could include higher incremental production growth from shale gas

reservoirs, lower costs to locate and produce natural gas, and lower demand.  Lower coal prices

result from improved mining productivity due to new technology and improved management

practices, and cost reductions associated with mining materials, supplies, and equipment.   

In the No CO2 Cost scenario, the cost associated with carbon emissions projected to commence in

2020 is removed from the forecast.  The cost of carbon being removed has an effect of reducing

natural gas prices by 11% across the Planning Period, and no appreciable change in coal or oil prices.  

DOM Zone peak energy prices are on average 9% lower than the basecase.   

Appendix 4A provides the annual prices (real $) provided by ICF for each commodity price

alternative scenario.  Figure 4.4.2.1 provides a comparison of the three alternative scenarios to the

basecase forecast.
55

Figure 4.4.2.1 ‐ 2014 Plan Scenarios Fuel & Power Price Comparison

4.5 DEVELOPMENT OF DSM PROGRAM ASSUMPTIONS

The Company develops assumptions for new DSM programs by using third‐parties to develop

assumptions for candidate programs and by testing the market through a bid process to find

vendors that can provide the necessary program implementation services.  The program design and

implementation firm may be the same entity, depending upon the program and the firm’s

capabilities.

The DSM program design process includes evaluating programs as either single measure like the

Residential Heat Pump Tune‐Up Program or multi‐measure like the Non‐Residential Energy Audit

Program.  For all measures in a program, the design vendor develops a baseline for a standard

customer end‐use technology.  The baseline establishes the current energy usage for a particular

appliance or customer end‐use.  Next, assumptions for a more efficient replacement measure or end‐

use are developed.  The difference between the more efficient energy end‐use and the standard end‐

use provides the incremental benefit that the Company and customer will achieve if the more

efficient energy use is implemented.

The program design vendor’s development of assumptions for a DSM program includes

determining cost estimates for the incremental customer investment in the more efficient

technology, the incentive that the Company should pay the customer to encourage investment in the

DSM measure, and the program cost the Company will likely incur to administer the program.  In

addition to the cost assumptions for the program, the program design vendor develops incremental

demand and energy reductions associated with the program.  This data is represented in the form of

a load shape for energy efficiency programs which identifies the energy reductions by hour for each

hour of the year (8,760 hour load shape).

The Company then uses the program assumptions developed by the program design vendor to

perform cost/benefit tests for the programs.  The cost/benefit tests assist in determining which

programs are cost‐effective and potentially included in the Company’s DSM portfolio.  Programs

that pass the Company’s screening process are included in the Company’s DSM portfolio.   

Fuel Price

Henry Hub Natural Gas ($/MMbtu) 6.02                                                       6.91                             5.36                                 5.37

DOM Zone Delivered Natural Gas ($/MMbtu) 6.01                                                       6.91                             5.35                                 5.36

CAPP CSX: 12,500 1%S  FOB ($/MMbtu) 2.86                                                       3.16                             2.60                                 2.87

No. 2 Oil ($/MMbtu) 22.43                                                  24.91                          20.95                              22.43

1% No. 6 Oil ($/Mmbtu) 15.24                                                  17.02                          14.27                              15.24

Electric and REC Prices

PJM‐DOM On‐Peak ($/MWh) 63.26                                                  70.07                          59.31                              57.74

PJM‐DOM Off‐Peak ($/MWh) 54.38                                                  59.99                          51.02                              49.00

PJM Tier 1 REC Prices ($/MWh) 18.16                                                  14.94                          21.29                              28.82

RTO Capacity Prices ($/KW‐yr) 76.20                                                  75.34                          77.69                              78.11

2015 ‐ 2029 Average Value (Nominal $ )

Basecase High Fuel Cost Low Fuel Cost No CO2 Cost
56

4.6 TRANSMISSION PLANNING

The Company’s transmission planning process, system adequacy, transfer capabilities, and

transmission interconnection process are described in the following subsections.  As used in this

Plan, electric transmission facilities at the Company can be generally defined as those operating at 69

kV and above that provide for the interchange of power within and outside of the Company’s

system.  

4.6.1 REGIONAL TRANSMISSION PLANNING & SYSTEM ADEQUACY

The Company’s transmission system is designed and operated to ensure adequate and reliable

service to its customers while meeting all regulatory requirements and standards.  Specifically, the

Company’s transmission system is developed to comply with the NERC Reliability Standards, as

well as the Southeastern Reliability Corporation supplements to the NERC standards.  

The Company participates in numerous regional, interregional, and sub‐regional studies to assess

the reliability and adequacy of the interconnected transmission system.  The Company is a member

of PJM, a RTO responsible for the movement of wholesale electricity.  PJM is registered with NERC

as the Company’s Planning Coordinator and Transmission Planner.  Accordingly, the Company

participates in the PJM Regional Transmission Expansion Plan (“RTEP”) to develop the RTO‐wide

transmission plan for PJM.  

The PJM RTEP covers the entire PJM control area and includes projects proposed by PJM, as well as

projects proposed by the Company and other PJM members through internal planning processes.  

The PJM RTEP process includes both a five‐year and 15‐year outlook.   

The Company evaluates its ability to support expected customer growth through its internal

transmission planning process.  The results of this evaluation will indicate if any transmission

improvements are needed, which the Company includes in the PJM RTEP process as appropriate

and, if the need is confirmed, then the Company seeks approval from the appropriate regulatory

body.  Additionally, the Company performs seasonal operating studies to identify facilities in the

Company’s transmission system that could be critical during the upcoming season.  In addition, it is

critical to maintain an adequate level of transfer capability between neighboring utilities to facilitate

economic and emergency power flows.  The Company coordinates with other utilities to maintain

adequate levels of transfer capability.  

4.6.2 SUBSTATION SECURITY

As part of the Companyʹs overall strategy to improve its transmission system resiliency and security,

the Company is installing additional physical security measures at substations in North Carolina

and Virginia.  The Company announced these plans publicly following the widely‐reported April

2013 Metcalfe Substation incident in California.  

As one of the region’s largest electricity suppliers, the Company has proposed to spend up to $500

million within the next five to seven years to increase the security for its transmission substations

and other critical infrastructure against man‐made physical threats and natural disasters, as well as

stockpile crucial equipment for major damage recovery.  These new security facilities will be

installed in accordance with recently approved NERC mandatory compliance standards.  In
57

addition, the Company is moving forward with constructing a new System Operations Center to be

commissioned by 2017.  

4.6.3 TRANSMISSION INTERCONNECTIONS

For any new generation proposed within the Company’s transmission system, either by the

Company or by other parties, the generation owner files an interconnection request with PJM.  PJM,

in conjunction with the Company, conducts Feasibility Studies, System Impact Studies, and Facilities

Studies to determine the facilities required to interconnect the generation to the transmission system

(Figure 4.6.3.1).  These studies ensure deliverability of the generation into the PJM market.  The

scope of these studies is provided in the applicable sections of the PJM manual 14A6 and the

Company’s Facility Connection Requirements.7

The results of these studies provide the requesting interconnection customer with an assessment of

the feasibility and costs (both interconnection facilities and network upgrades) to interconnect the

proposed facilities to the PJM system, which includes the Company’s transmission system.

Figure 4.6.3.1 ‐ PJM Interconnection Request Process

Source: PJM  

The Company’s planning objectives include analyzing planning options for transmission, as part of

the IRP process, and providing results that become inputs to the PJM planning processes.  In order

to accomplish this goal, the Company must comply and coordinate with a variety of regulatory

groups that address reliability, grid expansion, and costs which fall under the authority of NERC,

PJM, FERC, the NCUC, and the SCC.  In evaluating and developing this process, balance among

regulations, reliability, and costs are critical to providing service to the Company’s customers in all

aspects, which includes generation and transmission services.

The Company also evaluates and analyzes transmission options for siting potential generation

resources to offer flexibility and additional grid benefits.  The Company conducts power flow

studies and financial analysis to determine interconnection requirements for new supply‐side

resources.

                                                       

6 The PJM manual 14A is posted at http://www.pjm.com/~/media/documents/manuals/m14a.ashx.

7 The Company’s Facility Connection Requirements are posted at http://www.dom.com/business/electric‐

transmission/pdf/Facility_Connection_Requirements.pdf
58

The Company uses Promod IV®, which performs security constrained unit commitment and

dispatch, to consider the proposed and planned supply‐side resources and transmission facilities.  

Promod IV®, which incorporates extensive details in generating unit operating characteristics,

transmission grid topology and constraints, unit commitment/operating conditions, and market

system operations, is the industry‐leading fundamental electric market simulation software.

The Promod IV® model enables the Company to integrate the transmission and generation system

planning to: i) analyze the zonal and nodal level Locational Marginal Pricing (“LMP”) impact of new

resources and transmission facilities, ii) calculate the value of new facilities due to the alleviation of

system constraints, and iii) perform transmission congestion analysis.

The model is utilized to determine the most beneficial location for new supply‐side resources in

order to optimize the future need for both generation and transmission facilities while providing

reliable service to all customers.  The Promod IV® model evaluates the impact of resources under

development that are selected by the Strategist model.  Specifically, this Promod IV® LMP analysis

was conducted for the Warren County Power Station, along with the Brunswick County Power

Station.  In addition, the Promod IV® and Power System Simulator for Engineering were utilized to

evaluate the impact of future generation retirements on the reliability of the DOM Zone

transmission grid.   

4.7 GAS SUPPLY, ADEQUACY AND RELIABILITY

In maintaining its diverse generating portfolio, the Company manages a balanced mix of fuels that

includes fossil, nuclear and renewable resources.  Specifically, the Company’s fleet includes units

powered by natural gas, coal, petroleum, uranium, biomass (waste wood), water and solar.  This

balanced and diversified fuel management approach supports the Company’s efforts in meeting its

customers’ growing demand by responsibly and cost‐effectively managing risk.  By avoiding

overreliance on any single fuel source, the Company protects its customers from rate volatility and

other harms associated with shifting regulatory requirements, commodity price volatility and

reliability concerns.

Electric Power and Natural Gas Interdependency

Of the new generating capacity in North America projected to begin operation over the next 10

years, a majority is expected to rely on natural gas as the single or primary fuel.8  With a production

shift from conventional to an expanded array of unconventional gas sources (such as shale) and

relatively low commodity price forecasts, gas‐fired generation is the first choice for new capacity,

overtaking and replacing coal‐fired capacity.  Natural gas is expected to power electric generation

serving more than 50% of the electric peak demand (summer) in North America within one year.9  

However, the electric grid’s exposure to interruptions in natural gas fuel supply and delivery has

increased with the generating capacity’s growing dependence on a single fuel.  Natural gas is largely

                                                       

8 NERC Special Reliability Assessment: Accommodating an Increased Dependence on Natural Gas for Electric Power; Phase II: A

Vulnerability and Scenario Assessment for the North American Bulk Power System, page 7 (available at

http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_PhaseII_FINAL.pdf) (May 2013).

9 Id. at 3.
59

delivered on a just‐in‐time basis, and vulnerabilities in gas supply and transportation must be

sufficiently evaluated from a planning and reliability perspective.  Mitigating strategies – such as

storage, firm fuel contracts, alternate pipelines, dual‐fuel capability, access to multiple natural gas

basins, and overall fuel diversity all help to alleviate this risk.

There are two types of pipeline delivery service contracts – firm and interruptible service.  Natural

gas provided under a firm service contract is available to the customer at all times during the

contract term and is not subject to a prior claim from another customer.  For a firm service contract,

the customer typically pays a facilities charge representing the customer’s share of the capacity

construction cost and a fixed monthly capacity reservation charge.  Interruptible service contracts

provide the customer with natural gas subject to the contractual rights of firm customers.  The

Company currently uses a combination of both firm and interruptible service to fuel its gas‐fired

generation fleet.  As the percentage of natural gas use increases in terms of both energy and

capacity, the Company intends to increase its use of firm transport capacity to help ensure reliability

and price stability.

Pipeline deliverability can impact electrical system reliability.  A physical disruption to a pipeline or

compressor station can interrupt or reduce the flow pressure of gas supply to multiple electric

generating units at once.  Electrical systems also have the ability to adversely impact pipeline

reliability.  The sudden loss of a large efficient generator can cause numerous smaller gas‐fired

combustion turbines to be started in a short period of time, assuming capacity or other generators

are available.  This sudden change in demand may cause drops in pipeline pressure that could

reduce the quality of service to other pipeline customers, including other generators.  Electric

transmission system disturbances may also interrupt service to electric gas compressor stations,

which can disrupt the fuel supply to electric generators.

As a result, the Company routinely assesses the gas‐electric reliability of its system.  The result of

these assessments show that current interruptions on any single pipeline are manageable, but as the

Company and the electric industry shift to a heavier reliance on natural gas, additional actions are

needed to ensure future reliability and rate stability.  Additionally, equipping future CCs and CTs

with dual‐fuel capability may be needed to further enhance the reliability of the electric system.   

System Planning

In general, electric transmission service providers maintain, plan, design, and construct systems that

meet federally‐mandated NERC Reliability Standards and other requirements, and that are capable

of serving forecasted customer demands and load growth.  A well‐designed electrical grid, with

numerous points of interconnection and facilities designed to respond to contingency conditions,

results in a flexible, robust electrical delivery system.   

In contrast, pipelines generally are constructed to meet new load growth.  FERC does not authorize

new pipeline capacity unless customers have already committed to it via firm delivery contracts,

and pipelines are prohibited from charging the cost of new capacity to their existing customer base.  

Thus, in order for a pipeline to add or expand facilities, existing or new customers must request

additional firm service.  The resulting new pipeline capacity closely matches the requirements of the

new firm capacity request.  If the firm customers accept all of the gas under their respective
60

contracts, little or no excess pipeline capacity will be available for interruptible customers.  This is a

major difference between pipeline infrastructure construction and electric transmission system

planning because the electric system is expanded to address current or projected system conditions

and the costs are typically socialized across customers.   

Actions

The Company is aware of the risks associated with natural gas deliverability and has been proactive

in mitigating these risks.  For example, the Company continues to secure firm natural gas pipeline

transportation service for all new CC facilities including Bear Garden, Warren County, Brunswick

County, and the 2019 CC under early development.  Additionally, the Company maintains a

portfolio of firm gas transportation to serve a portion of its remaining gas generation fleet.   

Notwithstanding the above, the interstate transmission pipeline network can face severe constraints,

particularly in the Company’s service territory, leading to extremely high prices and possible

regional supply shortages during periods of intense demand, such as the Polar Vortex events during

the winter of 2014.  For example, average gas prices on one of the primary hubs serving Virginia rose

by more than 500%, from $10.78 per MMBtu to $72.62 per MMBtu, from January 6 to January 7, 2014.  

Later in the month, on January 22, spot prices on this hub surged to $118.10 per MMBtu during

another outbreak of extreme cold.  As such, additional pipeline infrastructure is needed into the

region to assure reliable natural gas supply and to enhance rate stability for the electric system.  This

need continues to increase as coal generation units retire and natural gas‐fired generation increases.

   
61

CHAPTER 5 – FUTURE RESOURCES 

5.1 FUTURE SUPPLY‐SIDE RESOURCES

The Company continues to monitor viable commercial‐ and utility‐scale emerging generation

technologies.  The Company gathers information about potential and emerging generation

technologies from a mix of internal and external sources.  The Company’s internal knowledge base

spans various departments including but not limited to planning, financial analysis, construction,

operation, alternative energy solutions, and business development.  The dispatchable and non‐

dispatchable resources examined in this 2014 Plan are defined and discussed in the following

subsections.

5.1.1 DISPATCHABLE RESOURCES

Biomass  

Biomass generation facilities rely on renewable fuel in their thermal generation process.  In the

Company’s service territory, the renewable fuel primarily used is waste wood, which is carbon

neutral.  The Company completed its Altavista, Hopewell, and Southampton unit conversions from

coal‐fired to biomass generation facilities, rated at 51 MW each, prior to the end of 2013.  Greenfield

biomass was considered for further analysis in the Company’s busbar curve analysis; however, it

was found to be uneconomic.  Generally, biomass generation facilities are geographically limited by

the access to the fuel source.

Coal

Circulating Fluidized Bed (“CFB”)  

CFB combustion technology is a clean coal technology that has been operational for the past few

decades and can consume a wide array of coal types and qualities, including low British thermal

unit (“Btu”) waste coal and wood products.  The technology uses jets of air to suspend the fuel and

results in a more complete chemical reaction allowing for efficient removal of many pollutants such

as NOx and SO2.  The preferred location for this technology is within the vicinity of large quantities

of waste coal fields.  The Company will continue to track this technology and its associated

economics based on the site and fuel resource availability.  With the limited site availability and

scarcity of fuel resources within the Company’s service territory, and strict standards on emissions

from the electric generating unit GHG New Source Performance Standards (“NSPS”) rule, this

resource was not considered for further analysis in the Company’s busbar curve analysis.

Coal with Carbon Capture and Sequestration (“CCS”)

Coal generating technology is very mature with hundreds of plants in operation across the United

States and others under various stages of development.  CCS is a new and developing technology

designed to collect and trap CO2 underground.  This technology can be combined with many

thermal generation technologies to reduce atmospheric carbon emissions; however, it is generally

proposed to be used with coal burning facilities.  The EPA’s GHG NSPS rule for new electric

generating units, as currently proposed, would require all new fossil fuel‐fired electric generation

resources to meet a strict limit for CO2 emissions.  To meet these standards, CCS technology is

assumed to be required on all new coal, including supercritical pulverized coal (“SCPC”) and
62

integrated‐gasification combined‐cycle (“IGCC”) technologies.  Coal generation with CCS

technology, however, is still under development and not commercially available.  The Company will

continue to track this technology and its associated economics.  This resource was considered for

further analysis in the Company’s busbar curve analysis.  

Coal without CCS

In accordance with the SCC’s Final Order in Case No. PUE‐2011‐00092, the Company included a

SCPC generating facility without CCS for the busbar screening curve.  The Company, however, does

not believe a new coal generating facility could be built without CCS due to effective and anticipated

environmental regulations that preclude such units from receiving the necessary environmental

permits.  This resource was considered for further analysis in the Company’s busbar curve analysis.

IGCC with CCS10

IGCC plants use a gasification system to produce synthetic natural gas from coal in order to fuel a

CC.  The gasification system process produces a pressurized stream of CO2 before combustion,

which research suggests provides some advantages in preparing the CO2 for CCS systems.  IGCC

systems remove a greater proportion of other air effluents in comparison to traditional coal units.  

The Company will continue to follow this technology and its associated economics.  This resource

was considered for further analysis in the Company’s busbar curve analysis.

IGCC without CCS

As per the SCC’s Final Order in Case No. PUE‐2011‐00092, the Company included IGCC without

CCS for the busbar screening curve.  The Company, however, does not believe a new IGCC unit

could be built without CCS due to effective and anticipated environmental regulations.  This

resource was considered for further analysis in the Company’s busbar curve analysis.

Energy Storage

There are several different types of energy storage technologies.  Energy storage technologies

include, but are not limited to, pumped storage hydroelectric power, superconducting magnetic

energy storage, capacitors, compressed air energy storage, flywheels, and batteries.  Cost

considerations have restricted widespread deployment of most of these technologies, with the

exception of pumped hydroelectric power and batteries.  

The Company is the operator and a 60% owner in the Bath County Pumped Storage Station, which is

one of the world’s largest pumped storage generation stations, with a net generating capacity of

3,003 MW.  Due to their size, pumped storage facilities are best suited for centralized utility‐scale

applications.  

Batteries serve a variety of purposes that make them attractive options to meet energy needs in both

distributed and utility‐scale applications.  Batteries can be used to provide energy for power station

blackstart, peak load shaving, frequency regulation services, or peak load shifting to off‐peak

                                                       

10 The Company currently assumes that the captured carbon cannot be sold.
63

periods.  They vary in size, differ in performance characteristics, and are usable in different

locations.  Recently, batteries have gained considerable attention due to their ability to integrate

intermittent generation sources, such as wind and solar, onto the grid.  Battery storage technology

facilitates the dispatchability of these variable energy resources.  The primary challenge facing

battery systems is the cost.  Other factors such as recharge times, variance in temperature, energy

efficiency, and capacity degradation are also important considerations for utility‐scale battery

systems.  

The Company is actively engaged in the evaluation of the potential for energy storage technologies

to provide ancillary services, to improve overall grid efficiency, and to enhance distribution system

reliability.  Due to the costs associated with technologies similar to batteries and location limitations

associated with pumped storage facilities, these resources were not considered for further analysis in

the Company’s busbar curve analysis.

Fuel Cell

Fuel cells are electrochemical cells that convert chemical energy from fuel into electricity and heat.  

They are similar to batteries in their operation, but where batteries store energy in the components (a

closed system), fuel cells consume their reactants.  Although fuel cells are considered an alternative

energy technology, they would only qualify as renewable in North Carolina or Virginia if powered

by a renewable energy resource as defined by the respective state’s statutes.  This resource was

considered for further analysis in the Company’s busbar curve analysis.

Gas‐Fired Combined‐Cycle

A natural gas CC plant combines a CT and a steam turbine plant into a single, highly‐efficient power

plant.  The Company considered CC 3x1 generators, with heat recovery steam generators and

supplemental firing capability, based on commercially available‐advanced technology.  The 3x1 CC

resources were considered for further analysis in the Company’s busbar curve analysis.

Gas‐Fired Combustion Turbine

Gas‐fired CT technology has the lowest capital requirements ($/kW) of any resource considered;

however, it has relatively high variable costs because of its low efficiency.  This is a proven

technology with cost information readily available.  This resource was considered for further

analysis in the Company’s busbar curve analysis.

Geothermal  

Geothermal technology uses the heat from the earth to create steam that is subsequently run through

a steam turbine.  As of 2012, the National Renewable Energy Laboratory has not indicated that there

are any viable sites for geothermal technology identified in the eastern portion of the United States.11  

The Company does not view this resource as a feasible option in its service territory at this time;

however, it will continue to monitor developments surrounding geothermal technology.  This

resource was not considered for further analysis in the Company’s busbar curve analysis.

                                                       

11 Retrieved from: http://www.nrel.gov/geothermal/.
64

Hydro

Facilities powered by falling water have been operating for over a century.  Construction of large‐

scale hydroelectric dams is currently unlikely due to environmental restrictions in the Company’s

service territory; however, smaller‐scale plants, or run‐of‐river facilities, are feasible.  Due to the site‐

specific nature of these plants, the Company does not believe it is appropriate to further investigate

this type of plant until a viable site is available.  This resource was not considered for further

analysis in the Company’s busbar curve analysis.

Nuclear  

With an increasing need for clean, non‐carbon emitting baseload power, many electric utilities are

re‐examining new nuclear power units.  The process for constructing a new nuclear unit remains

time‐consuming with various permits for design, location, and operation required by various

government agencies.  Recognizing the importance of nuclear power and its many environmental

and economic benefits, the Company continues to develop an additional unit at North Anna.  For

further discussion of the Company’s development of North Anna 3, see Section 5.3.  This resource

was considered for further analysis in the Company’s busbar curve analysis.

Nuclear Fusion

The Company will continue to monitor any developments regarding nuclear fusion technology.  

This resource was not considered for further analysis in the Company’s busbar curve analysis.

Small Modular Reactors (“SMR”)

SMRs are utility‐scale nuclear units with electrical output of 300 MW or less.  SMRs are

manufactured almost entirely off site in factories and delivered and installed on site in modules.  

The small power output of SMRs means electricity costs more per MW than a larger reactor, but the

initial costs of building the plant are significantly reduced.  An SMR entails underground placement

of reactors and spent‐fuel storage pools, a natural cooling feature that can continue to function in the

absence of external power, and has more efficient containment and lessened proliferation concerns

than standard nuclear units.  SMRs are still in the early stages of development and permitting, and

thus at this time are not considered a viable resource for the Company.  The Company will continue

to monitor the industry’s ongoing research and development regarding this technology.  This

resource was not considered for further analysis in the Company’s busbar curve analysis.  

5.1.2 NON‐DISPATCHABLE RESOURCES

Onshore Wind

Wind resources are one of the fastest growing resources in the United States.  The Company has

considered onshore wind resources as a means of meeting the RPS goals, REPS requirements, and as

a cost‐effective stand‐alone resource.  The suitability of this resource is highly dependent on locating

an operating site that can achieve an acceptable capacity factor.  Additionally, these facilities tend to

operate at times that are non‐coincidental with peak system conditions and therefore generally

achieve a capacity contribution significantly lower than their nameplate ratings.  There is limited

land available in the Company’s service territory with sufficient wind characteristics because the

Eastern portions of the United States wind resources are limited and available only in specialized

locations, such as on mountain ridges.  Figure 5.1.2.1 displays the onshore wind potential of North

Carolina and Virginia.  The Company continues to examine onshore wind and has identified three
65

feasible sites for consideration as onshore wind facilities in the western part of Virginia on

mountaintop locations.  This resource was considered for further analysis in the Company’s busbar

curve analysis.  

Figure 5.1.2.1 ‐    Onshore Wind Resources

Source: Retrieved from the National Renewable Energy Laboratory on July 3, 2014.

Offshore Wind

Offshore wind has the potential to provide the largest, scalable renewable resource for Virginia.   

Figure 5.1.2.2 displays the offshore wind potential of North Carolina and Virginia.  Virginia has a

unique offshore wind opportunity due to its shallow continental shelf extending approximately 40

miles off the coast, proximity to load centers, availability of local supply chain infrastructure, and

world class port facilities.  However, one challenge facing offshore wind development is its complex

and costly installation and maintenance when compared to onshore wind.  This resource was

considered for further analysis in the Company’s busbar curve analysis.

Figure 5.1.2.2 ‐ Offshore Wind Resources  

Source: Retrieved from Energy on July 3, 2014.
66

Solar PV & Concentrating Solar Power (“CSP”)

Solar PV and CSP are the two main types of solar technology used in electric power generation.  

Solar PV systems consist of interconnected PV cells that use semiconductor devices to convert

sunlight into electricity.  Solar PV technology is found in both large‐scale and distributed systems

and can be implemented where unobstructed access to sunlight is available.  CSP systems utilize

mirrors to reflect and concentrate sunlight onto receivers to convert solar energy into thermal energy

that in turn produces electricity.  CSP systems are generally used in large scale solar plants and are

mostly found in the southwestern area of the United States where solar resource potential is the

highest.

Although solar PV costs have declined in recent years, installed system costs can vary widely

depending on system size, technology types, and site specific factors.  For example, a solar cellʹs

output and efficiency depends on various components, such as its design and materials, the intensity

of the solar radiation hitting the cell, and the cellʹs temperature.  Solar PV generation is not

dispatchable and contributes less to peak load and reserve requirements than conventional

generation resources.  However, continuing advancements in storage technology may allow solar

output to become a more reliable peak load resource in the future.  Figure 5.1.2.3 displays the solar

PV potential of the United States.  As the quantity of solar increases in the system, the Company will

need to perform additional analysis to assure proper integration safeguards are in place, such as

operating reserve adequacy.

Solar PV technology was considered for further analysis in the Company’s busbar curve analysis,

while CSP was not.  The Company has considered both fixed tilt and tracking PV technology in its

busbar analysis.  Also included in the Company’s busbar curve analysis is a fixed tilt solar PV unit at

a brownfield (existing generation) site (“solar tag”).  By installing solar at an existing generating

facility, the output can be tied into the existing electrical infrastructure.  Use of such a site would

allow the Company to decrease the initial fixed cost of the resource, while the other characteristics of

the unit stay the same.
67

Figure 5.1.2.3 – National Photovoltaic Resources of the United States

Source: Retrieved from the National Renewable Energy Laboratory on July 3, 2014.

Tidal & Wave Power

Tidal and wave power rely on ocean water fluctuations to collect and release energy.  Significant

research is being conducted by many individuals and firms into the development of tidal‐ and

wave‐powered electric facilities.  However, neither type of facility has proven to be commercially

available.  The Company will continue to monitor developments surrounding these technologies.  

This resource was not considered for further analysis in the Company’s busbar curve analysis.  

5.1.3 ASSESSMENT OF SUPPLY‐SIDE RESOURCE ALTERNATIVES  

The process of selecting alternative resource types starts with the identification and review of the

characteristics of available and emerging technologies, as well as any applicable statutory

requirements.  Next, the Company analyzes the current commercial status and market acceptance of

alternative resources.  This analysis includes determining whether particular alternatives are feasible

in the short‐ or long‐term based on the availability of resources or fuel within the Company’s service

territory or power pool.  The technology’s ability to be dispatched is based on whether the resource

was able to alter its output up or down in an economical fashion to balance the Company’s

constantly changing demand requirements.  Further, this portion of the analysis requires

consideration of the viability of the resource technologies available to the Company.  This step

identifies the risks that technology investment could create for the Company and its customers, such

as site identification, development, infrastructure, and fuel procurement risks.  

The feasibility of both conventional and alternative generation resources is considered in utility‐

grade projects based on capital and operating expenses including fuel, operation and maintenance.  

Figure 5.1.3.1 summarizes the resource types that the Company reviewed as part of the 2014 Plan.  
68

Those resources considered for further analysis in the busbar screening model are identified in the

final column.  

Figure 5.1.3.1 ‐ Alternative Supply‐Side Resources

The resources not included as busbar resources for further analysis faced barriers such as the

feasibility of the resource in the Company’s service territory, the stage of technology development,

and the availability of reasonable cost information.12  Although such resources were not considered

in this 2014 Plan, the Company will continue monitoring all utility‐scale technologies.  The

Company is committed to using reliable technologies at reasonable and prudent costs that best meet

the energy needs of customers.  

5.2 LEVELIZED BUSBAR COSTS

The Company’s busbar model was designed to estimate the levelized busbar costs of various

technologies on an equivalent basis.  The busbar results show the levelized cost of power generation

at different capacity factors and represent the Company’s initial quantitative comparison of various

alternative resources.  These comparisons include: fuel, heat rate, emissions, variable and fixed

operation and maintenance (“O&M”) costs, expected service life, and overnight construction costs.

Figures 5.2.1 and 5.2.2 display summary results of the busbar model comparing the economics of the

different technologies discussed in Sections 5.1.1 and 5.1.2.  The results were separated into two

figures because non‐dispatchable resources are not equivalent to dispatchable resources for the

energy and capacity value they provide to customers.  For example, dispatchable resources are able

to generate when power prices are the highest, while non‐dispatchable resources may not have the

                                                       

12 Please see www.epri.com for more information on confidence ratings.

Resource Unit Type Dispatchable Primary Fuel

Busbar

Resource

Battery/Pumped Storage Intermediate Yes Varies No

Biomass Baseload Yes Renewable Yes

CC 3x1 Intermediate/Baseload Yes Natural Gas Yes

CFB Baseload Yes Coal No

Coal (SCPC) w / CCS Intermediate Yes Coal Yes

Coal (SCPC) w /o CCS Baseload Yes Coal Yes

CT Peak Yes Natural Gas Yes

Fuel Cell Baseload Yes Natural Gas Yes

Geothermal Baseload Yes Renewable No

Hydro Power Intermittent No Renewable No

IGCC CCS Intermediate Yes Coal Yes

IGCC w /o CCS Baseload Yes Coal Yes

Nuclear Baseload Yes Uranium Yes

Offshore Wind Intermittent No Renewable Yes

Onshore Wind Intermittent No Renewable Yes

Solar PV Intermittent No Renewable Yes

Solar Tag Intermittent No Renewable Yes

Tidal & Wave Power Intermittent No Renewable No
69

ability to do so.  Furthermore, non‐dispatchable resources typically receive less capacity value for

meeting the Company’s reserve margin requirements.  

Figure 5.2.1 ‐ Dispatchable Levelized Busbar Costs (2019 COD)

Figure 5.2.2 ‐ Non‐Dispatchable Levelized Busbar Costs (2019 COD)

Appendix 5A contains the tabular results of the screening level analysis.  Appendix 5B displays the

heat rates, fixed and variable operations expenses, maintenance expenses, expected service lives,

estimated 2014 real dollar construction costs, and the first year economic carrying charge.

$‐

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

$1,800

$2,000

$2,200

$2,400

$2,600

$2,800

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

$/kW‐YEAR

Capacity Factor

IGCC w/CCS

SCPC w/CCS

FUEL CELL

BIOMASS

NUCLEAR

CT 3X1 CC

SCPC without CCS

IGCC without CCS

$‐

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

$1,800

$2,000

$2,200

$2,400

$2,600

$2,800

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

$/kW‐YEAR

Capacity Factor

OFF SHORE WIND

ON SHORE WIND

SOLAR TRACKING

SOLAR TAG

SOLAR FIXED TILT
70

In Figure 5.2.1, the lower portion of the combined curves represents the lowest cost of all units at an

associated operating capacity factor range between 0% and 100%.  Resources with busbar costs

above the combined curves generally fail to move forward in the resource optimization.  Figures

5.2.1 and 5.2.2 allow comparative evaluation of resource types.  The cost curve at 0% capacity factor

depicts the amount of invested total fixed cost of the unit.  The slope of the unit’s cost curve

represents the variable cost of the unit, including fuel, emissions, and any REC or Production Tax

Credit (“PTC”) value a given unit may receive.  

Figure 5.2.1 shows that CT technology is currently the most cost‐effective option at capacity factors

less than approximately 25% for meeting Company’s peaking requirements.  Currently, the CC 3x1

technology is the most economical option for capacity factors greater than approximately 25% and,

therefore, is an economical way for the Company to meet its energy and capacity requirements.  

Nuclear units have higher total life‐cycle costs than a CC 3x1; however, they operate historically at

higher capacity factors and have relatively more stable fuel costs and operating costs generally.  Fuel

also makes up a smaller component of a nuclear unit’s overall and operating costs than is the case

with fossil fuel‐fired units.  Nuclear power provides fuel diversity and enhances price stability and

reliability.  New coal generation facilities without CCS technology will not meet the emission

limitation included in the EPA’s GHG NSPS rule for new electric generating units.   

A direct comparison between dispatchable and non‐dispatchable resources on the same busbar

curve is not appropriate due to the intermittent production, the limited dispatchability, and the

lower dependable capacity ratings associated with non‐dispatchable resources.  Wind and solar

plants produce less energy at peak demand periods, therefore more capacity would be required to

maintain the same level of reliability.  For example, onshore wind provides only 13% of its

nameplate capacity as firm capacity that is available to meet the Company’s PJM resource

requirements as described in Chapter 4.  Figure 5.2.2 displays the non‐dispatchable resources that

the Company considered in its busbar analysis.  Based on this analysis, the economic order for these

non‐dispatchable resources is: solar tag, solar PV, onshore wind, and offshore wind.  The Company

is routinely updating and evaluating the costs and availability of renewable resources, as discussed

in Section 5.4.  See Figure 5.2.3 for a summary and explanation of non‐dispatchable renewable

resource nameplate and firm capacities considered in the busbar analysis.

Figure 5.2.3 ‐ Renewable Capacity Summary  

 

Figure 5.2.4 identifies some basic capacity and energy differences between dispatchable resources

and non‐dispatchable resources.

Resource Type Nameplate Firm Capacity

Onshore Wind 247 32

Offshore Wind 504 84

Solar PV 520 197

Solar Tag 39 15

Solar Partnership Program 12.9 3.7
71

Figure 5.2.4 ‐ Comparison of Resources by Capacity and Annual Energy

The assessment of alternative resource types and the busbar screening process provides a simplified

foundation in selecting resources for further analysis.  However, the busbar curve is static in nature

because it relies on an average of all of the cost data of a resource over its lifetime.  Further analysis

was conducted in Strategist to incorporate seasonal variations in cost and operating characteristics,

while integrating new resources with existing system resources.  This analysis more accurately

matched the resources found to be cost‐effective in this screening process.  This simulation analysis

resulted in selecting the type and timing of additional resources that economically fit the Company’s

current and future needs.  

5.3 GENERATION UNDER DEVELOPMENT

North Anna 3  

The Company is in the process of developing a new nuclear unit, North Anna 3, at its existing North

Anna Power Station located in Louisa County in central Virginia, subject to obtaining all required

approvals.13 The Company has recently re‐assessed the overall schedule for completion of North

Anna 3.  This re‐assessment includes obtaining the COL, the SCC Rider Application process, and

construction of the facility.  Given this schedule re‐assessment, it is now determined that the earliest

possible in‐service date for North Anna 3 is September 2027, with capacity being available to meet

the Company’s 2028 summer peak.  The Company has not committed to build North Anna 3 and

will not make a final decision until after the issuance of the COL.  However, the Company continues

to develop the project actively, given the proven operational, economic, and environmental benefits

of nuclear power, and to assure that this supply‐side resource option remains available to its

customers.

The technology selection for North Anna 3 is GEH’s ESBWR nuclear technology, which is consistent

with the 2013 Plan.  In July 2013, the Company submitted a revised COL application to the NRC to

reflect the change in technology from the Mitsubishi Heavy Industries Advanced Pressurized Water

Reactor that was identified in the 2012 Plan.  This decision was based on a continuation of the

competitive procurement process that began in 2009 to find the best solution to meet its need for

future baseload generation.  Since 2009, GEH has continued to refine its design and has made

                                                       

13 Originally, Old Dominion Electric Cooperative (“ODEC”), part owner of North Anna Units 1 and 2, was also a participant in the

development of North Anna 3 but informed the Company of its intent to no longer participate in February 2011.  On January 30, 2013, the

NRC approved the transfer of ODEC’s interest to the Company.

Resource Type

Nameplate

Capacity

(MW)

Firm

Capacity

(MW)

Estimated

Capacity Factor

(%)

Estimated

Annual Energy

(MWh)

Onshore Wind 1,000 130 42% 3,679,200                  

Offshore Wind 1,000 167 42% 3,679,200                  

Solar PV 1,000 380 21% 1,839,600                  

Nuclear 1,000 960 95% 8,322,000                  

Combined Cycle (3x1) 1,000 970 70% 6,132,000                  

Combustion Turbine 1,000 986 10% 876,000                      
72

significant progress toward obtaining federal approval.  In addition, GEH and its consortium

partner Fluor Enterprises, Inc. (“Fluor”) provided contract enhancements that are expected to benefit

customers and stakeholders over the new unit’s planned 60‐year life.   

The Company expects to receive the COL in 2016 and intends to maintain the development option of

North Anna 3 for several key reasons.  First, North Anna 3 will provide much needed baseload

capacity to the region in the latter portion of the Planning Period while enhancing system reliability.  

Additionally, nuclear units are near emission‐free generation.  Next, North Anna 3 will enhance fuel

diversity within the Company’s generation portfolio, which will in turn, promote fuel price stability

for customers.  Finally, as shown in Figure 5.2.1, nuclear power is the lowest cost large‐scale

dispatchable baseload generating alternative to natural gas.

Combined‐Cycle

The Company is currently in the early stage of development of a natural gas‐fueled CC facility.  This

facility is being developed for commercial operations prior to the summer of 2019.

Onshore Wind

The Company continues to pursue onshore wind development; however, there is a limited amount

of onshore wind available within or near the Company’s service territory.  Only three feasible sites

have been identified by the Company for consideration of onshore wind facilities.  These sites are

located in Virginia mountaintop locations.

Offshore Wind

The Company continues to pursue offshore wind development.  A complete discussion of these

efforts is included in Section 5.4.

Solar PV

Pursuant to Chapter 771 of the 2011 Virginia Acts of Assembly (House Bill 1686), the Company

received SCC approval in March 2013 for a solar DG demonstration program with two components:  

(1) the Solar Partnership Program for up to 13 MW of Company‐owned solar DG (further discussed

in Section 3.1.5); and (2) the Solar Purchase Program, a tariff allowing the Company to purchase up

to 3 MW of energy output from customer‐owned solar DG.  Several utility‐scale Company‐owned

PV installations are under preliminary development.  This includes two solar tags to a generation

site and several greenfield solar PVs.

Solar Purchase Program

The SCC approved the Company’s Solar Purchase Program, by which the Company purchases

energy from qualifying residential and non‐residential solar customer‐generators at a fixed price of

15 cents per kWh under Rate Schedule SP, a voluntary experimental rate, for a period of five years.

Rate Schedule SP is designed to facilitate installation of up to 3 MW of customer‐owned solar DG

(up to 1.8 MW residential and up to 1.2 MW non‐residential) as an alternative to net energy

metering by allowing the Company to purchase 100% of the energy output, including all

environmental attributes and associated RECs, from qualifying solar customer‐generators.  The 15
73

cents per kWh price paid under Rate Schedule SP includes an avoided energy cost component and a

voluntary environmental contribution component provided by those customers participating in the

Company’s Green Power® program. 

Figure 5.3.1 ‐ Generation under Development1

Notes: 1) All Generation under Development projects and capital expenditures are preliminary in nature and subject to regulatory and/or

Board of Directors approvals.

Appendix 5C provides the in‐service dates and capacities for generation resources under

development.

5.4 EMERGING AND RENEWABLE ENERGY TECHNOLOGY DEVELOPMENT

The Company conducts technology research in the renewable and alternative energy technologies

sector, participates in federal and state policy development on alternative energy initiatives, and

identifies potential alternative energy resource and technology opportunities within the existing

regulatory framework for the Company’s service territory.  The Company is actively pursuing the

following technologies and opportunities.

Research and Development Initiatives – North Carolina

NCGS § 62‐133.8(h) allows North Carolina utilities to recover up to $1,000,000 per year through a

REPS rider for research that encourages the development of renewable energy, energy efficiency, or

improved air quality.  Pursuant to this law, the Company developed a microgrid demonstration

project at its Kitty Hawk District Office in North Carolina.  The microgrid project includes

innovative distributed renewable generation and energy storage technologies.  A microgrid, as

defined by the DOE, is a group of interconnected loads and distributed energy resources within

clearly defined electrical boundaries that acts as a single controllable entity with respect to the grid,

Summer Winter

2017 Solar VA Renewable Intermittent                               40                   15                    15

2017 Solar Tag VA Renewable Intermittent 4                                                     2                    2

2018 Solar VA Renewable Intermittent 40                                                15                   15

2018 Offshore Wind Demonstration Project VA Wind Intermittent 12                                                   2                    2

2019 Combined Cycle VA Natural Gas Intermediate/Baseload 1,566                                     1,566            1,614

2019 Solar VA Renewable Intermittent 40                                                15                  15

2020 Solar VA Renewable Intermittent 40                                                15                   15

2020 Solar Tag VA Renewable Intermittent 35                                                13                  13

2021 Solar VA Renewable Intermittent 40                                                15                   15

2022 Wind 1 VA Renewable Intermittent 120                                             16                  16

2022 Solar VA Renewable Intermittent 40                                                15                   15

2023 Wind 2 VA Renewable Intermittent 81                                                10                  10

2023 Solar VA Renewable Intermittent 40                                                15                   15

2024 Wind 3 VA Renewable Intermittent 46                                                   6                    6

2024 Solar VA Renewable Intermittent                               40                   15                    15

2025 Solar VA Renewable Intermittent 40                                                15                  15

2026 Solar VA Renewable Intermittent 40                                                15                   15

2027 Solar VA Renewable Intermittent 40                                                15                  15

2028 North Anna 3                                                  Mineral, VA Nuclear Baseload 1,453                                     1,453            1,514

2028 Solar VA Renewable Intermittent 40                                                15                  15

2029 Solar VA Renewable Intermittent 40                                                15                   15

Nameplate

Capacity (MW)

Forecasted Capacity (Net MW)

COD Unit Location Primary Fuel Unit Type
74

allowing it to operate in grid‐connected or island‐mode.  The project includes four different types of

micro‐wind turbines, a solar PV array, and a lithium‐ion battery integrated behind‐the‐meter with

the existing on‐site diesel generator and utility feed.  The Company completed construction of the

microgrid project in July 2014.  The Company also plans to integrate a small, residential‐sized fuel

cell into the microgrid project in 2015, in order to stud the fuel cell’s interaction with other

renewable energy technologies in a microgrid environment.

Research and Development Initiatives ‐ Virginia

A 2012 revision to Va. Code § 56‐585.2 resulting from HB 1102 and SB 413, legislation passed by the

2012 General Assembly at the request of the Governor, allows utilities that are participating in

Virginia’s RPS program to meet up to 20% of their annual RPS Goals using RECs issued by the SCC

for investments in renewable and alternative energy research and development activities.  Pursuant

to § 56‐585.2, the Company is currently partnering with 11 institutions of higher education on

Virginia renewable and alternative energy research and development projects.  The Company filed

its first annual report in March, 2014, analyzing the prior year’s PJM REC prices and quantifying its

qualified investments to facilitate the SCC’s validation and issuance of RECs for Virginia renewable

and alternative energy research and development projects.  In a June 2014 order entered in Case No.

PUE‐2014‐00056, the SCC issued the RECs quantified in the March 2014 report.   

Offshore Wind

The Company is actively participating in offshore wind policy and technology development in order

to identify ways to advance offshore wind responsibly and cost‐effectively.  

The Company bid $1.6 million on September 4, 2013, winning the lease for 112,800 acres of federal

land off the coast of Virginia to develop a commercial offshore wind turbine facility capable of

generating up to 2,000 MW of electricity, enough for 500,000 homes.

The Company is actively developing the Virginia commercial Wind Energy Area (“WEA”) and

plans to meet BOEM’s timetable for commercial development, including submittal of the site

assessment plan on May 1, 2014; submitting a construction and operations survey plan by

November 1, 2014; completing high‐resolution geophysical surveys by November 1, 2016; and

submitting a construction and operations plan by November 1, 2018.
75

Figure 5.4.1 ‐ Virginia Wind Energy Area

 

The Company also submitted a response to the BOEM Call for Information in North Carolina in

February 2013, and is evaluating the potential for a project off the coast of that state.  The Call for

Information by BOEM is the first step in the commercial offshore wind leasing process.  BOEM has

defined three Wind Energy Areas (“WEA”) offshore North Carolina.  The three Call Areas are

comprised of approximately 55 Outer Continental Shelf blocks, totaling approximately 307,000

acres.  One area is located 24 nautical miles offshore Kitty Hawk, and two areas are located 12 and

15 nautical miles offshore southern Wilmington.  The Company’s response focused on the

northernmost Call Area adjacent to Kitty Hawk.  Since multiple parties responded to the Call for

Information, the Company expects there will be a competitive auction for lease blocks in the future.

Offshore wind has the potential to provide the largest source of renewable generation for North

Carolina and Virginia; however, offshore wind is significantly more expensive compared to other

renewable generation alternatives as seen in Figure 5.2.2.  The Company is actively working to

evaluate ways to reduce the cost of offshore wind energy through two DOE funding awards.  The

DOE awarded the Company and its partners a $500,000 grant in 2011 to identify the impact of

innovative technologies on reducing the levelized cost of offshore wind energy relative to a baseline.  

The grant team brings together the expertise of several partners, including the Company, a wind

turbine manufacturer (Alstom), a federally‐funded research and development center (National

Renewable Energy Laboratory), a maritime planning and engineering firm (Moffatt & Nichol), and a

state university (Virginia Polytechnic Institute and State University).  This grant project is currently

underway and is scheduled to be complete in 2014.

VOWTAP was among seven projects selected by the DOE in 2012 for a $4 million award supporting

preliminary engineering, design, and permitting for a proposed offshore wind facility.  In May 2014,

the DOE announced that VOWTAP was one of three projects selected – out of seven finalists – for up

to an additional $47 million in federal funding to support final design, permitting, and construction.  

The VOWTAP consists of the Company as the project owner and operator, and its core Team ‐ 

Alstom; KBR; Keystone Engineering, Inc.; DMME; NREL; the Virginia Coastal Energy Research

Consortium represented by Virginia Polytechnic Institute and State University; Tetra Tech, Inc.; and

NNS.  Several other vendors and consultants are providing development support.
76

The primary objective of VOWTAP is to advance the offshore wind industry in the United States by

demonstrating innovative technologies and process solutions that will establish offshore wind as a

cost‐effective renewable energy resource.  The VOWTAP Team will design, construct, and operate a

12 MW offshore wind facility located approximately 24 nautical miles (27 statute miles) off the coast

of Virginia.   The Project consists of two 6 MW Alstom model HaliadeTM 150 turbines mounted on

inward battered guide structures (“IBGS”), and combined with other significant innovations to

make this a world‐class demonstration facility (Figure 5.4.2).  Subject to receiving applicable

regulatory approvals, VOWTAP is targeted to go into operation by the end of 2017.  The Company,

as the leaseholder of the WEA, anticipates its experience and knowledge gained through VOWTAP

will be applicable to its ongoing commercial‐scale offshore wind development.

Figure 5.4.2 ‐ Project Overview

Demonstrating its support for offshore wind off the coast of Virginia, the 2011 General Assembly

established a goal of developing 3,000 MW (nameplate) of offshore wind by 2025.  Moreover, the

General Assembly made it the policy of the Commonwealth that offshore wind development costs,

especially VOWTAP, are in the public interest.  Furthermore, the Virginia General Assembly passed

legislation in 2010 that created the Virginia Offshore Wind Development Authority (ʺVOWDAʺ) to

help facilitate offshore wind energy development.  The Company is represented on the executive

committee of VOWDA by an appointee of the Governor of Virginia.  As required by the 2010

legislation, the Company completed a transmission study to determine possible offshore wind

interconnection points to the onshore transmission grid.  The Company released the results of the

study in December 2010, which found that Virginia has an advantage compared to many states

because it has the capability to interconnect large scale wind generation facilities with the existing

grid in Virginia Beach, Virginia.  The study revealed that up to 4,500 MW (nameplate) of offshore

wind generation can be connected with minimal onshore transmission upgrades.  The Company

completed a second study in 2012, evaluating offshore transmission options to potentially support

multiple projects.  The study found that for every 500 ‐ 700 MW (nameplate) of offshore wind

capacity constructed, one service platform is appropriate with two lines to shore.  This transmission
77

solution limits the potential for stranded transmission investment and emphasizes the potential cost

savings that may be achieved through a phased build‐out, with a potential for standardization of

offshore transmission infrastructure.  

The Company is also a member of the Virginia Offshore Wind Coalition (“VOW”).  The VOW is an

organization comprised of developers, manufacturers, utilities, municipalities, businesses, and other

parties interested in offshore wind.  This group advocates on the behalf of offshore wind

development before the Virginia General Assembly and with the Virginia delegation to Congress.   

EV Initiatives

Various automotive original equipment manufacturers (“OEMs”) have released EVs for sale to the

public in the Company’s service territory.  The Chevrolet Volt, General Motorʹs first plug‐in hybrid

electric vehicle (“PHEVʺ), and the Nissan Leaf, an all‐electric vehicle, became available for sale in the

Company’s Virginia service territory in 2011.  Since that time, the Company has monitored the

introduction of EV models from several other OEMs in its Virginia service territory.  These include,

but are not limited to, the Toyota Prius, the Ford Focus Electric and C‐Max Hybrid Energi, the Tesla

Roadster and Model S, Model X, the Honda Fit EV, and the Mitsubishi i‐MIEV.  While the overall

penetration of EVs has been somewhat lower than anticipated, recent registration data from the

Virginia Department of Motor Vehicles demonstrates growth during last year.  Sales of EVs and

PHEVs have initially followed the historical adoption patterns of hybrid vehicles, and the Company

expects this trend to continue.  In the 2014 Plan, the Company used data from the Virginia

Department of Motor Vehicles, Electric Power Research Institute (“EPRI”) and Polk Automotive to

develop a projection of system level EV and PHEV penetrations across its service territory.  

The Company developed load shapes to evaluate potential capacity and energy impacts of EVs and

PHEVs on its system.  The Company projects approximately 241,000 EVs and PHEVs will be on the

road in 2029, which would equate to approximately 215 MW of additional potential load and an

additional annual energy usage of 853 GWh from EV charging.  To encourage customers to charge

EVs during off‐peak hours to avoid potentially adverse grid impacts, the Company launched an EV

Pilot Program in Virginia in October 2011 offering experimental and voluntary EV rate options to

encourage customers to charge their EVs during off‐peak periods.  These rate options are further

discussed in Section 3.2.3.  

Smart Grid Impacts

For the purposes of this 2014 Plan, the Company is providing information on smart grid

technologies that impact demand and energy savings.  The Company has projected potential

demand and energy savings associated with voltage conservation.  The technology that enables

voltage conservation is AMI.   

  

The Company’s installation of AMI began in 2009.  To date, the Company has installed over 260,000

smart meters in areas throughout Virginia.  The AMI system includes network and backbone

communication, IT infrastructure, and meters, which are all used to support the two‐way

communication.    
78

Over the next five years, the Company will continue to install AMI infrastructure.  The Company’s

AMI system provider is Silver Spring Networks (“SSN”).  The SSN system uses network access

points (routers) to collect the data and periodically transfers the data to the Company’s head‐end

system via a secure cellular network.  The routers are strategically placed in the field to ensure

information is passed from its source to its destination as quickly and efficiently as possible.  The

mesh network provides the ability to upgrade metering software and update firmware over the air.  

Instead of performing a meter exchange, the updates are completed over the airwaves.  The head‐

end system collects the information from the meters and is typically a system supported by the AMI

system provider.  The head‐end system collects data such as usage information, voltage readings

and provides alarms.  In addition, the Company utilizes a Meter Data Management (“MDM”)

system.  This system utilizes the usage data collected by the head‐end system and develops

information needed for the Customer Information System (“CIS”).  

The Company has projected potential demand and energy savings associated with voltage

conservation as a DSM program as part of its IRP process.  The objective of this program is to

conserve energy by reducing voltage for residential, commercial and industrial customers served

within the allowable band of 114 to 126 volts at the customer meter (for normal 120‐volt service)

during off‐peak hours.  The program is enabled through the deployment of AMI, which provides 15‐

minute voltage information from the meter.  Please refer to Appendices 5G through 5J for system

level information.   

Figure 5.4.3 provides an estimate of the timing and level of AMI infrastructure deployment in North

Carolina.  Energy impacts will be evident approximately one year following deployment and

implementation of voltage conservation.  This provides an indication of the energy impacts on a

North Carolina retail jurisdictional basis.  Impacts on a North Carolina retail customer class basis are

not currently available.

Figure 5.4.3 – AMI Infrastructure in North Carolina

If the Company chooses not to implement voltage conservation as a system‐wide DSM program, the

demand and energy savings in Appendices 5G ‐ 5I would not be achieved.  The Company will

Year Percentage of Meters

in NC

2015 0.0%

2016 0.0%

2017 0.0%

2018 0.0%

2019 0.0%

2020 0.0%

2021 2.2%

2022 1.9%

2023 1.6%

2024 5.0%

2025 5.0%

2026 5.0%
79

include an evaluation, measurement, and verification plan when approval is requested for voltage

conservation as a DSM program.  

5.5 FUTURE DSM INITIATIVES

The Company is committed to offering cost‐effective DSM programs in its North Carolina and

Virginia service territories in order to meet customers’ needs and improve the environment.  The

Company has developed relationships with third‐party vendors to assist in evaluating and

implementing programs approved by the Commission(s).  

The Company initiated its SRP in 2010.  Suggestions received during this process were included in

developing the proposed and future DSM initiatives included in this 2014 Plan.  The Company plans

to hold its next SRP in November 2014.

When potential programs are identified as possible DSM resources, the Company’s analysis of

future DSM programs begins with a screening process that determines whether a DSM program

warrants further evaluation.  If a DSM program passes the initial screening, the Company works

with industry experts to acquire modeling assumptions for that program.  Next, the programs are

evaluated using the Strategist model with respect to the four cost/benefit tests discussed in

Appendix 5D.  While these cost/benefit tests are a key component of the Company’s analysis, it also

considers stakeholder impacts, the potential for achieving a high level of acceptance by customers,

and the potential for energy and demand reductions.  The Company modeled the demand‐side

resources over the Study Period, including input variables from many sources.  These projections

were based on the best available information, including industry data acquired from experience the

Company has gained by working with program design vendors, stakeholders and DSM

implementation vendors, which validated the DSM program design parameters.  Appendix 5E

provides the estimated annual energy savings for all DSM programs included in the 2014 Plan.  

The Company has developed five incremental phases of DSM programs since 2008 and will continue

to work with consultants to develop and evaluate any additional programs for the North Carolina

and Virginia service territories that meet the Company’s cost/benefit test criteria.  The Company also

has DNV GL under contract to provide EM&V analysis for all of the Company’s approved

programs.  Data gathered from the EM&V activity is used to update capacity and energy impacts,

projected customer penetration levels for the DSM programs, and adjust market potential in the

future.  The Company works closely with its consultants on a regular basis to update existing

program designs and modeling assumptions.   

In order to identify more DSM programs, the Company initiated a DSM Market Potential Study

(“DSM Potential Study”) with DNV GL in 2013 and plans to share results with stakeholders at the

next SRP meeting, scheduled in November 2014.  The DSM Potential Study consists of three phases.  

Phase I is the appliance saturation survey, which was sent to a representative sample of Residential

and Commercial customers within the Company’s service territory to assess the number of

appliances within households and businesses, respectively.  This survey was completed at the end of

2013.  Phase II is the conditional demand analysis which effectively develops a model to accurately

identify the key end‐use drivers of energy consumption for the Company’s residential customers.  

This study was completed in May 2014.  Phase III starts by developing the baseline energy usage for
80

all appliances within the residential and commercial sectors by building type.  The baseline analysis

is followed by the technical, economic, and achievable market potential of energy savings for all

measures in the Company’s residential and commercial sectors.  The technical market potential

reflects the upper limit of energy savings assuming anything that could be done is done.  Similarly,

the economic potential reflects the upper limit of energy savings potential from all cost‐effective

measures.  The achievable potential reflects a more realistic assessment of energy savings by

considering what measures can be cost‐effectively implemented through a future program.   The

result is a list of cost‐effective measures that can ultimately be evaluated for use in future program

designs and a high level estimate of the amount of energy and capacity savings still available in the

Company’s service territory.    

5.5.1 STANDARD DSM TESTS

To evaluate DSM programs, the Company utilized four of the five standard tests from the California

Standards Practice Manual.  Based on the NCUC and the SCC findings and rulings in the

Company’s North Carolina DSM proceedings (Docket No. E‐22 Subs 463, 465, 466, 467, 468, 469, 495,

496, 497, 498, 499, and 500), and the Virginia DSM proceedings (Case Nos. PUE‐2009‐00023, PUE‐

2009‐00081, PUE‐2010‐00084, PUE‐2011‐00093, PUE‐2012‐00100, and PUE‐2013‐00072), the

Company’s future DSM programs are evaluated on both an individual and portfolio basis.

In the 2013 Plan and going forward, the Company made changes to its DSM screening criteria in

recognition of the Virginia General Assembly’s guidance through the 2012 Legislation that a

program “shall not be rejected based solely on the results of a single test.”  The Company has

adjusted the requirement that the TRC score be 2.0 or better when the RIM test is below 1.0 and the

Utility Cost and Participant tests have passing scores.  The Company will now consider including

DSM programs that have passing scores (cost/benefit scores above 1.0) on the Participant, Utility and

TRC tests.  This change will allow the Company to accomplish two objectives.  It will allow the

Company to propose additional DSM programs, ones that may fail the RIM test but have passing

scores on the other three tests.  Approval by the SCC of the new programs will allow the Company

to help the Commonwealth meet its 10% energy reduction target by 2022.  Also, by passing the UCT

test, the Company will be able to propose, and if approved, have programs which help the

Company reduce its overall future revenue requirement, which will benefit all customers.

Although the Company uses these criteria to assess DSM programs, there are circumstances that

require the Company to deviate from the aforementioned criteria and evaluate certain programs

which do not meet these criteria on an individual basis.  These DSM Programs serve important

policy and public interest goals, such as that recognized by the NCUC in approving the Low Income

Program in Docket No. E‐22, Sub 463, and by the SCC in Case No. PUE‐2009‐00081.

5.5.2 FUTURE DSM PROGRAMS

As part of the IRP process, the Company evaluated possible future DSM programs in North

Carolina and Virginia, referred to herein as “future programs.”  These programs have met the

Company’s evaluation criteria for inclusion in the 2014 Plan as described in Section 5.5.1.  Appendix

5F includes a brief description of each potential future DSM program.  Appendices 5G, 5H, 5I, and 5J

provide the non‐coincidental peak savings, coincidental peak savings, energy savings, and
81

penetrations, respectively, for each future program.  Currently, the Company plans for programs to

be proposed in North Carolina after approval in Virginia.  

5.5.3 FUTURE DSM PROGRAMS’ COST‐EFFECTIVENESS RESULTS

The Company performs individual cost/benefit tests on each future DSM program.  These results

were used to determine if a program should be included as a future DSM program in this 2014 Plan.  

The Company believes this evaluation is consistent with the guidance provided by the NCUC and

the SCC and legislation and regulations in both states.  Figure 5.5.3.1 provides the future DSM

programs’ individual cost/benefit results and projected cumulative demand and energy reductions

by 2029.

Figure 5.5.3.1 ‐ Future DSM Individual Cost‐Effectiveness Results

The Company also performed a portfolio evaluation to ensure that each DSM program passed the

cost/benefit tests as a portfolio of programs.  It is important to consider the portfolio results since all

resources available to meet or reduce load are considered together.  It is also important to examine

the portfolio run, which includes incremental common costs.  Common costs are expenses that

cannot be directly tied to any individual program but are incurred based on program start‐up and

general implementation costs for the collective DSM Program offerings.  The common costs are

included in the portfolio run to ensure the addition of these expenses does not alter the overall cost‐

effectiveness of the portfolio.

Figure 5.5.3.2 provides the future DSM portfolio’s cost/benefit results and projected demand and

energy reductions.  

Figure 5.5.3.2 ‐ Future DSM Portfolio Cost‐Effectiveness Results

5.5.4 REJECTED DSM PROGRAMS  

The Company has evaluated a wide variety of DSM programs for both the residential and non‐

residential sectors.  During the planning process, the Company screens programs that do not meet

the Company’s planning criteria.  Rejected programs may be re‐evaluated for inclusion in future

DSM portfolios, pending the outcome of the DSM Potential Study noted above.

A list of IRP rejected programs from prior IRP cycles is shown in Figure 5.5.4.1.  

Program Participant Utility TRC RIM

2029 MW

Reduction

2029 GWh

Reduction

Voltage Conservation Program N/A 2.39 2.39 0.50 0 1,916

Non Residential Custom Incentive 2.15 1.87 1.45 0.70 74 289

Program Participant Utility TRC RIM 2029 MW

Reduction

2029 GWh

Reduction

Voltage Conservation Program N/A 2.39 2.39 0.50 0 1,916

Non Residential Custom Incentive 2.15 2.03 1.57 0.76 74 289

Portfolio Results 12.25 2.30 2.14 0.54 74 2,206
82

Figure 5.5.4.1‐ IRP Rejected DSM Programs

Note: * Alternative Redesigned Program under consideration.

As part of this IRP, the Company has also decided not to pursue the following programs at this time:  

Program:  Cool Roof

Recommended Status:  Reject

As designed, the program would provide an incentive to retailers to present information about

lighter color roofing material to customers, with the information focused on the fact that lighter

colored material is essentially the same cost, but can save energy in some situations.  The use of

lighter color roofing material reduces energy consumption in the summer but can increase energy

use in the winter, causing the net energy savings to be minimal.  The outcome of this balance is

further complicated by the degree to which HVAC ducting is located in non‐conditioned space.  

Since the net energy savings and program benefit are minimal, it is not possible to provide an

appreciable financial incentive directly to customers.  The current program design does not include

any incentive directly to customers.  Because the benefits of this program are mixed and the ability

to provide a financial incentive is minimal, this program is recommended for rejection at this time.

   

Program:  Non‐Residential Data Centers

Recommended Status:  Reject

The latest data center program design would primarily provide incentives for enhancements to

cooling dedicated data center / data room facilities.  Larger data centers which tend to have high

levels of electrical demand would be either exempt from participation in the program or within a

size category that would allow them to opt‐out of participation in energy efficiency programs.  For

Program

Non‐Residential HVAC Tune‐Up Program

Non‐Residential Curtailable Service Program

Energy Management System Program

ENERGY STAR® New Homes Program

Geo‐Thermal Heat Pump Program

Home Energy Comparison Program

Home Performance with ENERGY STAR® Program

In‐Home Energy Display Program

Premium Efficiency Motors Program

Programmable Thermostat Program

Residential Refrigerator Turn‐In Program*

Residential Solar Water Heating Program

Residential Water Heater Cycling Program

Residential Comprehensive Energy Audit Program

Residential Radiant Barrier Program

Residential Lighting (Phase II) Program

Non‐Residential Refrigeration Program

Cool Roof Program

Non‐Residential Data Centers Program

Non‐Residential Re‐commissioning
83

this reason, participation in, and energy savings resulting from, a data center program would be

limited.  Measures for which incentives would be provided within the current data center program

design may be more appropriate for a custom measure program or as individual measures in the

Non‐Residential HVAC program.

Program:  Non‐Residential Re‐commissioning

Recommended Status:  Reject

The current program design for building re‐commissioning envisions a top‐to‐bottom engineering

review of a building’s energy consuming systems, re‐tuning of the systems and detailed

recommendations for enhancements as appropriate.  Because of the expense of re‐commissioning, it

is expected that this program would have limited appeal to customers.  A number of the buildings

for which re‐commissioning would be appropriate would have electrical demand levels that would

cause the customer to be either exempt from participation in the program or within a size category

that would allow them to opt‐out of participation in energy efficiency programs.  Due to the

expected low participation and high cost per customer, the building re‐commissioning program

design is recommended for rejection at this time.

In addition to the rejected programs listed in Figure 5.5.4.1, the Company evaluated the Curtailable

Service Program and found that this program does not meet the Company’s cost‐benefit criteria.  A

description of the program and explanation for rejection is listed below:

Program:  Non‐Residential Curtailable Service  

Recommended Status: Reject

Target Class:     Commercial and Industrial

NC Program Type: Peak Shaving

VA Program Type: Peak Shaving

NC Duration     2016 – 2039

VA Duration     2015 – 2039

Program Description:

In this program, a third‐party vendor would solicit customers who agree to reduce load during

curtailment events.  The vendor would operate the programs and monitor peak load reductions

produced during curtailment events.

Reason for Program Rejection:

The Curtailable Service Program was found not to be cost‐effective at this time.

5.5.5 REJECTED DSM PROGRAMS’ COST‐EFFECTIVENESS RESULTS

The cost‐effectiveness results for the Curtailable Service Program are provided in Figure 5.5.5.1.  
84

Figure 5.5.5.1‐ Curtailable Service Program

5.5.6 NEW CONSUMER EDUCATION PROGRAMS

Future promotion of DSM programs will be through methods that raise program awareness as

currently conducted in North Carolina and Virginia.

5.5.7 ASSESSMENT OF OVERALL DEMAND‐SIDE OPTIONS  

Figure 5.5.7.1 represents approximately 3,063 GWh in energy savings from the DSM programs at a

system‐level by 2029.   

Figure 5.5.7.1 ‐ DSM Energy Reductions

Figure 5.5.7.2 represents a system coincidental demand reduction of approximately 583 MW by 2029

from the DSM programs at a system‐level.

Participant Utility TRC RIM

Total NPV Benefits 53,427 $               $         73,549 $         73,549 $         73,549

Total NPV Costs $                    ‐ $         93,083 $         34,990 $         94,829

Net Benefits NPV $              53,427 $        (19,534) $         38,559 $       (21,280)

Benefit/Cost Ratio N/A 0 79 2.10 0.78

‐

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029

MWh

Total All

Total Approved/Proposed

Total Future
85

Figure 5.5.7.2 ‐ DSM Demand Reductions

The capacity reductions for the portfolio of DSM programs are higher than the projections in the

2013 Plan.  The total capacity reduction by the end of the planning period was 544 MW for the

portfolio of DSM programs in the 2013 Plan and is 583 MW in the 2014 Plan.  This represents

approximately a 7% increase in demand reductions.  The energy reduction for the DSM programs

was 3,149 GWh in the 2013 Plan and is approximately 3,063 GWh in the 2014 Plan.  This represents a

3% decrease in energy reductions.   

5.5.8   LOAD DURATION CURVES  

The Company has provided load duration curves for the years 2015, 2019, and 2029 in Figures

5.5.8.1, 5.5.8.2, and 5.5.8.3.

‐

100,000

200,000

300,000

400,000

500,000

600,000

700,000

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029

kW

Total All

Total Approved/Proposed

Total Future
86

Figure 5.5.8.1 ‐ Load Duration Curve 2015  

Figure 5.5.8.2 ‐ Load Duration Curve 2019  

5,000

10,000

15,000

20,000

MW

WithoutDSM

With DSM

5,000

10,000

15,000

20,000

MW

WithoutDSM

With DSM
87

Figure 5.5.8.3 ‐ Load Duration Curve 2029  

5.6 FUTURE TRANSMISSION PROJECTS

Appendix 5K provides a list of the Company’s transmission interconnection projects for the

Planning Period with associated enhancement costs.  Appendix 5L provides a list of transmission

lines that are planned to be constructed during the Planning Period.   

5,000

10,000

15,000

20,000

25,000

MW

WithoutDSM

With DSM
88

CHAPTER 6 – DEVELOPMENT OF THE 

INTEGRATED RESOURCE PLAN 

6.1   IRP PROCESS

The IRP process identifies, evaluates, and selects a variety of new resources to meet customers’

growing capacity and energy needs to augment existing resources.  The Company’s approach to the

IRP process relies on integrating supply‐side resources, market purchases, cost‐effective DSM

programs, and transmission options over the Study Period.  This integration is intended to produce

a long‐term plan consistent with the Company’s commitment to provide reliable electric service at

the lowest reasonable cost and mitigate risk of unforeseen market events, while meeting all

regulatory and environmental requirements.  This analysis develops a forward‐looking

representation of the Company’s system within the larger electricity market that simulates the

dispatch of its electric generation units, market transactions, and DSM programs in an economic and

reliable manner.  

The IRP process begins with the development of a long‐term annual peak and energy requirements

forecast.  Next, existing and approved supply‐ and demand‐side resources are compared with

expected load and reserve requirements.  This comparison yields the Company’s expected future

capacity needs to maintain reliable service for its customers over the Study Period.   

A feasibility screening, followed by a busbar screening curve analysis is conducted, as described in

Chapter 5, to determine supply‐side resources and a cost/benefit screening to determine demand‐

side resources that could potentially fit into the Company’s resource mix.  These potential resources

and their associated economics are then incorporated into the Company’s planning model,

Strategist.  The Strategist model then optimizes the quantity, type, and timing of these new resources

based on their economics to meet the Company’s future energy and capacity requirements.  

The next step is to develop a set of alternative plans, which represent plausible future paths

considering the major drivers of future uncertainty.  The Company develops these alternative plans

in order to test different resource strategies against plausible scenarios and sensitivities that may

occur given future market and regulatory uncertainty.  In order to test the plans, the Company

creates several scenarios and sensitivities to measure the strength of each alternative plan as

compared to other plans under a variety of conditions represented by these scenarios and

sensitivities.

During the course of the 2012 and 2013 Plan review proceedings, concerns were raised by

stakeholders and the NCUC and SCC staffs that additional analysis should be conducted to analyze

the costs, benefits and risks of a decision to pick a plan which is not the least cost plan, but provides

the operating cost benefits provided by a more diverse fuel mix.  The Company has agreed that such

an analysis should be conducted and through the 2014 IRP process, the Company has conducted an

initial analysis and study to provide further support and information to “quantify” the value of fuel

diversity and assess the risks associated with each Alternative Plan.  The Company developed a

Portfolio Evaluation Scorecard to provide a quantitative and qualitative measurement system to

further examine the benefits of a more diverse fuel mix than is provided by the Base Plan, which
89

relies primarily on natural gas‐fired generation to meet new capacity and energy needs on the

Company’s system.  The Company intends to refine this analysis in subsequent plans as needed.  

This analysis combines the results of the Strategist net present value (“NPV”) cost results with other

quantitative assessment criteria such as Rate Stability, as evaluated through fuel and construction

cost risk, GHG Emissions and Fuel Supply Concentration.   

                       

The Portfolio Evaluation Scorecard has been applied to each of the Alternative Plans and the results

are presented and discussed in Section 6.6.1.   

Based on the additional analysis provided by the Portfolio Evaluation Scorecard, the Company

finalized its expansion plan recommendations.  These recommendations represent a strategic path

forward that the Company maintains will best meet the energy and capacity needs of its customers

at the lowest reasonable cost over the Planning Period with due quantification, consideration and

analysis of future risks and uncertainties facing the industry, the Company, and its customers.   

6.2 CAPACITY & ENERGY NEEDS  

As discussed in Chapter 2 of this 2014 Plan, over the Planning Period, the Company forecasted

average annual growth rates of 1.4% and 1.3% in peak and energy requirements, respectively, for the

DOM LSE.  Chapter 3 discussed the Company’s existing supply‐ and demand‐side resources, NUG

contracts, generation retirements, and generation resources under construction.  Figure 6.2.1 shows

the Company’s supply‐ and demand‐side resources compared to the capacity requirement,

including peak load and reserve margin.  The area marked as “capacity gap” shows additional

capacity resources that will be needed over the Planning Period in order to meet the capacity

requirement.  The Company plans to meet this capacity gap using a diverse combination of

additional conventional and renewable generating capacity, DSM programs, and market purchases.   
90

Figure 6.2.1 ‐ Current Company Capacity Position (2015 – 2029)

 

Note: The values in the boxes represent total capacity in 2029.

1) Accounts for unit retirements and rating changes to existing units in the Plan, and reflects summer ratings.

2) See Section 4.2.2.

As indicated in Figure 6.2.1, the capacity gap at the end of the Planning Period is significant.  The

Planning Period capacity gap is expected to be approximately 3,600 MW.  If this capacity deficit is

not filled with additional resources, the reserve margin is expected to fall below the required 11.2%

beginning in 2017 and continue to decrease thereafter.  Figure 6.2.2 displays actual reserve margins

from 2014 to 2029.

NUGs

10,000

12,000

14,000

16,000

18,000

20,000

22,000

24,000

26,000

MW

Existing Generation1

Capacity

Gap

Generation

UnderConstruction

Approved DSM

16,519

2,716

3,570

36

425
91

Figure 6.2.2 ‐ Actual Reserve Margin with Existing Resources and  

Generation under Construction

The Company’s PJM membership has given it access to a wide pool of generating resources for

energy and capacity.  However, it is critical that adequate reserves are maintained not just in PJM as

a whole, but specifically in the DOM Zone to ensure that the Company’s load can be served reliably

and cost‐effectively.  Maintaining adequate reserves within the DOM Zone lowers congestion costs,

ensures a higher level of reliability, and keeps capacity prices low within the region.

For modeling purposes, the Company assumed that its existing NUG capacity will be available as a

firm resource in accordance with current contractual terms.  These NUG units also provide energy to

the Company according to their contractual arrangements.  At the expiration of these NUG

contracts, these units will no longer be modeled as a firm capacity resource.  The Company assumed

that NUGs or any other non‐Company owned resource without a contract with the Company are

available to the Company at market prices; therefore, the optimization model’s selection of market

purchases, in lieu of other Company‐owned/sponsored supply‐ or demand‐side resources, would

include these resources.  This is a reasonable planning assumption; however, parties may elect to

enter into future bilateral contracts on mutually agreeable terms.  For potential bilateral contracts not

known at this time, the market price is the best proxy to use for planning purposes.  

Figure 6.2.3 illustrates the amount of annual energy required by the Company after the dispatch of

its existing resources.  The figure shows that the Company’s energy requirements increase

significantly over time.  

Year Reserve Margin (%)

2014 13 2%

2015 15 6%

2016 17 0%

2017 11 5%

2018 8.9%

2019 6.2%

2020 4.8%

2021 3.3%

2022 0.8%

2023 ‐0.5%

2024 ‐1.7%

2025 ‐2.8%

2026 ‐3.9%

2027 ‐5.1%

2028 ‐6.3%

2029 ‐7.5%
92

Figure 6.2.3 ‐ Current Company Energy Position (2015 – 2029)

 

Note: The values in the boxes represent total energy in 2029

1) Accounts for unit retirements and rating changes to existing units in the Plan

The Company’s long‐term energy and capacity requirements shown in this section are met through

an optimal mix of new conventional and renewable generation, DSM, and market resources using

the IRP process.

6.3 MODELING PROCESSES & TECHNIQUES

The Company used a methodology that compares the costs of alternative plans to evaluate the types

and timing of resources that were included in those plans.  The first step in the process was to

construct a representation of the Company’s current resource base.  Then, future assumptions

including, but not limited to load, fuel prices, emissions costs, maintenance costs, and resource costs

were used as inputs to Strategist.  Concurrently, supply‐side resources underwent a screening

analysis as discussed in Chapter 5.  This analysis provided a set of future supply‐side resources

potentially available to the Company, along with their individual characteristics.  The types of

supply‐side resources that are available to the Strategist model are shown in Figure 6.3.1.

NUGs

40,000

50,000

60,000

70,000

80,000

90,000

100,000

110,000

120,000 GWh

Generation Under

Construction

Existing Generation1

Energy

Gap

Approved DSM

33,196

58,647

12,521

693

176
93

Figure 6.3.1 ‐ Supply‐Side Resources Available in Strategist

Key: CC: Combined‐cycle; CT: Combustion Turbine (2 units); IGCC CCS: Integrated‐Gasification Combined‐cycle with Carbon Capture and

Sequestration; Coal CCS: Coal with Carbon Capture and Sequestration; Solar PV: Solar Photovoltaic; Solar Tag: Solar Tag along to generation

site

As described in Chapter 5, potential DSM resources were also screened.  For the initial screening of

demand‐side resource options, an expansion plan of only supply‐side resources and approved DSM

programs was developed.  The proposed and future DSM programs that passed the Company’s

cost/benefit evaluation discussed in Section 5.5.1 were compared to this initial plan with the

opportunity to modify the expansion plan based on their economics.  After cost‐effective demand‐

side resources were identified, they were included as a portfolio of programs that was given the

opportunity to eliminate, defer, or alter the need for future supply‐side resources and market

purchases.  Next, supply‐side options, market purchases and approved and proposed demand‐side

resource options were re‐optimized along with the future DSM portfolio to arrive at a Base Plan.  

This process ensured that supply‐ and demand‐side resources were placed on equal footing to meet

future peak capacity and energy requirements.  

Strategist develops resource plans based on the total NPV utility costs over the Study Period.  The

NPV utility costs included the variable costs of all resources (including emissions and fuel), the cost

of market purchases, and the fixed costs of future resources.

  

To assess an optimum resource strategy and the validity of the Company’s 2014 Plan, the Company

developed six Alternative Plans representing plausible future paths, as described in Section 6.4.  All

six Alternative Plans were then analyzed and tested against a set of scenarios and sensitivities

designed to measure the relative cost performance of each plan under varying market, commodity,

and regulatory conditions.   

Biomass

CC 2x1

CC 3x1

Coal w /CCS

CT

Fuel Cell

IGCC w /CCS

Nuclear (NA3)

Offshore Wind

Onshore Wind

Solar NUG

Solar PV

Solar Tag

Dispatchable

Non Dispatchable
94

Figure 6.3.2 ‐ Plan Development Process  
95

6.4   ALTERNATIVE PLANS

The Company’s Alternative Plan analysis is intended to represent plausible paths of future resource

additions.  Each Alternative Plan is given certain characteristics.  For example, Plan B: Fuel Diversity

Plan includes a nuclear unit being constructed along with onshore wind and solar in the Planning

Period, Plan C: Renewable Plan includes selected amounts of renewable generation being

constructed throughout the Planning Period.  After this step, each Alternative Plan was then

optimized around the Company’s basecase assumptions, where each individual plan was able to

select additional resources from those shown in Figure 6.3.1 in order to meet peak capacity and

energy requirements through the Study Period.  

Along with the individual characteristics of the Alternative Plans, the plans also share a number of

individual generation resource assumptions.  Each Alternative Plan includes the resources for which

the Company has filed and/or has been granted CPCN approval from the SCC.  These resources

include Warren County Power Station, Brunswick County Power Station, and the SPP.   

All Alternative Plans have the same level of approved, proposed and future DSM programs

reaching 583 MW by the end of the Planning Period.  Additionally, each Alternative Plan reflects the

retirement of Chesapeake Energy Center Units 1 (111 MW), 2 (111 MW), 3 (149 MW), and 4 (207

MW) and Yorktown Units 1 (159 MW) and 2 (164 MW), respectively by 2015 and in 2016.  The solar

NUGs are also included (total 200 MW nameplate) by 2016.  The Company’s six Alternative Plans

are described in greater detail below.  

Plan A: Base Plan

The Base Plan does not include any additional plan characteristics.  The Base Plan was developed

using least cost modeling methodology.  Specifically, Plan A selects:

 3,132 MW of CC capacity (two CCs);

 914 MW of CT capacity (two banks of 2 CTs – 457 MW per bank).

Plan B: Fuel Diversity  

Plan B is designed to address considerations such as reliability, fuel diversity, price stability pending

carbon regulation, and environmental compliance for the Company’s customers over the Planning

Period.  Plan B includes:

 1,453 MW North Anna 3 nuclear facility;

 247 MW (nameplate) of onshore wind;

 12 MW (nameplate) Offshore Wind Demonstration Project;

 520 MW (nameplate) of generic solar;

 39 MW (nameplate) of solar tag comprised of two units;

And selects:

 1,566 MW of CC capacity (one CC);

 457 MW of CT capacity (one bank of 2 CT units).
96

Plan C: Renewable  

The Renewable Plan presents a way for the Company to test the feasibility and cost of meeting

North Carolina’s REPS requirements as well as Virginia’s RPS goals through increased building of

new renewable resources.

The North Carolina legislature has established the REPS (NCGS § 62‐133.8) which imposes

mandatory renewable requirements that increase by year and include specific requirements for

solar, swine waste, and poultry waste.  Similarly, the Virginia legislature has indicated that small

renewable energy projects are in the public interest (Va. Code § 56‐580.D).  Additionally, the

Virginia legislature enacted Va. Code § 56‐585.2, establishing a voluntary RPS program with a goal

that increases by year stating that it is in the public interest for utilities to achieve the targets set

forth in Virginia’s RPS program.   

To meet these targets with new Company‐owned resources, the Company would be required to

develop an additional significant amount of renewable resources compared to all other plans.  This

plan includes:

 247 MW (nameplate) of onshore wind;

 500 MW (nameplate) of offshore wind;

 12 MW (nameplate) Offshore Wind Demonstration Project;

 1,300 MW (nameplate) of generic solar;

 39 MW (nameplate) of solar tag.

And selects:

 1,566 MW of CC capacity (one CC);

 914 MW of CT capacity (two banks of 2 CT units – 457 MW per bank).

Plan D: Coal

In response to questions related to the cost and feasibility related to developing coal facilities in Case

No. PUE‐2011‐00092, as required by the Final Order, the Company developed Plan D: Coal.  The

Coal Plan considers the Company developing generic pulverized coal‐fired facilities with carbon

capture and sequestration technology.  These coal CCS units are approximately 640 MW each.  This

plan only considers coal facilities with CCS.  Coal facilities without CCS will not meet the

requirements of the EPA’s GHG NSPS rule for new electric generating units if finalized as currently

proposed and are therefore not feasible.  This plan includes:

 1,920 MW of coal CCS (three 640 MW units);

And selects:

 1,566 MW of one CC;

 457 MW CT capacity (one bank of 2 CT units).
97

Plan E: Offshore Wind

The Offshore Wind Plan represents a plan with significant offshore wind.  Specifically, Plan D

includes:

 500 MW of offshore wind in the Planning Period (1,500 MW over the Study Period);

 12 MW (nameplate) Offshore Wind Demonstration Project.

And selects:

 3,132 MW of CC capacity (two CCs);

 914 MW of CT capacity (two banks of 2 CT units ‐ 457 MW per bank).

Plan F: EPA GHG Plan

Plan F is designed as one possible path that the Company could take to comply with the proposed

EPA GHG regulations on carbon emission standards for electric generating units announced in June

2014.   

Under Plan F, carbon intensity (as defined by EPA) for the electric generation fleet operating in

Virginia (under ownership of the Company and others) is limited to an average of 884 lb/MWh from

2020 ‐ 2029 and 810 lb/MWh for 2030 and beyond, consistent with the limits set in the proposed EPA

GHG regulations issued in June 2014.  Carbon intensity calculations exclude Pump Hydro, Hydro

units, units in West Virginia (Mt. Storm), 94% of existing nuclear, market purchases, and existing

and future CTs operating with a capacity factor less than 33%.  This Plan models over 700 MW of

coal retirements and also includes:

 247 MW (nameplate) of onshore wind;

 12 MW (nameplate) Offshore Wind Demonstration Project;

 39 MW (nameplate) of solar tag;

 1,453 MW North Anna 3 nuclear facility;

 1,300 MW (nameplate) of generic solar.

And selects:

 1,566 MW of CC capacity (one CC);

 914 MW of CT capacity.
98

Figure 6.4.1 ‐ Alternative Plans

Key: App. DSM: Approved DSM Programs; Bio: Biomass; Brunswick: Brunswick County Power Station; CC: Combined‐cycle 3x1; SPP: Solar

Partnership Program; COAL CCS: Coal w/ Carbon Capture Sequestration; CT: Combustion Turbine (2 units); NA3: North Anna Unit 3; OFF:

Offshore Wind; OFFD: Offshore Wind Demonstration Project; Fut. DSM: Proposed & Future DSM Programs; SLR1: Generic Solar (40 MW);

SLR2: Generic Solar (100 MW); SLR NUG: Solar NUG; SLR TAG: Solar Tag; Warren: Warren County Power Station; WND: Onshore Wind.

Note: 1) DSM capacity continues to increase throughout the Planning Period.

Traditional Renewable/ DSM Traditional Renewable/ DSM Traditional Renewable/ DSM

2015 Warren App.DSM/ SPP/ SLR

NUG

Warren App.DSM/ SPP/

SLR NUG

Warren App.DSM/ SPP/

SLR NUG

2016 Brunswick

SLR NUG/SPP/  

Fut.DSM

Brunswick

SLR NUG/SPP/  

Fut.DSM

Brunswick

SLR NUG/SPP/  

Fut.DSM

2017 SLR/ SLR TAG SLR2/ SLR TAG

2018 SLR/ OFFD SLR2/ OFFD

2019 CC CC SLR CC SLR2

2020 SLR/ WND/         

SLR TAG

SLR2/ WND/        

SLR TAG

2021 SLR/ WND SLR2/ WND

2022 CT CT SLR/ WND SLR2/ WND

2023 CT SLR CT SLR2

2024 SLR SLR2

2025 SLR CT SLR2/ OFF

2026 SLR SLR2

2027 SLR SLR2

2028 NA3 SLR SLR2

2029 CC SLR SLR2

Year

Plan A Plan B Plan C

Base Fuel Diversity Renewable

Traditional Renewable/ DSM Traditional Renewable/ DSM Traditional Renewable/ DSM

2015 Warren App.DSM/ SPP/

SLR NUG

Warren App.DSM/ SPP/

SLR NUG

Warren App.DSM/ SPP/ SLR

NUG

2016 Brunswick

SLR NUG/SPP/  

Fut.DSM

Brunswick

SLR NUG/SPP/  

Fut.DSM

Brunswick

SLR NUG/SPP/  

Fut.DSM

2017 SLR2/ SLR TAG

2018 OFFD SLR2/ OFFD

2019 CC CC CC SLR2

2020

CT

SLR2/ WND/         

SLR TAG

2021 SLR2/ WND

2022 CT CT SLR2/ WND

2023 SLR2

2024 COAL CCS CT SLR2

2025 OFF SLR2

2026 COAL CCS SLR2

2027 SLR2

2028 COAL CCS NA3 SLR2

2029 CT CC SLR2

Plan F

Year EPA GHG Plan

Plan D Plan E

Coal Offshore Wind
99

6.5 BASECASE, SCENARIOS & SENSITIVITIES

The Company used a number of scenarios and sensitivities based upon its planning assumptions to

evaluate these six Alternative Plans.  The Company’s operational environment is highly dynamic

and can be significantly impacted by variations in commodity prices, construction costs,

environmental, and regulatory requirements.  Testing multiple expansion plans under different

assumptions assesses each plan’s cost performance under a variety of possible future outcomes.  The

Company examined one basecase, three scenarios, and 12 sensitivities as explained below.

Basecase (1)

The basecase used the expected or forecast “base” values including the load forecast (Chapter 2),

existing system resources (Chapter 3), planning assumptions (Chapter 4), and new resources

(Chapter 5).  

Scenarios:

Scenarios provide a broad range view of the variable future evolution of the markets and regulatory

conditions.  Several key assumptions were changed in each scenario, which accounted for systemic

changes in the view of the future.  These changes included multiple variables that were interrelated,

such as emission and cost variables, ensuring all assumptions were consistent.  The Company

examined (a) no carbon cost, (b) high fuel cost, and (c) low fuel cost.

No Carbon Cost Scenario (2)

A significant uncertainty for the electric utility industry is the timing and structure of industry‐wide

carbon legislation/regulation and potential impacts on the fuel markets.  The Company’s basecase

assumes that carbon legislation/regulation will be enacted by 2020.  The assumed program is

structured as a carbon tax efficiency requirement that would increase the cost of generating

electricity using fossil fuels because of their carbon emissions.  Until proposed regulations are

finalized or a specific new law is passed uncertainty remains as to the market structure, pricing

mechanism, and the impact on the marginal cost of electricity that may result from carbon

regulation.   

Due to these uncertainties, the Company chose to examine a scenario where there would be no

marginal cost of carbon emissions in the Study Period; fuel and commodity processes were

correlated appropriately to the effects of removing the modeled CO2 market.  The assumptions that

were adjusted in this scenario include: i) fossil fuel prices (coal, gas, and oil); ii) market capacity and

energy prices; and iii) REC prices.

High and Low Fuel Cost Scenarios (3 ‐ 4)

These scenarios were designed to test fuel price variations for all generation units in each

Alternative Plan, because fuel costs are a significant portion of final customer rates.  Volatility in

rates is generally viewed as undesirable; therefore, plans that reduce volatility may be preferred to

other Alternative Plans.  These scenarios consider adjustments to the following assumptions (with

the changes in the fuel prices being the main driver): i) fossil fuel prices (coal, gas, and oil); ii) market

capacity and energy prices; and iii) REC prices.
100

Sensitivities:

A sensitivity represents a change in a single or small subset of variables from the basecase

assumptions.  The sensitivities performed by the Company were designed to test the Alternative

Plans under varying assumptions to better understand the inherent risks embedded in the

Company’s 2014 Plan.  The Company performed the following 12 sensitivities:  

High and Low Load Growth Sensitivities (5 ‐ 6)

Future load growth was one of the key inputs used to develop the 2014 Plan.  Demand growth is

significantly impacted by regional economic growth and technological changes.  As discussed in

Chapter 2, the basecase average annual growth rate over the Planning Period for the DOM LSE is

1.4% and 1.3% for peak and energy requirements, respectively.  The high and low load growth

sensitivities assume a plus and minus 0.5% change in these average annual growth rates (see Figure

6.5.1).  The high load growth sensitivity could result from an above average economic growth rate or

expanded penetration of new technological devices at home and in the workplace.  The low load

growth sensitivity may come from lower than expected economic growth, additional energy

conservation, or a decline in real disposable income.

Figure 6.5.1 ‐ Summary of High Load and Low Load Sensitivities

High and Low Construction Cost Sensitivities (7 ‐ 8)

The potential for increases in construction costs represents a significant challenge to utilities,

regulators, and customers across the United States as utilities focus on replacing aging infrastructure

and adding new capacity to meet current regulatory requirements and future demand growth.  The

construction cost sensitivities analyzed the risk associated with potential future increases or

decreases in the construction costs of traditional and renewable plants.  The high and low

construction cost sensitivities assumed an increase and decrease of costs by 10% for CCs, CTs, and

solar and 25% for the other plants such as nuclear, coal and wind in order to determine the economic

impact of potential changes in the construction cost of new units.  

High Load Low Load High Load Low Load

2015 17,756 17,583 88,603 87,745

2016 18,176 17,823 91,180 89,419

2017 18,618 18,078 93,113 90,421

2018 19,004 18,272 94,880 91,233

2019 19,367 18,439 96,275 91,662

2020 19,685 18,557 98,050 92,435

2021 20,046 18,712 99,331 92,719

2022 20,400 18,856 101,039 93,385

2023 20,761 19,000 102,777 94,058

2024 21,111 19,131 104,508 94,702

2025 21,465 19,261 106,236 95,321

2026 21,828 19,394 108,005 95,954

2027 22,213 19,541 109,824 96,611

2028 22,588 19,676 111,691 97,287

2029 22,964 19,807 113,544 97,928

Peak (MW) Energy (GWh) Year
101

High and Low Transmission and Distribution (“T&D”) Cost Sensitivities (9 ‐ 10)

The Company assumed that a portion of the benefits from the Companyʹs portfolio of DSM

programs was from avoided T&D investments to meet incremental demand growth.  The costs

estimated for incremental T&D projects have increased in recent years in a similar fashion to

generation construction projects.  As a result, the high and low T&D cost sensitivities of the

approved, proposed, and future DSM programs were tested by increasing and decreasing the T&D

benefit of the DSM programs by 25%.  

Net Metering (11)

In North Carolina, there is no aggregate capacity limit for net metering.  In Virginia, net metering is

currently available to customers on a first‐come, first‐serve basis in each electric distribution

Company’s service area.  This occurs until the rated generating capacity owned and operated by

eligible customer generators reaches 1% of each electric distribution Company’s adjusted Virginia

peak load forecast for the previous year (see Figure 6.5.2).  This sensitivity will allow the Company

to determine the impact on load in the event that the 1% cap is reached in Virginia by 2034.  

Figure 6.5.2 ‐ Summary of Net Metering Sensitivity

Electric Vehicles Sensitivity (12)

The Company’s basecase assumed approximately 241,000 EVs and PHEVs in its service territory by

2029, with penetrations increasing throughout the Study Period (see Figure 6.5.3).  Peak demand and

energy requirements due to EVs and PHEVs in the basecase reach 215 MW and 853 GWh by 2029.

This sensitivity relies on the EPRI’s PHEV study14 for a higher penetration of 0.95 million PHEVs.  

The objective of the EV and PHEV sensitivity was to project the impact of higher plug‐in EV

penetration on the Company’s grid and identify resources needed to meet this potential new

technology’s requirements.

                                                       

14 This study is available at http://www.epri.com.

Year Energy  

(GWh)

Capacity  

(MW)

Coincident Peak

Impact (MW)

2015 13 9 3

2016 15 10 3

2017 18 12 4

2018 22 15 4

2019 27 18 5

2020 34 23 7

2021 43 29 8

2022 54 36 11

2023 69 46 14

2024 87 58 17

2025 108 73 21

2026 133 90 26

2027 161 108 32

2028 191 128 38

2029 219 147 44
102

Figure 6.5.3 ‐ Summary of Electric Vehicle Sensitivity

No REC Sales Sensitivity (13)

In this sensitivity, the Company assumed that it would not be able to sell RECs, therefore increasing

the net cost of renewable generation.  

High REC Sales Sensitivity (14)

This sensitivity assumed that renewable generation resources will produce a REC that has twice the

value of a basecase REC.   

High and Low Cost Combination Sensitivities (15 ‐ 16)

The high and low cost combination sensitivities included a grouping of three individual sensitivities

to form a more extreme case.  The high cost combination case included the high fuel cost scenario,

high construction cost, and high T&D sensitivities, while the low cost combination case included the

low fuel cost scenario, low construction cost, and the low T&D sensitivities.  

6.6   ALTERNATIVE PLAN NPV COMPARISON  

The Company evaluated the six Alternative Plans using the basecase, three scenarios, and 12

sensitivities to compare and contrast the plans using the NPV utility costs over the Study Period.  

Figure 6.6.1 presents the results of the Alternative Plans compared on an individual scenario and

sensitivity basis.  Each row of the figure constitutes a grouping of plans that were considered for that

particular scenario or sensitivity.  The results are displayed as a percentage change in costs

compared to the Base Plan with basecase assumptions (marked with a star).  

EV Count Peak

(MW)

Energy

(GWh)

EV Count Peak

(MW)

Energy

(GWh)

2015 7,735 7 27 22,353 20 79

2016 14,085 13 50 47,752 43 169

2017 22,022 20 78 79,500 71 281

2018 31,546 28 112 117,599 105 416

2019 42,658 38 151 162,047 145 573

2020 55,358 49 196 212,845 190 753

2021 69,645 62 246 269,993 241 955

2022 85,519 76 303 333,491 298 1,180

2023 102,981 92 364 403,338 360 1,427

2024 122,030 109 432 479,535 428 1,697

2025 142,667 127 505 562,082 502 1,989

2026 164,891 147 583 650,979 581 2,303

2027 188,703 169 668 746,225 666 2,641

2028 214,102 191 758 847,822 757 3,000

2029 241,089 215 853 955,768 853 3,382

Year

Base Forecast EV Sensitivity
103

Figure 6.6.1 ‐ Alternative Plan Comparison  

Note: The results are displayed as a percentage of costs compared to the Base Plan with basecase assumptions (marked with star).

6.6.1 PORTFOLIO EVALUATION SCORECARD  

As discussed in Section 6.1, the Company developed a Portfolio Evaluation Scorecard to provide a

quantitative and qualitative measurement system to further examine the Alternative Plans

compared to the Base Plan, which relies primarily on natural gas‐fired generation to meet new

capacity and energy needs on the Company’s system.  The Company intends to refine this analysis

in subsequent plans as needed.  This analysis combines the results of the Strategist NPV cost results

with other quantitative assessment criteria such as Rate Stability, as evaluated through fuel and

construction cost risk, GHG Emissions and Fuel Supply Concentration.                         

A brief description of each assessment criteria follows:   

Low Cost

This assessment criteria evaluates each Alternative Plan according to the results of the Strategist

NPV analysis given basecase assumptions.  The lowest NPV cost Alternative Plan is assessed a

favorable ranking, while the highest cost Alternative Plan is assessed an unfavorable ranking.

Rate Stability

Two metrics are reflected under this criteria and incorporate the results of the Strategist NPV

analysis.  The first measures the percent difference between the High Fuel Cost Scenario and the

Base Case while the second measures the percent difference between the High Cost Combination

Plan A:   

Base

Plan B:   

Fuel

Diversity

Plan C:

Renew able

Plan D:

Coal

Plan E:    

Offshore

Wind

Plan F:

EPA GHG

Plan

1 Base Case 7.73% 13.11% 12.73% 10.38% 9.52%

2 No CO2 Cost Scenario ‐16.61% ‐7.35% ‐3.63% ‐3.05% ‐6.20% ‐3.71%

3 High Fuel Cost Scenario 7.93% 14.81% 20.45% 20.55% 18.05% 16.70%

4 Low Fuel Cost Scenario ‐6.25% 2.27% 7.38% 6.58% 4.36% 4.13%

5 High Load Grow th 11.29% 18.99% 24.36% 24.11% 21.66% 20.44%

6 Low Load Grow th ‐8.46% ‐0.66% 4.71% 4.24% 2.00% 1.64%

7 High Construction Cost 0.64% 11.52% 17.11% 15.88% 13.59% 13.63%

8 Low Construction Cost ‐0.64% 3.94% 9.11% 9.57% 7.18% 5.41%

9 High T&DCosts ‐0.09% 7.63% 13.01% 12.63% 10.29% 9.42%

10 Low T&DCosts 0.09% 7.82% 13.20% 12.82% 10.48% 9.61%

11 Net Metering ‐0.24% 7.50% 12.88% 12.49% 10.15% 9.29%

12 Electric Vehicles 3.12% 10.83% 16.21% 15.85% 13.49% 12.46%

13 No REC Sales 0.50% 8.57% 14.42% 13.23% 11.15% 10.58%

14 High REC Sales ‐0.64% 6.75% 11.67% 12.09% 9.49% 8.32%

15 High Cost Combination 8.35% 18.39% 24.24% 23.49% 21.05% 20.57%

16 Low Cost Combination ‐6.68% ‐1.31% 3.59% 3.65% 1.36% 0.25%

Plan Average ‐0.51% 7.31% 12.58% 12.28% 9.87% 9.25%

Scenarios and Sensitivities
104

Sensitivity and the Base Case.  The Alternative Plan that reflects the smallest percentage difference is

assessed a favorable ranking and the plan that reflects the highest difference between the two

metrics is assessed an unfavorable ranking.  The purpose of this category is to provide separate

assessments of how each Alternative Plan performs under a high fuel cost environment and a high

construction cost environment.  The Company maintains that the Alternative Plans that reflect the

lowest variance between the high stress scenarios and sensitivities relative to the Base Case can

result in more stable rates to the Company’s customers.   

GHG Emissions

Two metrics are reflected under these assessment criteria.  The first is a measure of average annual

CO2 intensity over the Study Period.  This metric is important because CO2 intensity is specifically

targeted by the proposed EPA GHG rules and is a representation of the CO2 emissions across the

generation portfolio.  For the purposes of this scoring, CO2 intensity is calculated by dividing the

annual total CO2 emissions in pounds for the Company’s generation system by the Company’s total

annual generation in MWhs.  The simple average is then determined for the years included in the

Study Period.   The Alternative Plan with the lowest intensity is assessed with a favorable ranking,

while the plan with the highest intensity is assessed an unfavorable ranking.  

The second metric is a simple annual average of the total system CO2 emissions in pounds (i.e., lbs.)

over the Study Period for each Alternative Plan (and the Base Plan).  Total CO2 emissions can also be

a reasonable proxy for total emissions.  The Alternative Plan with the lowest system emissions are

expressed in percentages as compared to the Base Plan is assessed a favorable ranking, while the

Alternative Plan with the highest system emissions as expressed in percentages as compared to the

Base Plan is assessed an unfavorable ranking.

Given current societal trends and the proposed EPA GHG regulations associated with electric

generation, Alternative Plans with lower CO2 intensity and total system CO2 emissions are valued

more favorably.

Fuel Supply Concentration

As it has been noted in numerous sections of this planning document, an over dependence on any

one fuel source is not desirable.  Further, due to the enhanced production of shale gas in the United

States, most forecasts for natural gas prices are lower than in the recent past and, as such, future

electric generation portfolios are expected to include a large percentage of natural gas‐fired

generation.  

In light of the above, the Fuel Supply Concentration assessment is designed to measure the level of

natural gas generation in each Alternative Plan, inclusive of market purchases.  Specifically, the

metric used is the total percentage of electric energy generation from natural gas‐fired facilities

within the Alternative Plan plus energy purchased in the PJM market over the Planning Period.  

Purchased energy is included because the Company assumes that natural gas fired generation will

most often be setting the market clearing price.  The Alternative Plan that has the lowest percentage

of natural gas fired energy and purchases is assessed a favorable ranking, while the plan with the

highest percentage of natural gas fired generation and purchases is assessed an unfavorable ranking.    
105

Figure 6.6.1.1 – Portfolio Evaluation Scorecard

Figure 6.6.1.2 – Portfolio Evaluation Scorecard with Scores

Based on the score rating (Favorable, Neutral and Unfavorable) illustrated in Figure 6.6.1.1, scores

(1, 0 and ‐1, respectively) were assigned to each portfolio.  Figure 6.6.1.2 displays the total score for

each portfolio.  The results of the Portfolio Evaluation Scorecard with Scores show that the

Alternative Plans with the most favorable rankings are the Fuel Diversity Plan and the EPA GHG  

Plan, with the highest total score of 1.  Given that the EPA GHG Plan has a higher cost, and given

that the proposed EPA GHG rules for existing generation units are not yet final, the Company

maintains that at this time the Fuel Diversity Plan is superior.  The Fuel Diversity Plan offers a

favorable path forward given the significant uncertainties faced by the industry, the Company, and

most importantly, the Company’s customers.  Albeit more robust, the Company understands that

the Fuel Diversity Plan is a higher cost option than the Base Plan.  Therefore, the Company

maintains that it is important to keep all non‐natural gas fired generation options open so those

options are available to the Company’s customers should the future conditions change.        

6.7 2014 PLAN  

Based on the results above, the Company recommends a path forward that continues to follow an

expansion consistent with Plan A: Base Plan, which follows least‐cost methodology given basecase

Objective Basecase Cost Fuel Supply

Period 2029

Portfolio

System Cost  

Compared to   

A. Base (%)

Cost Increase

in High Fuel

Cost Scenario

(%)

Cost increase in

High Cost

Combination

Sensitivity (%)

CO2

Intensity

(short ton/

1,000 kWh)

Total System

CO2 Emission

Compared to

Base (%)

Reliance on Single

Fuel Source (Percent

of Energy from

Natural Gas and

Market Purchases)

A. Base   0.0% 7.9% 8.4% 0.43 0.0% 48.5%

B. Fuel Diversity 7.7% 6.6% 9.9% 0.40 ‐6.4% 35.2%

C. Renew able 13.1% 6.5% 9.8% 0.41 ‐4.3% 42.9%

D. Coal 12.7% 6.9% 9.5% 0.42 ‐2.9% 41.8%

E. Offshore Wind 10.4% 6.9% 9.7% 0.42 ‐1.6% 46.8%

F. EPA GHG Plan (884 limit betw een

2020 and 2029, and 810 limit after 2030) 9.5% 6.6% 10.1% 0.37 ‐14.0% 36.6%

Rate Stability GHG Emissions

2014 ‐ 2039

Portfolio

System Cost  

Compared to   

A. Base (%)

Cost Increase

in High Fuel

Cost Scenario

(%)

Cost increase in

High Cost

Combination

Sensitivity (%)

CO2

Intensity

(short ton/

1,000 kWh)

Total System

CO2 Emission

Compared to

Base (%)

Reliance on Single

Fuel Source (Percent

of Energy from

Natural Gas and

Market Purchases)

Total

Score

A. Base   1 ‐1 1 ‐1 ‐1 ‐1 ‐2

B. Fuel Diversity 0 0 0 00 1 1

C. Renew able ‐1 1 0 00 0 0

D. Coal 0 0 0 00 0 0

E. Offshore Wind 0 0 0 00 0 0

F. EPA GHG Plan (884 limit betw een

2020 and 2029, and 810 limit after 2030)

0 0 ‐1 11 0 1
106

assumptions, and concurrently continues forward with reasonable development efforts of the

additional resources identified in Plan B: Fuel Diversity Plan (Plan A and B are specified in Chapter

6).  Collectively, this recommended path forward is the 2014 Plan.

As mentioned in earlier Sections of this document, the electric power industry has been and

continues to be dynamic in nature with rapidly changing developments and regulatory challenges.  

The Company expects that these dynamics will continue into the future and will be further

complicated by societal trends such as an enhanced interest in national security (including

infrastructure security), aging infrastructure, and climate change focused laws and regulations.  

Therefore, it is prudent for the Company to adequately preserve reasonable development options

available to it in order to be able to respond to the future market, regulatory, and industry changes

that are likely to occur in some form, but are difficult to predict at the present time.  This is

especially important to preserve resource options requiring significantly longer development

timelines such as nuclear and wind.  

Consistent with the results of Section 6.6, Plan A: Base Plan, given current basecase assumptions, is

the least cost plan and performs reasonably well under the deterministic scenarios and sensitivities

included in Section 6.6.  Plan A: Base Plan, however, is almost exclusively dependent on fueling the

Company’s expansion with natural gas.  Following this path would potentially leave the Company

and its customers vulnerable to natural gas price volatility similar to that seen in the New England

States over the last 15 to 20 years (see Figure 6.7.1).  In addition, this vulnerability is magnified by

possible future regulatory limitations on natural gas production or service disruptions on the natural

gas transmission/distribution grid.  Such low probability, high impact events could lead to electric

service reliability issues and large cost increases to the Company’s customers and the economy of its

service territory that could be mitigated by the more resource diverse Plans identified in Section 6.5.  

While such events are low probability in nature, the electric power industry (along with the United

States) has experienced numerous “low probability, high impact” events during recent history.  For

example:

 Electric power de‐regulation and subsequent re‐regulation;

 Midwest capacity shortages of the late 1990s and early 2000s;

 California Energy Crisis of the early 2000s;

 EPA’s Mercury & Air Toxics Standards leading to massive coal unit retirements;

 High gas prices of the mid‐2000s leading to the shale gas revolution;

 Mortgage crisis leading to the recession of 2007 through 2009;

 Polar Vortex.
107

Figure 6.7.1 ‐ Mass Hub Power Prices

The deterministic scenarios and sensitivities identified in Sections 6.5 and 6.6 are designed to mimic

events with a reasonable‐to‐high probability of occurrence.  As described above, however, low

probability events do occur.  When planning any portfolio, it is fundamental to prepare for

uncertainty.  For these reasons the Company is recommending Plan A: Base Plan, while concurrently

preserving the continued development of the additional resource options included in Plan B: Fuel

Diversity Plan.  

The Company maintains that the Fuel Diversity Plan, despite its higher cost under current planning

assumptions, would promote fuel‐price stability for customers over the long‐term by reducing an

overreliance on any one fuel source and/or generation technology.  Also, the Fuel Diversity Plan

includes a more balanced mix of baseload, intermediate, and peaking units, as well as a diverse fuel

mixture including fossil, nuclear, and renewable resources and has a potential of meeting EPA GHG

target, with additional renewable resources and coal retirements.  Plan A: Base Plan and Plan B: Fuel

Diversity Plan are displayed in tabular format in Figures 6.7.2(a) and 6.7.2(b), respectively.

$0.00

$20.00

$40.00

$60.00

$80.00

$100.00

$120.00

$140.00

$160.00

$180.00

3 7 11 3 7 11 3 7 11 3 7 11 3 7 11 3 7 11 3 7 11 3 7 11 3 7 11 3 7 11 3 7 11 3 7

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

RTC Average Monthly PowerPrice Massachusetts Hub (Real Time)

$/MWh
108

Figure 6.7.2(a) ‐ Plan A: Base Plan  

 

Figure 6.7.2(b) ‐ Plan B: Fuel Diversity Plan  

Key: Retrofit: Additional environmental control reduction equipment; Repower: Convert fuel to biomass or repower by natural gas; Retire:

Remove a unit from service; BR: Bremo; Brunswick: Brunswick County Power Station; CEC: Chesapeake Energy Center Unit; CC:

Combined‐Cycle; CT: Combustion Turbine (2 units); OFFD: Offshore Wind Demonstration Project; North Anna 3: North Anna Unit 3; PP5:

Possum Point Unit 5; SNCR: Selective Non‐Catalytic Reduction; SLR: Generic Solar (40 MW); SLR NUG: Solar NUG; SLR TAG: Solar Tag;

SPP: Solar Partnership Program; Warren: Warren County Power Station; WND: Onshore Wind; YT: Yorktown Unit.

Note: 1) DSM capacity savings continue to increase throughout the Planning Period.

2) Earliest possible in‐service date for North Anna 3 is September 2027, which is reflected as a 2028 capacity resource.

3) SPP and SLR NUG started in 2014.

New

Conventional

New            

Renew able Retrofit Repow er Retire

2015 Warren SLR NUG/SPP3     CEC 1‐4   

2016 Brunswick SLR NUG/SPP3 YT 1‐2

2017

2018

PP5 – SNCR

YT3 – SNCR

2019 CC

2020

2021

2022 CT

2023 CT

2024

2025

2026

2027

2028

2029 CC

Approved DSM

Proposed & Future

DSM                  

583 MW by 2029

3,063 GWh by 2029

Demand‐side

Resources1 Year

Supply‐side Resources

New

Conventional

New           

Renew able Retrofit Repow er Retire

2015 Warren SLR NUG/SPP3     CEC 1‐4   

2016 Brunswick SLR NUG/SPP3 YT 1‐2

2017 SLR TAG/SLR

2018 OFFD/SLR

PP5 – SNCR

YT3 – SNCR

2019 CC SLR

2020 WND/SLR

TAG/SLR

2021 WND/SLR

2022 CT WND/SLR

2023 SLR

2024 SLR

2025 SLR

2026 SLR

2027 SLR

2028 North Anna 32 SLR

2029 SLR

Year

Supply‐side Resources

Approved DSM

Proposed & Future

DSM                  

583 MW by 2029

3,063 GWh by 2029

Demand‐side

Resources1
109

The Company believes it is prudent to continue reasonable development efforts of the additional

resource options identified in Plan B: Fuel Diversity Plan for the following reasons:

 While initially capital intensive, nuclear units represent the most cost‐effective baseload,

near emission‐free, and a long‐term (60+ years) reliable resource for meeting future energy

and capacity needs;

 The Base Plan’s potential generation expansion of almost exclusively CC and CT technology

is heavily reliant on a single fuel source, natural gas, which also adds risks to the natural gas

pipeline infrastructure during extreme weather;

 The need for new nuclear power becomes greater with the future license expirations of the

Company’s current nuclear facilities.  The license expirations of Surry Units 1 (838 MW) and

2 (838 MW) and North Anna Unit 1 (838 MW) occur within the Study Period (2032, 2033, and

2038, respectively).  The license for North Anna Unit 2 (834 MW) will also expire in 2040;

 Three land‐based wind energy sites in Virginia with a potential to generate a total of 247

MW (nameplate) would support the Company’s portfolio fuel diversity and decrease the

Company’s overall emissions, including CO2;  

 Developing the Offshore Wind Demonstration Project (12 MW nameplate) is a first step

towards a potentially viable future renewable resource that enhances fuel diversity and

decreases emissions;  

 Approximately 520 MW (nameplate) of new generation powered by solar energy by 2029

would support the Company’s portfolio, fuel diversity, and decrease the Company’s overall

emissions, including CO2;

 The Fuel Diversity Plan  best positions the Company to meet the proposed EPA GHG target

with additional renewable resources and coal retirements ; and

 The Fuel Diversity Plan performs well on the Portfolio Evaluation Scorecard when assessed

for high fuel cost, lower carbon intensity, and lower reliance on natural gas fired generation.
110

Figure 6.7.3(a) ‐ Plan A: Base Plan – Capacity (2015 ‐ 2029)

Note: 1) Accounts for unit retirements and rating changes to existing units in the Plan, and reflects summer ratings.

2) See Section 4.2.2.

Figure 6.7.3(b) ‐ Plan B: Fuel Diversity Plan – Capacity (2015 ‐ 2029)

Note: 1) Accounts for unit retirements and rating changes to existing units in the Plan, and reflects summer ratings.

2) See Section 4.2.2.

NUGs

10,000

12,000

14,000

16,000

18,000

20,000

22,000

24,000

26,000

MW

Generation

Under Construction

Potential Generation

Existing Generation1

Approved DSM

Proposed and Future DSM

Market Purchases

Generation Under

Development

16,519

1,566

2,480

2,716

158

36

425

NUGs

10,000

12,000

14,000

16,000

18,000

20,000

22,000

24,000

26,000

MW

Generation

Under Construction

Potential Generation

Existing Generation1

Approved DSM

Proposed and Future DSM

Market Purchases

Generation Under

Development

16,519

3,265

457

2,716

158

36

425
111

Figure 6.7.4(a) ‐ Plan A: Base Plan – Energy Projection (2015 – 2029)

 

Note: 1) Accounts for unit retirements and rating changes to existing units in the Plan.

Figure 6.7.4(b) ‐ Plan B: Fuel Diversity Plan – Energy Projection (2015 – 2029)

Note: 1) Accounts for unit retirements and rating changes to existing units in the Plan.

NUGs

40,000

50,000

60,000

70,000

80,000

90,000

100,000

110,000

120,000 GWh

Generation Under

Construction

Potential Generation

Existing Generation1

Generation

Under Development

Approved DSM

Proposed and Future DSM

Market Purchases

12,052

9,129

9,470

58,647

12,521

693

176

2,370

NUGs

40,000

50,000

60,000

70,000

80,000

90,000

100,000

110,000

120,000 GWh

Generation Under

Construction

Potential Generation

Existing Generation1

Generation

Under Development

Approved DSM

Proposed and Future DSM

Market Purchases

8,052

191

22,873

58,004

12,697

693

176

2,370
112

In addition to maintaining the balance between baseload, intermediate, and peaking capacity, the

Company has considered the fuel mix that would result from its 2014 Plan.  Figure 6.7.5 and Figure

6.7.6 display the Company’s current fuel mix including uranium, coal, oil, natural gas, renewables,

purchased power, and NUGs for the Base Plan and the Fuel Diversity Plan.  Figure 6.7.5 displays

how the Base Plan meets the energy requirements throughout the Study Period.  The Base Plan’s

generation expansion relies almost exclusively on natural gas units as seen in Figure 6.4.1, and

therefore the energy mix throughout the Study Period becomes increasingly dependent on natural

gas.  Figure 6.7.6 illustrates that the Fuel Diversity Plan helps maintain a more balanced, diverse fuel

mix that also continues to include nuclear as a major source of dispatchable baseload energy to

reliably meet the increasing energy requirements throughout the Study Period.   
113

Figure 6.7.5 ‐ Energy by Source (Base Plan)

Figure 6.7.6 ‐ Energy by Source (Fuel Diversity Plan)
114

6.8 CONCLUSIONS

The Company’s 2014 Plan provides a recommended path forward to ensure the Company reliably

meets its customers’ needs for energy and capacity at the lowest reasonable cost.  The Company

proposes to pursue Plan A: Base Plan, while concurrently continuing reasonable development

efforts to preserve the additional resource options identified in Plan B: Fuel Diversity Plan, so that

the Company and its customers are well positioned to meet the challenges of an uncertain industry

future over the long‐term.  Figure 6.8.1 summarizes Plan A: Base Plan from 2015 to 2029.  Figure

6.8.2 provides the additional resources under development between Plan A: Base Plan and Plan B:

Fuel Diversity.

Figure 6.8.1 ‐ Summary of the 2014 Base Plan

Figure 6.8.2 ‐ Additional Resources under Development from the 2014 Fuel Diversity Plan

New

Conventional

New

Renewable

2015 Warren SPP/ SLR NUG

2016 Brunswick SPP/ SLR NUG

2017

2018

2019 CC

2020

2021

2022 CT

2023 CT

2024

2025

2026

2027

2028

2029 CC

Year

Supply‐side Resources

Approved DSM      

Proposed & Future

DSM                

583 MW by 2029    

3,063 GWh by 2029

Demand‐side

Resources

New

Conventional

New

Renewable

2015

2016

2017 SLR/ SLR TAG

2018 OFFD/SLR

2019 SLR

2020 WND/  SLR/   

SLR TAG

2021 WND/ SLR

2022 WND/ SLR

2023 SLR

2024 SLR

2025 SLR

2026 SLR

2027 SLR

2028 North Anna 3 SLR

2029 SLR

Year

Supply‐side Resources

Demand‐side

Resources
115

CHAPTER 7 – SHORT-TERM ACTION PLAN 

The STAP provides the Company’s strategic plan for the next five years (2015 – 2019), as well as a

discussion of the specific short‐term actions the Company is taking to meet the initiatives discussed

in this 2014 Plan.  A combination of developments on the market, technological, and regulatory

fronts over the next five years will likely shape the future of the Company and the utility industry

for many decades to come.  The Company is proactively positioning itself in the short‐term to

address these evolving developments for the benefit of all stakeholders over the long‐term.  Major

components of the Company’s strategy for the next five years are expected to include:

 enhance and upgrade the Company’s existing transmission grid;

 enhance the Company’s access (and deliverability) to natural gas supplies, including shale

gas supplies from the Marcellus and Utica supply basins;

 construct additional generation while maintaining a balanced fuel mix;

 continue to develop and implement a renewable strategy that supports the North Carolina

REPS requirements and the Virginia RPS goals;

 conclude and implement cost‐effective programs that result from the DSM Potential study;  

 continue to implement cost‐effective DSM programs in North Carolina and Virginia; and

 enhance reliability and customer service.

A more detailed discussion of the current and planned activities over the next five years is provided

in the following sections.  

7.1 CURRENT ACTIONS (2014)

Demand‐Side Management:

North Carolina

On August 16, 2012, in Docket No. E‐22, Subs 467 and 469, the Company suspended the Commercial

HVAC Upgrade and Commercial Lighting Programs pursuant to NCUC approval.   On August 20,

2013, the Company filed for NCUC approval in Docket Nos. E‐22, sub 495, 496, 497, 498, 499, and

500, of the six Phase II DSM Programs that were approved in Virginia in Case No. PUE‐2011‐00093,

with the exception of the CDG Program, which was previously denied approval in North Carolina.  

Additionally, in Docket Nos. E‐22, Sub 467 and 469, the Company filed for NCUC approval to

reinitiate the Commercial HVAC Upgrade and Commercial Lighting Programs on a North Carolina‐

only basis.  On December 16, 2013, the NCUC issued Orders approving the six Phase II DSM

Programs, as well as the two NC‐only Programs.  On June 30, 2014, the Company filed for NCUC

approval of the three Phase III Programs that were approved in Virginia in Case No.  

PUE‐2013‐00072.  The Company also received NCUC approval on August 13, 2014 (Docket No. E‐22,

Subs 467 and 469) to close the two North Carolina‐only Commercial HVAC Upgrade and

Commercial Lighting Programs.  Additionally, the Company has filed to amend the Low Income

Program to a North Carolina‐only Program for 2015, due to closure of that Program in Virginia as of

December 31, 2014.  The request is pending before the NCUC.
116

Virginia

On August 31, 2012, in Case No. PUE‐2012‐00100, the Company applied to extend the Residential

Air Conditioner Cycling and Low Income Programs in Virginia.  Both these programs were

approved for extension by the SCC in April 2013.  On August 30, 2013, the Company applied for

SCC approval of three new DSM Programs: Lighting Systems and Controls, Heating and Cooling

Efficiency, and Solar Window Film (Phase III), as well as an expansion of the Non‐Residential

Energy Audit Program, as discussed in Chapter 3 (Case No. PUE‐2013‐00072).  In its April 29, 2014

Order, the SCC approved the Company’s petition to implement all three programs and the

expansion of the Energy Audit Program.  The Company filed its “Phase IV” DSM Application on

August 29, 2014, seeking approval of three new energy efficiency DSM Programs: Income and Age

Qualifying Home Improvement, Residential Appliance Recycling, and Qualifying Small Business

Improvement (Case No. PUE‐2014‐00071).

Advanced Metering Infrastructure:

The Company is currently installing AMI, or smart meters, on homes and businesses in areas

throughout Virginia.  AMI has demonstrated the effectiveness of the technology in achieving voltage

conservation, remotely turning off and on electric service, power outage and restoration detection

and reporting, remote daily meter readings, and offering dynamic rates.   

Conventional Generation:  

 Solar Partnership Program 13 MW (nameplate) of PV solar DG – is under construction and is

expected to be complete by 2015.

 Warren County Power Station (1,337 MW), approved on February 2, 2012, is currently under

construction.

 Brunswick County Power Station (1,375 MW), approved on August 2, 2013, is currently

under construction.

 Continue the early stage development of a natural gas fueled CC facility, forecasted to be

completed in 2019.

 Continue reasonable development efforts associated with the North Anna 3 Nuclear Unit.

Transmission:

Virginia:  

The following planned Virginia transmission projects detailed in Figure 7.2.6 are pending SCC

approval or are tentatively planned for filing with the SCC in 2014:

 Warrenton/Wheeler/Gainesville 230 kV Lines from Wheeler and Vint Hill Stations.

 Elmont – Cunningham 500 kV Line Rebuild.

 Mosby – Brambleton 500 kV Line.

 230 kV Line Extension to new Pacific Substation.

 230 kV Line Extension to new Haymarket Substation.

 230 kV Line Extension to new Poland Road and Broad Run Substations.
117

 Glebe – Station C 230 kV Line.

Renewable Energy Resources:

Approximately 575 MW of qualifying renewable generation is currently in operation.  The Company

has one contracted renewable NUG facility at Covanta Fairfax that will provide approximately 63

MW in 2013.  The Company has recently entered into PPAs with approximately 100 MW of North

Carolina solar NUGs with estimates of an additional 100 MW by 2016.

North Carolina:

 North Carolina REPS Compliance Report – The Company achieved its 2013 solar set‐aside

and general obligation requirement, which is detailed in its annual REPS Compliance Report

submitted on August 28, 2014.  

 North Carolina REPS Compliance Plan – The Company submitted its annual REPS

Compliance Plan, which is filed as North Carolina IRP Addendum 1 to this 2014 Plan.  

Virginia:

 Virginia RPS Program – The Company plans to meet its 2014 target by applying renewable

generation from existing qualified facilities and purchasing cost‐effective RECs.

 Virginia Annual Report – On November 1, 2014, the Company intends to submit its Annual

Report to the SCC, as required, detailing its efforts towards the RPS plan.

7.2 FUTURE ACTIONS (2015 – 2019)

DSM PROGRAMS

Figure 7.2.1 lists the projected demand and energy savings by 2019 from the approved, proposed

and future DSM programs.  
118

Figure 7.2.1 ‐ DSM Projected Savings By 2019

GENERATION ADDITIONS AND CHANGES:

Figure 7.2.2 lists the generation plants that are currently under construction and are expected to be

operational by 2019.  Figure 7.2.3 lists the generation plants that are currently under development

and are expected to be operational by 2019.  

Figure 7.2.2 ‐ Generation under Construction

Note: 1) Commercial Operation Date.

Figure 7.2.3 ‐ Generation under Development1

Note: 1) All Generation under Development projects and planned capital expenditures are preliminary in nature and subject to regulatory

and/or Board of Directors approvals.

Program Projected MW

Reduction

Projected GWh

Savings

Status (VA/NC)

Air Conditioner Cycling Program 189 0

Residential Low Income Program 2 10

Residential Lighting 22 240 Completed/Completed

Commercial Lighting 15 121

Commercial Heating Vent and AC 1 4

Non‐Residential Distributed Generation Program 21 1 Approved/Rejected

Non‐Residential Energy Audit Program 21 102

Non‐Residential Duct & Sealing Program 18 67

Residential Bundle Program 62 238

Residential Home Energy Check‐Up Program 2 7

Residential Duct & Sealing Program 6 9

Residential Heat Pump Tune Up Program 12 67

Residential Heat Pump Upgrade Program 42 155

Non‐Residential Window Film Program 19 78

Non‐Residential Lighting 28 100

Non‐Residential Heating Vent 27 34

Proposed Elderly and Income Qualifying Audit Program 3 12

Proposed Residential Appliance Recycling 7 35

Proposed Non‐Residential Small Business Audit 60 86

Voltage Conservation Program 0 660

Non Residential Custom Incentive 51 201

Approved/Proposed

Approved/Approved

Closed/Pending Closure

Approved/Approved

Proposed/Future

Future/Future

Summer Winter

2015 Warren County Power Station Warren County, VA Natural Gas Intermediate/ Baseload 1,337 1,437

2015 Solar Partnership Program VA Solar Intermittent 8 8

2016 Solar Partnership Program VA Solar Intermittent 5 5

2016 Brunswick County Power Station Brunswick, VA Natural Gas Intermediate/ Baseload 1,375 1,509

Capacity (Net MW) Location Primary Fuel Unit TypeForecasted

COD1 Unit Name

Summer Winter

2017 Solar VA Renewable Intermittent 40 15 15

2017 Solar Tag VA Renewable Intermittent 4 2 2

2018 Solar VA Renewable Intermittent 40 15 15

2018 Offshore Wind Demonstration Project VA Wind Intermittent 12 2 2

2019 Combined Cycle VA Natural Gas Intermediate/Baseload 1,566 1,566 1,614

Forecasted Capacity (Net MW)

COD Unit Location Primary Fuel Unit Type Nameplate Capacity  (MW)
119

GENERATION UPRATES/DERATES:

Figure 7.2.4 lists the Company’s planned changes to existing generating units.  

Figure 7.2.4 ‐ Changes to Existing Generation  

GENERATION RETIREMENTS:

The Company plans to retire the units listed in Figure 7.2.5.  

Figure 7.2.5 – Generation Retirements1

Note: (1) Reflects retirement assumptions used for planning purposes, not firm Company commitments.

Transmission:

Figure 7.2.6 lists the major transmission additions including line voltage and capacity, expected

operation target dates, and their regulatory status.  

Unit Name Type MW

Year

Effective

Possum Point 5 SNCR ‐ 2018

Yorktown 3 SNCR ‐ 2018

Unit Name MW Summer Year Effective

Chesapeake 1 111 2015

Chesapeake 2 111 2015

Chesapeake 3 149 2015

Chesapeake 4 207 2015

Possum Point CT 72 2015

Yorktown 1 159 2016

Yorktown 2 164 2016

Lowmoor CT 48 2016

Mt. Storm CT 11 2016

Northern Neck CT 47 2017
120

Figure 7.2.6 ‐ Planned Transmission Additions

Note: Asterisk reflects planned transmission addition subject to change based on inclusion in future PJM RTEP and/or receipt of applicable

regulatory approval(s).

RENEWABLE RESOURCES:

North Carolina:

 The Company’s strategy to meet the North Carolina REPS requirements is outlined in the

Company’s 2013 REPS Compliance Plan, filed as North Carolina IRP Addendum 1 to this

2014 Plan.  

 Solar requirements will be met by purchasing unbundled solar RECs.  The Company has

procured the solar RECs necessary to comply with the North Carolina REPS solar

requirements for 2013.  

 The Company continues to develop its plans to comply with swine and poultry waste

requirements.   

Line Terminal

Line Voltage

(kV)

Line Capacity

(MVA) Target Date Location

Roanoke Industrial Park 115kV DP 115 261 Sep‐14 NC

Dooms to Bremo 230kV Transmission Line Rebuild 115 180 Oct‐14 VA

Cannon Branch to Cloverhill ‐ New 230kV Line 230 1,047 Dec‐14 VA

Rebuild Line #551 (Mt Storm ‐ Doubs) 500 4,334 Dec‐14 VA

Ridge Road Sub and Build Double Circuit 115kV Lines 115 261 Apr‐15 VA

Uprate Line 2022 ‐ Possum Point to Dumfries Substation 230 797 May‐15 VA

Line #262 Rebuild (Yadkin ‐ Chesapeake EC) 230 1,047 May‐15 VA

Shawboro – Aydlett Tap 230kV Line 230 751 May‐15 NC

Cloverhill to Liberty ‐ New 230kV Line 230 1,047 May‐15 VA

Convert Line 64 to 230kV and Install 230kV Capacitor Bank at Winfall 230 775 (#2131)      

840(#2126) Jun‐15 NC

Line 32 Rebuild 115 240 Jun‐15 VA

Line #2020 Rebuild Winfall ‐ Elizabeth City 230 1,047 Jun‐15 NC

Yadkin ‐ Chesapeake increase 115 kV Capacity 115 398 Jun‐15 VA

Line #22 Rebuild  Kerr Dam ‐ Eatons Ferry 115 262 Jun‐15 VA/NC

Line #30 Rebuild (Altivista to Skimmer) 115 239 Jun‐15 VA

2nd 230kV Line Harrisonburg to Endless Caverns 230 1,047 Jun‐15 VA

Line #17 Uprate Shockoe ‐ Northeast and Terminate Line #17 at Northeast 115 231 Jul‐15 VA

Line #222 Uprate from Northwest to Southwest 230 706 Jul‐15 VA

New 115kV DP to Replace Pointon 34.5kV DP ‐ SEC 115 230 Jul‐15 VA

Line #201 Rebuild 230 1,200 Nov‐15 VA

Burton Switching Station and 115 kV Line to Oakwood 115 233 Dec‐15 VA

Surry ‐ Skiffes Creek 500 kV Line 500 4,325 Apr‐16 VA

Skiffes Creek ‐ Whealton 230 kV Line 230 1,047 Apr‐16 VA

Line #2090 Uprate 230 1,195 May‐16 VA

Line #2032 Uprate (Elmont ‐ Four Rivers) 230 1,195 May‐16 VA

Loudoun – Pleasant View Line #558 Rebuild 500 4,000 May‐16 VA

Line #2104 Reconductor and Upgrade 230 1,047 May‐16 VA

Rebuild Line #2027 (Bremo ‐ Midlothian) 230 1,047 May‐16 VA

230kV Line Extension to new Pacific Substation 230 1,047 May‐16 VA

Line #11 ‐ Rebuild or Reconductor from Gordonsville to Somerset 115 353 May‐16 VA

Rebuild Dooms to Lexington 500 kV Line 500 4,000 Jun‐16 VA

Line #33 Rebuild and Halifax 230kV Ring Bus 115 353 Jun‐16 VA

Line #22 Rebuild Carolina ‐ Eatons Ferry 115 262 Jun‐16 NC

Line #54 Reconductor   Carolina ‐ Woodland 115 306 Jun‐16 NC

New 230kV Line Dooms to Lexington 230 1,047 Jun‐16 VA

230kV Line Extension to new Haymarket Substation 230 1,047 May‐17 VA

*Network Line 2086 from Warrenton 230 1,047 May‐17 VA

*Idylwood to Scotts Run – New 230kV Line and Scotts Run Substation 230 1,047 May‐17 VA

Line #69 Uprate Reams DP to Purdy 115 300 Jun‐17 VA

Line #47 Rebuild 115 353 May‐18 VA

* Reconfigure Line #4 Bremo to Cartersville 115 89 May‐18 VA

Line #553 (Cunningham to Elmont) Rebuild and Uprate 500 4,000 Jun‐18 VA
121

 The Company intends to meet the general REPS requirements with a combination of:

o energy efficiency programs;

o Company‐generated renewable resources;

o purchase of cost‐effective RECs; and  

o development of new renewable resources when and where feasible.

Virginia:

Figure 7.2.7 lists the Company’s future renewable resources within the first five years of the Plan.

 The Base Plan and Fuel Diversity Plan include 112 MW (nameplate) of renewable resources.  

Plan B: Fuel Diversity Plan also identifies an additional 136 MW (nameplate) of renewable

resources to be online by 2019 (Figure 7.2.7).  The Company plans to meet its Virginia RPS

goals at a reasonable cost and in a prudent manner by:  

o application of current renewable generating facilities including NUGs;

o purchase of cost‐effective RECs;  

o continuation of reasonable development efforts associated with new renewable

resources; and

o continuation of reasonable developmental efforts associated with offshore wind.

Figure 7.2.7 ‐ Future Renewable Resources

 

Key: A: Plan A: Base Plan; B: Plan B: Fuel Diversity.

OTHER INITIATIVES:

As discussed in Section 5.4, the Company is currently pursuing other technologies and resources

within the next five years including:

 Solar Power Partnership and Purchase Programs ‐ In response to Chapter 771 of the 2011

Virginia Acts of Assembly that promoted solar DG, the Company filed for and received

approval for a solar DG demonstration program with two components: the Solar Partnership

Program and the Solar Purchase Program.  In the Solar Partnership Program, the Company

installs solar panels on public and private property at strategic sites in its Virginia service

area to study the impact and assess the benefits to the distribution system.  The Solar

Resource Name Year Type Nameplate 

Capacity (MW)

Firm Capacity 

(MW) Plan

Solar NUG 2015 Solar 50 19 A, B

Solar Partnership Program 2015 Distributed Solar 7 4 2 1 A, B

Solar NUG 2016 Solar 50 19 A, B

Solar Partnership Program 2016 Distributed Solar 4 9 1 4 A, B

Solar 2017 Solar 40 15 B

Solar Tag 2017 Solar 4 2 B

Solar 2018 Solar 40 15 B

Offshore Wind Demonstration Project 2018 Wind 12 2 B

Solar 2019 Solar 40 15 B

Total 248.70 90.09
122

Purchase Program provides the opportunity for customers to sell solar generation output

and renewable energy certificates to the Company.   

 Rate Schedule RG – In December 2013, the Company received SCC approval of a

demonstration program to offer large non‐residential customers in Virginia the ability to

purchase a greater percentage of their energy needs from renewable energy resources than

they currently receive from the company’s existing generation mix.   The Company provides

this offering under Rate Schedule RG, a voluntary companion rate to customers taking

service under the GS‐3 and GS‐4 rates.  Rate Schedule RG allows qualifying non‐residential

customers to choose the percentage of their energy requirements that they want to meet with

renewable resources.   

 EV Pilot Program ‐ On July 11, 2011, in Case No. PUE‐2011‐00014, the SCC approved the

Company’s petition for a pilot program to offer experimental and voluntary EV rate options,

providing incentives to residential customers who purchase or lease EVs to charge them

during off‐peak periods.  In November 2013, the SCC approved an extension of the Pilot for

two additional years.  The program is open to up to 1,500 residential customers, with up to

750 in each of the two experimental rates.  Pilot enrollment began October 3, 2011, and the

Pilot will conclude on November 30, 2016.  If warranted by the results of the Pilot program,

the Company plans to request approval of a Virginia service territory EV peak‐shaving

program in the future.
AP ‐ 1

APPENDIX 
AP ‐ 2

Appendix 2A – Total Sales by Customer Class  

(DOM LSE) (GWh)

Note: Historic (2004 – 2013), Projected (2014 – 2029).

Year Residential Commercial Industrial Public

Authority

Street

and

Traffic

Lighting

Sales

for

Resale

Total

2004 28,249                               25,878              10,843                 9,798                          284                 2,216              77,268

2005 29,942                               27,023              10,331              10,120                          280                 1,778              79,474

2006 28,544                               27,078              10,168              10,040                          282                 1,841              77,952

2007 30,469                               28,416              10,094              10,660                          283                 1,995              81,917

2008 29,646                               28,484                 9,779              10,529                          282                 1,926              80,646

2009 29,904                               28,455                 8,644              10,448                          276                 1,909              79,635

2010 32,547                               29,233                 8,512              10,670                          281                 1,980              83,223

2011 30,779                               28,957                 7,960              10,555                          273                 2,013              80,538

2012 29,174                               28,927                 7,849              10,496                          277                 1,947              78,671

2013 30,380                               29,611                 8,097              10,413                          278                 1,961              80,740

2014 30,543                               30,301                 8,631              10,634                          299                 1,955              82,364

2015 30,717                               32,224                 8,751              10,780                          301                 1,940              84,712

2016 31,190                               33,617                 8,734              10,820                          306                 1,961              86,629

2017 31,800                               34,453                 8,624              10,856                          314                 1,986              88,032

2018 32,330                               35,236                 8,503              10,858                          319                 2,017              89,262

2019 32,836                               35,655                 8,426              10,850                          324                 2,039              90,129

2020 33,330                               36,354                 8,396              10,871                          328                 2,062              91,341

2021 33,671                               36,895                 8,338              10,921                          331                 2,079              92,236

2022 34,108                               37,569                 8,283              10,933                          335                 2,100              93,328

2023 34,535                               38,241                 8,232              11,017                          339                 2,123              94,487

2024 35,081                               38,948                 8,200              11,064                          342                 2,150              95,786

2025 35,449                               39,489                 8,166              11,008                          346                 2,170              96,629

2026 35,904                               40,134                 8,134              11,042                          349                 2,195              97,758

2027 36,334                               40,850                 8,107              11,039                          353                 2,220              98,904

2028 36,899                               41,622                 8,101              11,070                          356                 2,249            100,297

2029 37,353                               42,146                 8,050              11,103                          360                 2,271            101,282
AP ‐ 3

Appendix 2B– North Carolina Sales by Customer Class 

(DOM LSE) (GWh)

Note: Historic (2004 – 2013), Projected (2014 – 2029).

Year Residential Commercial Industrial Public

Authority

Street

and

Traffic

Lighting

Sales

for

Resale

Total

2004 1,479                                        769                 1,792                    146                               8                      45                 4,239

2005 1,583                                        780                 1,709                    143                               8                      43                 4,267

2006 1,477                                        775                 1,763                    137                               8                      87                 4,247

2007 1,579                                        810                 1,735                    140                               8                      89                 4,362

2008 1,546                                        806                 1,715                    138                               8                      49                 4,262

2009 1,579                                        809                 1,497                    136                               8                      49                 4,078

2010 1,716                                        825                 1,640                    141                               8                      52                 4,381

2011 1,626                                        795                 1,618                    132                               8                      51                 4,230

2012 1,502                                        864                 1,614                    126                               8                      50                 4,165

2013 1,578                                        893                 1,703                    128                               8                      50                 4,360

2014 1,598                                        883                 1,510                    138                               9                      54                 4,191

2015 1,607                                        919                 1,531                    140                               9                      55                 4,260

2016 1,631                                        949                 1,528                    140                               9                      55                 4,314

2017 1,663                                        970                 1,508                    141                               9                      56                 4,347

2018 1,691                                        985                 1,485                    141                               9                      57                 4,369

2019 1,718                                        997                 1,472                    141                             10                      57                 4,394

2020 1,744                                    1,017                 1,466                    141                             10                      58                 4,436

2021 1,762                                    1,033                 1,455                    142                             10                      59                 4,459

2022 1,785                                    1,052                 1,445                    142                             10                      59                 4,493

2023 1,807                                    1,072                 1,436                    142                             10                      60                 4,527

2024 1,836                                    1,092                 1,430                    144                             10                      60                 4,572

2025 1,855                                    1,108                 1,424                    143                             10                      61                 4,601

2026 1,879                                    1,127                 1,418                    143                             10                      61                 4,638

2027 1,902                                    1,147                 1,413                    143                             10                      62                 4,677

2028 1,931                                    1,170                 1,412                    143                             10                      63                 4,729

2029 1,955                                    1,185                 1,402                    144                             11                      63                 4,760
AP ‐ 4

Appendix 2C – Virginia Sales by Customer Class 

(DOM LSE) (GWh)

Note: Historic (2004 – 2013), Projected (2014 – 2029).

Year Residential Commercial Industrial

Public

Authority

Street

and

Traffic

Lighting

Sales

for

Resale

Total

2004 26,771                               25,109                 9,051                 9,652                          275                 2,216              73,029

2005 28,359                               26,243                 8,621                 9,976                          272                 1,778              75,207

2006 27,067                               26,303                 8,404                 9,903                          274                 1,841              73,705

2007 28,890                               27,606                 8,359              10,519                          274                 1,995              77,556

2008 28,100                               27,679                 8,064              10,391                          273                 1,926              76,384

2009 28,325                               27,646                 7,147              10,312                          268                 1,909              75,558

2010 30,831                               28,408                 6,872              10,529                          273                 1,980              78,842

2011 29,153                               28,163                 6,342              10,423                          265                 2,013              76,309

2012 27,672                               28,063                 6,235              10,370                          269                 1,947              74,507

2013 28,802                               28,718                 6,394              10,285                          270                 1,961              76,380

2014 28,946                               29,418                 7,122              10,496                          290                 1,901              78,173

2015 29,110                               31,305                 7,219              10,640                          292                 1,885              80,452

2016 29,559                               32,668                 7,205              10,680                          297                 1,905              82,315

2017 30,136                               33,483                 7,115              10,715                          305                 1,930              83,685

2018 30,639                               34,251                 7,017              10,717                          310                 1,960              84,893

2019 31,118                               34,658                 6,954              10,709                          314                 1,981              85,735

2020 31,586                               35,337                 6,930              10,730                          318                 2,004              86,905

2021 31,910                               35,862                 6,883              10,779                          322                 2,021              87,776

2022 32,323                               36,517                 6,837              10,791                          325                 2,041              88,836

2023 32,728                               37,170                 6,796              10,874                          329                 2,063              89,961

2024 33,245                               37,856                 6,770              10,920                          332                 2,090              91,213

2025 33,594                               38,381                 6,742              10,865                          336                 2,109              92,028

2026 34,025                               39,007                 6,716              10,899                          339                 2,134              93,120

2027 34,433                               39,703                 6,695              10,896                          343                 2,158              94,227

2028 34,968                               40,452                 6,689              10,927                          346                 2,186              95,567

2029 35,398                               40,961                 6,647              10,959                          349                 2,208              96,522
AP ‐ 5

Appendix 2D – Total Customer Count 

(DOM LSE)

Note: Historic (2004 – 2013), Projected (2014 – 2029).

Year Residential Commercial Industrial Public

Authority

Street

and

Traffic

Lighting

Sales

for

Resale

Total

2004 1,998,691                         216,186                    684              27,910                 2,275                         5         2,245,751

2005 2,036,041                         219,837                    655              28,233                 2,426                         5         2,287,197

2006 2,072,726                         223,961                    635              28,540                 2,356                         5         2,328,223

2007 2,102,751                         227,829                    620              28,770                 2,347                         4         2,362,320

2008 2,124,089                         230,715                    598              29,008                 2,513                         3         2,386,925

2009 2,139,604                         232,148                    581              29,073                 2,687                         3         2,404,097

2010 2,157,581                         232,988                    561              29,041                 2,798                         3         2,422,972

2011 2,171,795                         233,760                    535              29,104                 3,031                         3         2,438,227

2012 2,187,670                         234,947                    514              29,114                 3,246                         3         2,455,495

2013 2,206,657                         236,596                    526              28,847                 3,508                         3         2,476,138

2014 2,228,237                         237,810                    622              28,918                 3,654                         3         2,499,244

2015 2,248,750                         239,872                    621              29,045                 3,796                         3         2,522,086

2016 2,284,842                         243,075                    619              29,142                 3,940                         3         2,561,622

2017 2,333,811                         247,258                    618              29,288                 4,084                         3         2,615,062

2018 2,369,545                         250,111                    614              29,479                 4,227                         3         2,653,979

2019 2,398,308                         252,732                    612              29,581                 4,371                         3         2,685,606

2020 2,424,854                         255,204                    611              29,665                 4,515                         3         2,714,852

2021 2,450,409                         257,613                    610              29,740                 4,659                         3         2,743,034

2022 2,475,273                         259,976                    609              29,806                 4,803                         3         2,770,470

2023 2,499,527                         262,301                    608              29,866                 4,947                         3         2,797,251

2024 2,523,127                         264,583                    606              29,918                 5,091                         3         2,823,329

2025 2,546,402                         266,844                    605              29,964                 5,235                         3         2,849,053

2026 2,569,717                         269,106                    604              30,006                 5,379                         3         2,874,815

2027 2,593,049                         271,370                    603              30,044                 5,523                         3         2,900,592

2028 2,615,943                         273,608                    602              30,079                 5,667                         3         2,925,902

2029 2,638,306                         275,810                    600              30,109                 5,811                         3         2,950,639
AP ‐ 6

Appendix 2E – North Carolina Customer Count 

(DOM LSE)

Note: Historic (2004 – 2013), Projected (2014 – 2029).

Year Residential Commercial Industrial Public

Authority

Street

and

Traffic

Lighting

Sales

for

Resale

Total

2004 96,906                                15,228                      79                 1,894                    362                         2            114,470

2005 98,235                                15,380                      70                 1,890                    364                         2            115,942

2006 99,296                                15,406                      69                 1,886                    363                         2            117,021

2007 99,867                                15,460                      66                 1,874                    376                         2            117,645

2008 100,497                              15,502                      60                 1,867                    397                         1            118,324

2009 100,761                              15,485                      59                 1,867                    398                         1            118,572

2010 101,005                              15,457                      56                 1,857                    395                         1            118,771

2011 101,009                              15,418                      53                 1,852                    392                         1            118,725

2012 101,024                              15,501                      50                 1,849                    390                         1            118,815

2013 101,158                              15,557                      50                 1,851                    390                         1            119,007

2014 101,529                              15,629                      50                 1,850                    394                         1            119,453

2015 101,902                              15,701                      50                 1,850                    398                         1            119,901

2016 102,276                              15,773                      50                 1,849                    402                         1            120,351

2017 102,651                              15,846                      50                 1,848                    406                         1            120,803

2018 103,028                              15,919                      50                 1,848                    410                         1            121,256

2019 103,407                              15,992                      50                 1,847                    414                         1            121,711

2020 103,786                              16,066                      50                 1,847                    418                         1            122,168

2021 104,167                              16,140                      50                 1,846                    422                         1            122,627

2022 104,550                              16,214                      50                 1,846                    427                         1            123,087

2023 104,933                              16,289                      50                 1,845                    431                         1            123,549

2024 105,319                              16,364                      50                 1,844                    435                         1            124,013

2025 105,705                              16,439                      50                 1,844                    439                         1            124,479

2026 106,093                              16,515                      50                 1,843                    444                         1            124,947

2027 106,483                              16,591                      50                 1,843                    448                         1            125,416

2028 106,874                              16,668                      50                 1,842                    453                         1            125,887

2029 107,266                              16,745                      50                 1,842                    457                         1            126,360
AP ‐ 7

Appendix 2F – Virginia Customer Count 

(DOM LSE)

Note: Historic (2004 – 2013), Projected (2014 – 2029).

Year Residential Commercial Industrial Public

Authority

Street

and

Traffic

Lighting

Sales

for

Resale

Total

2004 1,901,785                         200,958                    606              26,017                 1,913                         3         2,131,281

2005 1,937,806                         204,457                    585              26,343                 2,062                         3         2,171,255

2006 1,973,430                         208,556                    566              26,654                 1,994                         3         2,211,202

2007 2,002,884                         212,369                    554              26,896                 1,971                         2         2,244,675

2008 2,023,592                         215,212                    538              27,141                 2,116                         2         2,268,601

2009 2,038,843                         216,663                    522              27,206                 2,290                         2         2,285,525

2010 2,056,576                         217,531                    504              27,185                 2,404                         2         2,304,202

2011 2,070,786                         218,341                    482              27,252                 2,639                         2         2,319,502

2012 2,086,647                         219,447                    464              27,265                 2,856                         2         2,336,680

2013 2,105,500                         221,039                    477              26,996                 3,118                         2         2,357,131

2014 2,126,708                         222,181                    572              27,068                 3,259                         2         2,379,790

2015 2,146,848                         224,172                    571              27,195                 3,398                         2         2,402,185

2016 2,182,566                         227,302                    570              27,293                 3,538                         2         2,441,271

2017 2,231,159                         231,412                    568              27,440                 3,678                         2         2,494,259

2018 2,266,516                         234,192                    564              27,632                 3,817                         2         2,532,723

2019 2,294,901                         236,739                    563              27,733                 3,957                         2         2,563,895

2020 2,321,067                         239,138                    561              27,819                 4,097                         2         2,592,684

2021 2,346,242                         241,473                    560              27,894                 4,237                         2         2,620,408

2022 2,370,723                         243,762                    559              27,961                 4,376                         2         2,647,383

2023 2,394,594                         246,012                    558              28,021                 4,516                         2         2,673,702

2024 2,417,808                         248,219                    557              28,074                 4,656                         2         2,699,316

2025 2,440,696                         250,404                    555              28,121                 4,796                         2         2,724,574

2026 2,463,624                         252,591                    554              28,163                 4,935                         2         2,749,868

2027 2,486,566                         254,779                    553              28,201                 5,075                         2         2,775,176

2028 2,509,070                         256,940                    552              28,237                 5,214                         2         2,800,014

2029 2,531,039                         259,066                    551              28,267                 5,354                         2         2,824,279
AP ‐ 8

Appendix 2G – Summer & Winter Peaks

(1) Adjusted load from Appendix 2H.

(2) Includes firm Additional Forecast, Conservation Efficiency, and Peak Adjustments from Appendix 2H.

Company Name: Virginia Electric and Powe r Company

POWER SUPPLY DATA

(ACTUAL) (PROJECTED)

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 

II. Load (MW)

1. Summe r

a. Adjus ted Summer Pe ak(1) 17,635 16,897 16,469 17,650 18,148 18,734 19,065 18,291 18,507 18,702 18,963 19,219 19,469 19,702 19,937 

b. Othe r Commitments(2) ‐114 ‐110 ‐103 ‐379 ‐478 ‐735 ‐719 344 391 413 406 396 394 397 399 c. Total System Summer Peak 17,521 16,787 16,366 17,271 17,670 17,999 18,347 18,635 18,898 19,114 19,369 19,615 19,863 20,099 20,336 d. Pe rcent Incre ase in Total

Summe r Pe ak 4.4% ‐4.2% ‐2.5% 5.5% 2.3% 1.9% 1.9% 1.6% 1.4% 1.1% 1.3% 1.3% 1.3% 1.2% 1.2% 

2. Winte r

a. Adjus ted Winter Pe ak(1) 15,358 14,654 15,209 14,828 14,832 15,010 15,189 15,399 15,505 15,628 15,774 15,954 16,137 16,319 16,493 b. Othe r Commitments(2) ‐114 ‐110 ‐103 ‐86 99 156 219 259 303 327 322 308 298 300 302 c. Total System Winter Peak 15,244 14,544 15,106 14,742 14,931 15,166 15,407 15,658 15,808 15,955 16,096 16,263 16,435 16,620 16,795 d. Pe rcent Incre ase in Total

Winte r Pe ak 0.4% ‐4.6% 3.9% ‐2.4% 1.3% 1.6% 1.6% 1.6% 1.0% 0.9% 0.9% 1.0% 1.1% 1.1% 1.1% 
AP ‐ 9

Appendix 2H – Projected Summer & Winter Peak Load & Energy Forecast

(1) Actual metered data.

(2) Demand response programs are classified as capacity resources and are not included in adjusted load.

(3) Existing DSM programs are included in the load forecast.

(4) Actual historical data based upon measured and verified EM&V results.

(5) Actual historical data based upon measured and verified EM&V results. Projected values represent modeled DSM firm capacity.

(6) Future BTM, which is not included in the Base forecast.

Company Name: Virginia Electric and Powe r Company

I. PEAK LOAD AND ENERGY FORECAST

(ACTUAL)(1) (PROJECTED)

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 

1. Utility Pe ak Load (MW)

A. Summe r

1a. Base Forecast 17,521 16,787 16,366 17,271 17,670 17,999 18,347 18,635 18,898 19,114 19,369 19,615 19,863 20,099 20,336 20,578 

1b. Additional Forecast

NCEMC 150 150 150 150                 ‐ ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐              ‐               ‐               ‐               

  

2. Conse rva tion, Efficiency(5) ‐36 ‐40 ‐47 ‐65 ‐107 ‐172 ‐232 ‐289 ‐336 ‐358 ‐351 ‐341 ‐339 ‐342 ‐344 ‐346 3. Demand Re sponse(2)(5) ‐51 ‐83 ‐83 ‐123 ‐136 ‐152 ‐171 ‐190 ‐210 ‐219 ‐219 ‐218 ‐218 ‐219 ‐221 ‐223 4. Demand Re sponse‐Existing(2)(3) ‐6 ‐7 ‐5 ‐5 ‐5 ‐5 ‐5 ‐5 ‐5 ‐5 ‐5 ‐5 ‐5 ‐5 ‐5 ‐5 5. Pe ak Adjustment               ‐ ‐               ‐ 294 585 907 951 ‐55 ‐55 ‐55 ‐55 ‐55 ‐55 ‐55 ‐55 ‐55 6. Adjus ted Load 17,635 16,897 16,469 17,650 18,148 18,734 19,065 18,291 18,507 18,702 18,963 19,219 19,469 19,702 19,937 20,177 7. % Incre ase in Adjus ted Load 4.3% ‐4.2% ‐2.5% 7.2% 2.8% 3.2% 1.8% ‐4.1% 1.2% 1.1% 1.4% 1.4% 1.3% 1.2% 1.2% 1.2% 

(from previous year)

B. Winter

1a. Base Forecast 15,244 14,544 15,106 14,742 14,931 15,166 15,407 15,658 15,808 15,955 16,096 16,263 16,435 16,620 16,795 16,977 

1b. Additional Forecast

NCEMC 150 150 150 150                 ‐ ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐              ‐               ‐               ‐               

  

2. Conse rva tion, Efficiency(5) ‐36 ‐40 ‐47 ‐64 ‐99 ‐156 ‐219 ‐259 ‐303 ‐327 ‐322 ‐308 ‐298 ‐300 ‐302 ‐304 3. Demand Re sponse(2)(4) ‐10 ‐16 ‐15 ‐21 ‐17 ‐15 ‐17 ‐19 ‐21 ‐23 ‐24 ‐25 ‐26 ‐27 ‐28 ‐29 4. Demand Re sponse‐Existing(2)(3) ‐8 ‐6 ‐5 ‐5 ‐5 ‐5 ‐5 ‐5 ‐5 ‐5 ‐5 ‐5 ‐5 ‐5 ‐5 ‐5 5. Adjus ted Load 15,358 14,654 15,209 14,828 14,832 15,010 15,189 15,399 15,505 15,628 15,774 15,954 16,137 16,319 16,493 16,673 6. % Incre ase in Adjus ted Load 0.3% ‐4.6% 3.8% ‐2.5% 0.0% 1.2% 1.2% 1.4% 0.7% 0.8% 0.9% 1.1% 1.1% 1.1% 1.1% 1.1% 

2. Ene rgy (GWh)

A. Base Forecast 83,393 81,498 83,311 85,777 88,174 90,297 91,760 93,043 93,946 95,208 95,976 97,146 98,331 99,496 100,644 101,816 1B. Additional Forecast

NCEMC               ‐ ‐               ‐ 676                 ‐ ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐              ‐               ‐               ‐               

  

Future BTM(6)               ‐ ‐               ‐               ‐410 ‐410 ‐410 ‐410 ‐410 ‐410 ‐410 ‐410 ‐410 ‐410 ‐410 ‐410 ‐410 

C. Conse rva tion & Demand Re sponse(5) ‐294 ‐338 ‐351 ‐529 ‐676 ‐885 ‐1,126 ‐1,552 ‐1,988 ‐2,334 ‐2,560 ‐2,762 ‐3,025 ‐3,179 ‐3,037 ‐3,042 D. Demand Re sponse‐Exis ting(2)(3)               ‐ ‐               ‐               ‐                ‐                 ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐              ‐               ‐               ‐               

  

E. Adjusted Ene rgy 83,099 81,160 82,960 85,515 87,089 89,003 90,225 91,081 91,548 92,465 93,007 93,975 94,897 95,908 97,197 98,364 F. % Incre ase in Adjusted Ene rgy ‐3.9% ‐2.3% 2.2% 3.1% 1.8% 2.2% 1.4% 0.9% 0.5% 1.0% 0.6% 1.0% 1.0% 1.1% 1.3% 1.2% 
AP ‐ 10

Appendix 2I – Required Reserve Margin

(1) To be calculated based on Total Net Capability for summer and winter.

(2) The Company and PJM forecasts a summer peak throughout the Planning Period.

(3) Does not include spot purchases of capacity.(4) The Company follows PJM reserve requirements which are based on LOLE.

Company Name: Virginia Electric and Powe r Company 

POWER SUPPLY DATA (continued)

(ACTUAL) (PROJECTED)

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 

I. Reserve Margin(1)

(Including Cold Reserve Capability)

1. Summe r Re se rve Margin

a. MW(1) 1,201 2,473 3,026 2,616 2,855 3,263 2,850 2,049 2,073 2,095 2,343 2,325 2,530 2,298 2,233 

b. Pe rcent of Load 6.8% 14.6% 18.4% 14.8% 15.7% 17.4% 15.0% 11.2% 11.2% 11.2% 12.4% 12.1% 13.0% 11.7% 11.2% c. Actual Re se rve Margin(3) N/A N/A N/A 13.2% 15.6% 17.1% 11.8% 9.4% 15.3% 14.0% 12.4% 12.1% 13.0% 11.7% 10.4% 

2. Winte r Rese rve Margin

a. MW(1) N/A N/A N/A 5,497 6,263 5,561 6,501 5,304 7,658 7,263 7,073 7,134 7,416 7,235 7,062 

b. Pe rcent of Load N/A N/A N/A 37.1% 42.2% 37.0% 42.8% 34.4% 49.4% 46.5% 44.8% 44.7% 46.0% 44.3% 42.8% c. Actual Re se rve Margin(3) N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 

I. Reserve Margin(1)(2)(Excluding Cold Reserve Capability)

1. Summe r Re se rve Margin

a. MW(1) 1,096 2,473 3,026 2,616 2,855 3,263 2,850 2,049 2,073 2,095 2,343 2,325 2,530 2,298 2,233 

b. Pe rcent of Load 6.2% 14.6% 18.4% 14.8% 15.7% 17.4% 15.0% 11.2% 11.2% 11.2% 12.4% 12.1% 13.0% 11.7% 11.2% c. Actual Re se rve Margin(3) N/A N/A N/A 13.2% 15.6% 17.1% 11.8% 9.4% 15.3% 14.0% 12.4% 12.1% 13.0% 11.7% 10.4% 

2. Winte r Rese rve Margin

a. MW(1) N/A N/A N/A 5,497 6,263 5,561 6,501 5,304 7,658 7,263 7,073 7,134 7,416 7,235 7,062 

b. Pe rcent of Load N/A N/A N/A 37.1% 42.2% 37.0% 42.8% 34.4% 49.4% 46.5% 44.8% 44.7% 46.0% 44.3% 42.8% c. Actual Re se rve Margin(3) N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 

III. Annual Loss‐of‐Load Hours(4) N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 
AP ‐ 11

APPENDIX 2J – Economic Assumptions Used In the Sales and Hourly Budget Forecast M

(Annual Growth Rate)

Year 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 

Population: Total, (Ths.) 8,333 8,404 8,477 8,550 8,625 8,699 8,773 8,847 8,920 8,993 9,065 9,136 9,206 Disposable Personal Income, (Mil., 2005$, SAAR) 323,048 336,260 350,735 360,280 367,706 374,761 382,260 390,426 398,616 405,763 412,697 419,783 427,296 per Capita Real Disposable Personal Income, (Ths., 2005$, SAAR) 38.8 40.0 41.4 42.1 42.6 43.1 43.6 44.1 44.7 45.1 45.5 46.0 46.4 

Residential Permits: Total, (#, SAAR) 40,802 61,742 62,477 54,947 46,620 42,002 40,352 38,837 38,199 36,835 35,968 36,015 36,310 

Employment: Total Manufacturing, (Ths., SA) 230 231 234 234 233 231 229 227 224 222 220 217 215 

Employment: Total Government, (Ths., SA) 708.8 711.9 711.9 711.7 712.2 712.9 713.7 715.4 717.0 718.2 718.9 719.6 719.9 

Employment: Military personnel, (Ths., SA) 146 144 141 138 135 133 130 128 127 126 125 125 124 

Employment: State and local government, (Ths., SA) 541 548 549 550 550 551 552 553 555 556 557 558 558 Employment: Commercial Sector (Ths., SA) 2,665.6 2,732.7 2,801.4 2,846.4 2,872.1 2,892.3 2,914.0 2,937.3 2,958.0 2,977.0 2,994.9 3,011.9 3,029.4 

Gross Product: Manufacturing, (Mil. Chained 2005 $, SAAR) 39,309 41,404 43,125 44,296 45,475 46,857 48,238 49,528 50,770 52,034 53,303 54,627 56,033 

Gross State Product: Total, (Bil. Chained 2005 $, SAAR) 407.2 423.4 434.7 443.6 451.4 458.3 465.9 474.7 483.7 492.4 500.8 509.1 517.5 

Gross Product: State & Local Government, (Mil. Chained 2005 $, SAAR) 27,893 27,839 27,526 27,301 27,140 27,033 27,011 27,044 27,057 27,021 26,949 26,828 26,659 

Source: Economy com, March 2014 vintage

Year 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 

Population: Total, (Ths.) 8,275 8,357 8,438 8,520 8,602 8,685 8,768 8,851 8,934 9,018 9,101 9,185 9,269 Disposable Personal Income, (Mil., 2005$, SAAR) 286,891 296,511 309,255 321,453 331,231 339,153 346,758 355,022 363,705 372,378 380,994 389,577 398,194 

per Capita Real Disposable Personal Income, (Ths., 2005$, SAAR) 34.7 35.5 36.7 37.7 38.5 39.1 39.6 40.1 40.7 41.3 41.9 42.4 43.0 

Residential Permits: Total, (#, SAAR) 38,418 52,377 57,878 57,110 54,319 47,862 44,304 42,787 41,343 40,680 39,304 38,645 38,989 Employment: Total Manufacturing, (Ths., SA) 233 233 235 238 238 237 235 234 232 231 229 228 226 

Employment: Total Government, (Ths., SA) 716.6 723.1 734.2 741.1 745.2 748.0 750.2 752.1 753.5 754.3 754.8 754.8 754.9 

Employment: Military personnel, (Ths., SA) 139 138 137 136 136 135 134 133 132 131 130 130 129 Employment: State and local government, (Ths., SA) 543 551 563 570 574 577 579 581 582 583 584 584 585 Employment: Commercial Sector (Ths., SA) 2,630.2 2,679.7 2,752.9 2,826.9 2,879.5 2,913.5 2,943.3 2,975.2 3,007.2 3,038.5 3,067.8 3,095.7 3,123.3 

Gross Product: Manufacturing, (Mil. Chained 2005 $, SAAR) 37,118 38,428 40,033 41,421 42,553 43,406 44,245 45,155 46,103 47,030 47,948 48,853 49,766 

Gross State Product: Total, (Bil. Chained 2005 $, SAAR) 392.4 405.8 421.6 436.0 448.0 458.4 468.4 479.0 490.3 501.6 512.8 523.9 535.0 

Gross Product: State & Local Government, (Mil. Chained 2005 $, SAAR) 27,418 27,568 27,923 28,351 28,635 28,780 28,894 28,992 29,052 29,068 29,031 28,973 28,874 

Source: Economy.com, April 2013 vintage
AP ‐ 12

Appendix 3A – Existing Generation Units in Service

(1) Commercial Operation Date.

Company Name: Virginia Electric and Powe r Company Schedule 14a

UNIT PERFORMANCE DATA

Existing Supply‐Side Resources (MW)

Unit Name Location Unit Class Primary Fuel Type C.O.D.(1) MW

Summer

MW

Winter

Altavista                                                       Altavista, VA Base Renewable Feb‐1992 51 51

Ba th County Units 1‐6                               Warm Springs, VA Intermedia te Hydro‐Pumped Storage Dec‐1985 1,802 1,802

Be ar Garden                                                Buckingham County, Va Intermedia te Na tural Gas‐CC May‐2011 590 612

Belleme ade                                                 Richmond, VA Intermedia te Na tural Gas‐CC Mar‐1991 267 267

Bremo 3                                                        Bremo Bluff, VA Pe ak Na tural Gas Jun‐1950 71 71

Bremo 4                                                        Bremo Bluff, VA Pe ak Na tural Gas Aug‐1958 156 156

Chesape ake 1                                             Chesape ake, VA Base Coal Jun‐1953 111 111

Chesape ake 2                                             Chesape ake, VA Base Coal Dec‐1954 111 111

Chesape ake 3                                             Chesape ake, VA Base Coal Jun‐1959 149 149

Chesape ake 4                                             Chesape ake, VA Base Coal May‐1962 207 207

Chesape ake CT 1, 2, 4, 6                           Chesape ake, VA Pe ak Light Fuel Oil Dec‐1967 51 69

Cheste rfield 3                                              Cheste r, VA Base Coal Dec‐1952 98 99

Cheste rfield 4                                              Cheste r, VA Base Coal Jun‐1960 163 163

Cheste rfield 5                                              Cheste r, VA Base Coal Aug‐1964 336 340

Cheste rfield 6                                              Cheste r, VA Base Coal Dec‐1969 670 680

Cheste rfield 7                                              Cheste r, VA Intermedia te Na tural Gas‐CC Jun‐1990 197 221

Cheste rfield 8                                              Cheste r, VA Intermedia te Na tural Gas‐CC May‐1992 200 231

Clove r 1                                                        Clove r, VA Base Coal Oct‐1995 219 219

Clove r 2                                                        Clove r, VA Base Coal Mar‐1996 219 219

Cushaw Hydro                                            Big Island, VA Intermedia te Hydro‐Conventional Jan‐1930 2 3

Darbytown 1                                                Richmond, VA Pe ak Na tural Gas‐Turbine May‐1990 84 91

Darbytown 2                                                Richmond, VA Pe ak Na tural Gas‐Turbine May‐1990 84 91

Darbytown 3                                                Richmond, VA Pe ak Na tural Gas‐Turbine Apr‐1990 84 91

Darbytown 4                                                Richmond, VA Pe ak Na tural Gas‐Turbine Apr‐1990 84 91

Elizabe th Rive r 1                                         Chesape ake, VA Pe ak Na tural Gas‐Turbine Jun‐1992 116 116

Elizabe th Rive r 2                                         Chesape ake, VA Pe ak Na tural Gas‐Turbine Jun‐1992 116 116

Elizabe th Rive r 3                                         Chesape ake, VA Pe ak Na tural Gas‐Turbine Jun‐1992 116 116

Gaston Hydro                                             Roanoake Rapids, NC Intermedia te Hydro‐Conventional Feb‐1963 220 220

Gordonsville 1                                             Gordonsville, VA Intermedia te Na tural Gas‐CC Jun‐1994 109 127

Gordonsville 2                                             Gordonsville, VA Intermedia te Na tural Gas‐CC Jun‐1994 109 125

Gravel Neck 1‐2                                          Surry, VA Pe ak Light Fuel Oil Aug‐1970 28 38

Gravel Neck 3                                              Surry, VA Pe ak Na tural Gas‐Turbine Oct‐1989 85 91

Gravel Neck 4                                              Surry, VA Pe ak Na tural Gas‐Turbine Jul‐1989 85 91

Gravel Neck 5                                              Surry, VA Pe ak Na tural Gas‐Turbine Jul‐1989 85 91

Gravel Neck 6                                              Surry, VA Pe ak Na tural Gas‐Turbine Nov‐1989 85 91

Hopewell                                                      Hopewell, VA Base Renewable Jul‐1989 51 51

Ladysmith 1                                                 Woodford, VA Pe ak Na tural Gas‐Turbine May‐2001 151 172

Ladysmith 2                                                 Woodford, VA Pe ak Na tural Gas‐Turbine May‐2001 151 172

Ladysmith 3                                                 Woodford, VA Pe ak Na tural Gas‐Turbine Jun‐2008 161 182

Ladysmith 4                                                 Woodford, VA Pe ak Na tural Gas‐Turbine Jun‐2008 160 182

Ladysmith 5                                                 Woodford, VA Pe ak Na tural Gas‐Turbine Apr‐2009 160 183

Lowmoor CT 1‐4                                         Covington, VA Pe ak Light Fuel Oil Jul‐1971 48 64
AP ‐ 13

Appendix 3A Cont. – Existing Generation Units in Service

(1) Commercial Operation Date.

Company Name: Virginia Electric and Powe r Company Schedule 14a

UNIT PERFORMANCE DATA

Existing Supply‐Side Resources (MW)

Unit Name Location Unit Class Primary FuelType C.O.D.(1) MW

Summer

MW

Winter

Mecklenburg 1                                            Clarksville, VA Base Coal Nov‐1992 69 69

Mecklenburg 2                                            Clarksville, VA Base Coal Nov‐1992 69 69

Mount Storm 1                                            Mt. Storm, WV Base Coal Sep‐1965 554 554

Mount Storm 2                                            Mt. Storm, WV Base Coal Jul‐1966 555 555

Mount Storm 3                                            Mt. Storm, WV Base Coal Dec‐1973 520 520

Mount Storm CT                                         Mt. Storm, WV Pe ak Light Fuel Oil Oct‐1967 11 12

North Anna 1                                               Mine ral, VA Base Nucle ar Jun‐1978 838 868

North Anna 2                                               Mine ral, VA Base Nucle ar Dec‐1980 834 863

North Anna Hydro                                     Mine ral, VA Inte rmediate Hydro‐Conventional Dec‐1987 1 1

Northe rn Neck CT 1‐4                                Warsaw, VA Pe ak Light Fuel Oil Jul‐1971 47 63

Pittsylvania                                                  Hurt, VA Base Renewable Jun‐1994 83 83

Possum Point 3                                            Dumfrie s, VA Pe ak Natural Gas Jun‐1955 96 96

Possum Point 4                                            Dumfrie s, VA Pe ak Natural Gas Apr‐1962 220 220

Possum Point 5                                            Dumfrie s, VA Pe ak He avy Fuel Oil Jun‐1975 786 786

Possum Point 6                                            Dumfrie s, VA Inte rmediate Natural Gas‐CC Jul‐2003 559 612

Possum Point CT 1‐6                                  Dumfrie s, VA Pe ak Light Fuel Oil May‐1968 72 96

Remington 1                                                Remington, VA Pe ak Natural Gas‐Turbine Jul‐2000 153 174

Remington 2                                                Remington, VA Pe ak Natural Gas‐Turbine Jul‐2000 151 172

Remington 3                                                Remington, VA Pe ak Natural Gas‐Turbine Jul‐2000 152 172

Remington 4                                                Remington, VA Pe ak Natural Gas‐Turbine Jul‐2000 152 172

Roanoke Rapids Hydro                             Roanoake Rapids, NC Inte rmediate Hydro‐Conventional Sep‐1955 98 98

Rosemary                                                    Roanoke Rapids, NC Inte rmediate Natural Gas‐CC Dec‐1990 165 183

Solar Partne rship Program                      Distributed Inte rmittent Renewable Jan‐2012 0 0

Southampton                                               Franklin, VA Base Renewable Mar‐1992 51 51

Surry 1                                                          Surry, VA Base Nucle ar Dec‐1972 838 875

Surry 2                                                          Surry, VA Base Nucle ar May‐1973 838 875

Virginia City Hybrid Ene rgy Cente r      Virginia City, Va Base Coal Jul‐2012 610 620

Yorktown 1                                                   Yorktown, VA Base Coal Jul‐1957 159 160

Yorktown 2                                                   Yorktown, VA Base Coal Jan‐1959 164 164

Yorktown 3                                                   Yorktown, VA Pe ak He avy Fuel Oil Dec‐1974 790 801

8,567 8,725

4,319 4,502

4,791 5,129

0 0

Total 17,677 18,356

Subtotal ‐ Base

Subtotal ‐ Intermediate

Subtotal ‐ Peak

Subtotal ‐ Intermittent
AP ‐ 14

Appendix 3B – Other Generation Units

(1) Commercial Operation Date.

(2) These units are provided for informational purposes, they are not part of the 2014 Plan.

(3) Agreement to provide excess energy only.

(4) PPA is for Excess Energy only typically 4,000 ‐ 14,000 kW.

Company Name: Virginia Electric and Powe r Company Schedule 14b

UNIT PERFORMANCE DATA

Existing Supply‐Side Resources (kW)

Unit Name Location Unit Class Primary

Fuel Type

kW

Summer

Capacity

Resource

Contract

Start

Contract

Expiration

     Non‐Utility Generation (NUG) Units

Spruance Genco, Facility 1 (Richmond 1)                          Richmond, VA Base Coal 115,500 Yes 8/1/1992 7/31/2017

Spruance Genco, Facility 2 (Richmond 2)                          Richmond, VA Base Coal 85,000 Yes 8/1/1992 7/31/2017

Edgecombe Genco (Rocky Mount)                                   Battleboro, NC Base Coal 115,500 Yes 10/15/1990 10/14/2015

Doswell Complex                                                          Ashland, VA Intermediate Natural Gas 605,000 Yes 5/16/1992 5/5/2017

Hopewell Cogen                                                           Hopewell, VA Intermediate Natural Gas 336,600 Yes 8/1/1990 7/31/2015

Covanta Fairfax                                                     Lorton, VA Base MSW 63,000 Yes 5/5/1990 5/31/2015

Roanoke Valley II                                                        Weldon, NC Base Coal 44,000 Yes 6/1/1995 3/31/2019

Roanoke Valley Projec t                                                   Weldon, NC Base Coal 165,000 Yes 5/29/1994 3/31/2019

SEI Birchwood                                                            King George, VA Base Coal 217,800 Yes 11/15/1996 11/14/2021

      Behind‐The‐Meter Generation (BTMG) Units(2)

BTM Alexandria/Arling ton ‐ Covanta VA NUG MSW 21,000 No 1/29/1988 1/28/2023

BTM Richmond Elec tric VA Must Take Methane 2,900 No 8/27/1993 8/26/2013

BTM Brasfield Dam VA Must Take Hydro 2,485 No 10/12/1993 10/11/2013

BTM Suffolk Landfill VA Must Take Methane 3,000 No 11/4/1994 11/3/2014

BTM Columbia Mills VA Must Take Hydro 147 No 2/7/1985 2/6/2015

BTM S choolfield Dam VA Must Take Hydro 2,500 No 12/1/1990 11/30/2015

BTM Lakeview (Swift Creek) Dam VA Must Take Hydro 400 No 11/26/2008 Auto renew

BTM MeadWestvaco (formerly Westvaco ) VA NUG Coal/Biomass 125,000 No 11/3/1982 Auto renew

BTM Banister Dam VA Must Take Hydro 1,785 No 9/28/2008 Auto renew

BTM 119 Goose Castle Terrace NC Must Take S olar 3 No 3/18/2008 Auto renew

BTM 4113 Lindberg Ave (ultra small residential) NC Must Take S olar 2 No 2/19/2008 Auto renew

BTM Coquina Beach NC Must Take Wind 2 No 8/22/2006 Auto renew

BTM Jockeyʹs Ridge S tate Park NC Must Take Wind 10 No 5/21/2010 Auto renew

BTM 302 First Flight Run NC Must Take S olar 3 No 5/5/2010 Auto renew

BTM 409 W Villa Dunes NC Must Take S olar 4 No 2/24/2009 Auto renew

BTM 148 Turner Road NC Must Take S olar 2 No 7/1/2009 Auto renew

BTM 3620 Virginia Dare Trail N NC Must Take S olar 4 No 9/14/2009 Auto renew

BTM Domtar (Weyerhaeuser) NC NUG Coal/biomass 28400(4) No 7/27/1991 Auto renew

BTM Chapman Dam VA Must Take Hydro 300 No 10/17/1984 Auto renew

BTM I‐95 Landfill VA Must Take Methane 3,000 No 1/1/1992 12/31/2011

BTM I‐95 Phase 2 VA Must Take Methane 3,000 No 2/10/1993 2/9/2013

BTM Smurfit‐S tone Container VA NUG Coal/biomass 48400(4) No 3/21/1981 10/26/2012

BTM Rivanna VA Must Take Hydro 100 No 4/21/1998 Auto renew

BTM Rapidan Mill VA Must Take Hydro 100 No 6/15/2009 Auto renew

BTM River Farm Energy VA Must Take S olar 8 No 1/30/2009 Auto renew

BTM S outh Hill Renewable Energy VA Must Take Hydro 40 No 11/3/2010 Auto renew

BTM Dairy Energy VA Must Take Biomass 400 No 8/2/2011 8/1/2016

BTM W. E. Partners II VA Must Take Biomass 300 No 3/15/2012 3/14/2017

BTM Plymouth Solar NC Must Take S olar 2,400 No Pending N/A
AP ‐ 15

Appendix 3B Cont. – Other Generation Units

(5) These units are provided for informational purposes, they are not part of the 2014 Plan.

Company Name: Virginia Electric and Powe r Company Schedule 14b

UNIT PERFORMANCE DATA

Existing Supply‐Side Resources (kW)

Unit Name Location Unit Class Primary

FuelType

kW

Summer

Capacity

Resource

Contract

Start

Contract

Expiration

Customer Owned(5)

Ahoskie S tandby Diesel 2550 No N/A N/A

Tillery S tandby Diesel 585 No N/A N/A

Whitakers S tandby Diesel 10000 No N/A N/A

Columbia S tandby Diesel 400 No N/A N/A

Grandy S tandby Diesel 400 No N/A N/A

Kill Devil Hills S tandby Diesel 500 No N/A N/A

Moyock S tandby Diesel 350 No N/A N/A

Nags Head S tandby Diesel 400 No N/A N/A

Nags Head S tandby Diesel 450 No N/A N/A

Roanoke Rapids S tandby Diesel 400 No N/A N/A

Conway S tandby Diesel 500 No N/A N/A

Conway S tandby Diesel 500 No N/A N/A

Roanoke Rapids S tandby Diesel 500 No N/A N/A

Corolla S tandby Diesel 700 No N/A N/A

Kill Devil Hills S tandby Diesel 700 No N/A N/A

Rocky Mount S tandby Diesel 700 No N/A N/A

Roanoke Rapids S tandby Coal 25000 No N/A N/A

Manteo S tandby Diesel 300 No N/A N/A

Conway S tandby Diesel 800 No N/A N/A

Lewiston S tandby Diesel 4000 No N/A N/A

Roanoke Rapids S tandby Diesel 1200 No N/A N/A

Weldon S tandby Diesel 750 No N/A N/A

Tillery S tandby Diesel 450 No N/A N/A

Elizabeth City S tandby Unknown 2000 No N/A N/A

Greenville S tandby Diesel 1800 No N/A N/A

Northern VA S tandby Diesel 50 No N/A N/A

Northern VA S tandby Diesel 1270 No N/A N/A

Alexandria S tandby Diesel 300 No N/A N/A

Alexandria S tandby Diesel 475 No N/A N/A

Alexandria S tandby Diesel 2 ‐ 60 No N/A N/A

Northern VA S tandby Diesel 14000 No N/A N/A

Northern VA S tandby Diesel 10000 No N/A N/A

Norfolk S tandby Diesel 4000 No N/A N/A

Richmond S tandby Diesel 4470 No N/A N/A

Arling ton S tandby Diesel 5650 No N/A N/A

Richmond S tandby Diesel 22950 No N/A N/A

Northern VA S tandby Diesel 50 No N/A N/A

Hampton Roads S tandby Diesel 3000 No N/A N/A

Northern VA S tandby Diesel 900 No N/A N/A

Richmond S tandby Diesel 20110 No N/A N/A

Richmond S tandby Diesel 3500 No N/A N/A

Richmond S tandby Natural Gas 10 No N/A N/A

Richmond S tandby LP 120 No N/A N/A

VA Beach S tandby Diesel 2000 No N/A N/A

Chesapeake S tandby Diesel 500 No N/A N/A

Chesapeake S tandby Diesel 2500 No N/A N/A
AP ‐ 16

Appendix 3B Cont. – Other Generation Units

(5) These units are provided for informational purposes, they are not part of the 2014 Plan.

Company Name: Virginia Electric and Powe r Company Schedule 14b

UNIT PERFORMANCE DATA

Existing Supply‐Side Resources (kW)

Unit Name Location Unit Class Primary

Fuel Type

kW

Summer

Capacity

Resource

Contract

Start

Contract

Expiration

Customer Owned(5)

Fredericksburg S tandby Diesel 700 No N/A N/A

Hopewell S tandby Diesel 75 No N/A N/A

Newport News S tandby Unknown 1000 No N/A N/A

Newport News S tandby Unknown 4500 No N/A N/A

Norfolk S tandby Diesel 2000 No N/A N/A

Norfolk S tandby Diesel 9000 No N/A N/A

Portsmouth S tandby Diesel 2250 No N/A N/A

VA Beach S tandby Diesel 3500 No N/A N/A

VA Beach S tandby Diesel 2000 No N/A N/A

Chesterfield S tandby Diesel 2000 No N/A N/A

Central VA Merchant Coal 92000 No N/A N/A

Central VA Merchant Coal 115000 No N/A N/A

Williamsburg S tandby Diesel 2800 No N/A N/A

Richmond S tandby Diesel 30000 No N/A N/A

Charlo ttesville S tandby Diesel 40000 No N/A N/A

Arling ton S tandby Diesel 13042 No N/A N/A

Arling ton S tandby Diesel/ Natural Gas 5000 No N/A N/A

Fauquier S tandby Diesel 1885 No N/A N/A

Hanover S tandby Diesel 12709.5 No N/A N/A

Hanover S tandby Natural Gas 13759.5 No N/A N/A

Hanover S tandby LP 81.25 No N/A N/A

Henrico S tandby Natural Gas 1341 No N/A N/A

Henrico S tandby LP 126 No N/A N/A

Henrico S tandby Diesel 828 No N/A N/A

Northern VA S tandby Diesel 200 No N/A N/A

Northern VA S tandby Diesel 8000 No N/A N/A

Newport News S tandby Diesel 1750 No N/A N/A

Northern VA S tandby Diesel 37000 No N/A N/A

Chesapeake S tandby Unknown 750 No N/A N/A

Northern VA Merchant Natural Gas 50000 No N/A N/A

Northern VA S tandby Diesel 138000 No N/A N/A

Richmond S tandby S team 20000 No N/A N/A

Herndon S tandby Diesel 415 No N/A N/A

Herndon S tandby Diesel 50 No N/A N/A

VA Merchant Hydro 2700 No N/A N/A

Northern VA S tandby Diesel 37000 No N/A N/A

Fairfax County S tandby Diesel 20205 No N/A N/A

Fairfax County S tandby Natural Gas 2139 No N/A N/A

Fairfax County S tandby LP 292 No N/A N/A

Springfield S tandby Diesel 6500 No N/A N/A

Warrenton S tandby Diesel 2 ‐ 750 No N/A N/A

Northern VA S tandby Diesel 5350 No N/A N/A

Richmond S tandby Diesel 16400 No N/A N/A

Norfolk S tandby Diesel 350 No N/A N/A

Charlo ttesville S tandby Diesel 400 No N/A N/A
AP ‐ 17

Appendix 3B Cont. – Other Generation Units

(5) These units are provided for informational purposes, they are not part of the 2014 Plan.

Company Name: Virginia Electric and Powe r Company Schedule 14b

UNIT PERFORMANCE DATA

Existing Supply‐Side Resources (kW)

Unit Name Location Unit Class Primary

Fuel Type

kW

Summer

Capacity

Resource

Contract

Start

Contract

Expiration

Customer Owned(5)

Farmville S tandby Diesel 350 No N/A N/A

Mechanicsville S tandby Diesel 350 No N/A N/A

King George S tandby Diesel 350 No N/A N/A

Chatham S tandby Diesel 350 No N/A N/A

Hampton S tandby Diesel 350 No N/A N/A

Virginia Beach S tandby Diesel 350 No N/A N/A

Portsmouth S tandby Diesel 400 No N/A N/A

Powhatan S tandby Diesel 350 No N/A N/A

Richmond S tandby Diesel 350 No N/A N/A

Richmond S tandby Diesel 350 No N/A N/A

Chesapeake S tandby Diesel 400 No N/A N/A

Newport News S tandby Diesel 350 No N/A N/A

Dinwiddie S tandby Diesel 300 No N/A N/A

Goochland S tandby Diesel 350 No N/A N/A

Portsmouth S tandby Diesel 350 No N/A N/A

Fredericksburg S tandby Diesel 350 No N/A N/A

Northern VA S tandby Diesel 22690 No N/A N/A

Northern VA S tandby Diesel 5000 No N/A N/A

Hampton Roads S tandby Diesel 15100 No N/A N/A

Herndon S tandby Diesel 1250 No N/A N/A

Herndon S tandby Diesel 500 No N/A N/A

Henrico S tandby Diesel 1000 No N/A N/A

Alexandria S tandby Diesel 2 ‐ 910 No N/A N/A

Alexandria S tandby Diesel 1000 No N/A N/A

Fairfax S tandby Diesel 4 ‐ 750 No N/A N/A

Loudoun S tandby Diesel 2100 No N/A N/A

Loudoun S tandby Diesel 710 No N/A N/A

Mount Vernon S tandby Diesel 1500 No N/A N/A

Northern VA S tandby Diesel 50 No N/A N/A

Eastern VA S tandby Black Liquor/Natural Gas 112500 No N/A N/A

Central VA S tandby Diesel 1700 No N/A N/A

Hopewell S tandby Diesel 500 No N/A N/A

Falls Church S tandby Diesel 200 No N/A N/A

Falls Church S tandby Diesel 250 No N/A N/A

Northern VA S tandby Diesel 500 No N/A N/A

Fredericksburg S tandby Diesel 4200 No N/A N/A

Norfolk S tandby NG 1050 No N/A N/A

Richmond S tandby Diesel 6400 No N/A N/A

Henrico S tandby Diesel 500 No N/A N/A

Elkton S tandby Natural Gas 6000 No N/A N/A

Southside VA S tandby Diesel 30000 No N/A N/A

Northern VA S tandby Diesel 5000 No N/A N/A

Northern VA S tandby #2 FO 5000 No N/A N/A

Northern VA S tandby Diesel 50 No N/A N/A

Vienna S tandby Diesel 5000 No N/A N/A

Northern VA S tandby Diesel 200 No N/A N/A
AP ‐ 18

Appendix 3B Cont. – Other Generation Units

(5) These units are provided for informational purposes, they are not part of the 2014 Plan.

Company Name: Virginia Electric and Powe r Company Schedule 14b

UNIT PERFORMANCE DATA

Existing Supply‐Side Resources (kW)

Unit Name Location Unit Class Primary

Fuel Type

kW

Summer

Capacity

Resource

Contract

Start

Contract

Expiration

Customer Owned(5)

Northern VA S tandby Diesel 50 No N/A N/A

Northern VA S tandby Diesel 1270 No N/A N/A

Alexandria S tandby Diesel 300 No N/A N/A

Alexandria S tandby Diesel 475 No N/A N/A

Alexandria S tandby Diesel 2 ‐ 60 No N/A N/A

Northern VA S tandby Diesel 14000 No N/A N/A

Northern VA S tandby Diesel 10000 No N/A N/A

Norfolk S tandby Diesel 4000 No N/A N/A

Richmond S tandby Diesel 4470 No N/A N/A

Arling ton S tandby Diesel 5650 No N/A N/A

Ashburn S tandby Diesel 22000 No N/A N/A

Richmond S tandby Diesel 22950 No N/A N/A

Northern VA S tandby Diesel 50 No N/A N/A

Hampton Roads S tandby Diesel 3000 No N/A N/A

Northern VA S tandby Diesel 900 No N/A N/A

Richmond S tandby Diesel 20110 No N/A N/A

Richmond S tandby Diesel 3500 No N/A N/A

Richmond S tandby NG 10 No N/A N/A

Richmond S tandby LP 120 No N/A N/A

Va Beach S tandby Diesel 2000 No N/A N/A

Chesapeake S tandby Diesel 500 No N/A N/A

Chesapeake S tandby Diesel 2500 No N/A N/A

Fredericksburg S tandby Diesel 700 No N/A N/A

Hopewell S tandby Diesel 75 No N/A N/A

Newport News S tandby Unknown 1000 No N/A N/A

Newport News S tandby Unknown 4500 No N/A N/A

Norfolk S tandby Diesel 2000 No N/A N/A

Norfolk S tandby Diesel 9000 No N/A N/A

Portsmouth S tandby Diesel 2250 No N/A N/A

Va Beach S tandby Diesel 3500 No N/A N/A

Va Beach S tandby Diesel 2000 No N/A N/A

Chesterfield S tandby Diesel 2000 No N/A N/A

Central VA Merchant Coal 92000 No N/A N/A

Central VA Merchant Coal 115000 No N/A N/A

Williamsburg S tandby Diesel 2800 No N/A N/A

Richmond S tandby Diesel 30000 No N/A N/A

Charlo ttesville S tandby Diesel 40000 No N/A N/A

Arling ton S tandby Diesel 13042 No N/A N/A

Arling ton S tandby Diesel/NG 5000 No N/A N/A

Fauquier S tandby Diesel 1885 No N/A N/A

Hanover S tandby Diesel 12709.5 No N/A N/A

Hanover S tandby NG 13759.5 No N/A N/A

Hanover S tandby LP 81.25 No N/A N/A

Henrico S tandby NG 1341 No N/A N/A

Henrico S tandby LP 126 No N/A N/A

Henrico S tandby Diesel 828 No N/A N/A

Northern VA S tandby Diesel 200 No N/A N/A

Northern VA S tandby Diesel 8000 No N/A N/A

Newport News S tandby Diesel 1750 No N/A N/A

Northern VA S tandby Diesel 37000 No N/A N/A
AP ‐ 19

Appendix 3B Cont. – Other Generation Units

(5) These units are provided for informational purposes, they are not part of the 2014 Plan.

Company Name: Virginia Electric and Powe r Company Schedule 14b

UNIT PERFORMANCE DATA

Existing Supply‐Side Resources (kW)

Unit Name Location Unit Class Primary

FuelType

kW

Summer

Capacity

Resource

Contract

Start

Contract

Expiration

Customer Owned(5)

Chesapeake S tandby Unknown 750 No N/A N/A

Northern VA Merchant NG 50000 No N/A N/A

Northern VA S tandby Diesel 138000 No N/A N/A

Richmond S tandby S team 20000 No N/A N/A

Herndon S tandby Diesel 415 No N/A N/A

Herndon S tandby Diesel 50 No N/A N/A

VA Merchant Hydro 2700 No N/A N/A

Northern VA S tandby Diesel 37000 No N/A N/A

Fairfax County S tandby Diesel 20205 No N/A N/A

Fairfax County S tandby NG 2139 No N/A N/A

Fairfax County S tandby LP 292 No N/A N/A

Springfield S tandby Diesel 6500 No N/A N/A

Warrenton S tandby Diesel 2 ‐ 750 No N/A N/A

Northern VA S tandby Diesel 5350 No N/A N/A

Richmond S tandby Diesel 16400 No N/A N/A

Norfolk S tandby Diesel 350 No N/A N/A

Charlo ttesville S tandby Diesel 400 No N/A N/A

Farmville S tandby Diesel 350 No N/A N/A

Mechanicsville S tandby Diesel 350 No N/A N/A

King George S tandby Diesel 350 No N/A N/A

Chatham S tandby Diesel 350 No N/A N/A

Hampton S tandby Diesel 350 No N/A N/A

Virginia Beach S tandby Diesel 350 No N/A N/A

Portsmouth S tandby Diesel 400 No N/A N/A

Powhatan S tandby Diesel 350 No N/A N/A

Richmond S tandby Diesel 350 No N/A N/A

Richmond S tandby Diesel 350 No N/A N/A

Chesapeake S tandby Diesel 400 No N/A N/A

Newport News S tandby Diesel 350 No N/A N/A

Dinwiddie S tandby Diesel 300 No N/A N/A

Goochland S tandby Diesel 350 No N/A N/A

Portsmouth S tandby Diesel 350 No N/A N/A

Fredericksburg S tandby Diesel 350 No N/A N/A

Northern VA S tandby Diesel 22690 No N/A N/A

Northern VA S tandby Diesel 5000 No N/A N/A

Hampton Roads S tandby Diesel 15100 No N/A N/A

Herndon S tandby Diesel 1250 No N/A N/A

Herndon S tandby Diesel 500 No N/A N/A

Henrico S tandby Diesel 1000 No N/A N/A

Alexandria S tandby Diesel 2 ‐ 910 No N/A N/A

Alexandria S tandby Diesel 1000 No N/A N/A

Fairfax S tandby Diesel 4 ‐ 750 No N/A N/A

Loudoun S tandby Diesel 2100 No N/A N/A

Loudoun S tandby Diesel 710 No N/A N/A

Mount Vernon S tandby Diesel 1500 No N/A N/A

Northern VA S tandby Diesel 50 No N/A N/A

Eastern VA S tandby Black liquor/Natural Gas 112500 No N/A N/A
AP ‐ 20

Appendix 3B Cont. – Other Generation Units

(5) These units are provided for informational purposes, they are not part of the 2014 Plan.

Company Name: Virginia Electric and Powe r Company Schedule 14b

UNIT PERFORMANCE DATA

Existing Supply‐Side Resources (kW)

Unit Name Location Unit Class Primary

Fuel Type

kW

Summer

Capacity

Resource

Contract

Start

Contract

Expiration

Customer Owned(5)

Central VA S tandby Diesel 1700 No N/A N/A

Hopewell S tandby Diesel 500 No N/A N/A

Falls Church S tandby Diesel 200 No N/A N/A

Falls Church S tandby Diesel 250 No N/A N/A

Northern VA S tandby Diesel 500 No N/A N/A

Fredericksburg S tandby Diesel 4200 No N/A N/A

Norfolk S tandby NG 1050 No N/A N/A

Richmond S tandby Diesel 6400 No N/A N/A

Henrico S tandby Diesel 500 No N/A N/A

Elkton S tandby Nat gas 6000 No N/A N/A

S outhside VA S tandby Diesel 30000 No N/A N/A

Northern VA S tandby Diesel 5000 No N/A N/A

Northern VA S tandby #2 FO 5000 No N/A N/A

Northern VA S tandby Diesel 50 No N/A N/A

Vienna S tandby Diesel 5000 No N/A N/A

Northern VA S tandby Diesel 200 No N/A N/A

Norfolk S tandby Diesel 1000 No N/A N/A

Northern VA S tandby Diesel 1000 No N/A N/A

Norfolk S tandby Diesel 1500 No N/A N/A

Northern VA S tandby Diesel 3000 No N/A N/A

Newport News S tandby Diesel 750 No N/A N/A

Chesterfield S tandby Coal 500 No N/A N/A

Richmond S tandby Diesel 1500 No N/A N/A

Richmond S tandby Diesel 1000 No N/A N/A

Richmond S tandby Diesel 1000 No N/A N/A

Northern VA S tandby Diesel 3000 No N/A N/A

Richmond Metro S tandby NG 25000 No N/A N/A

Suffolk S tandby Diesel 2000 No N/A N/A

Northern VA S tandby Diesel 8000 No N/A N/A

Northern VA S tandby Diesel 21000 No N/A N/A

Richmond S tandby Diesel 500 No N/A N/A

Hampton Roads S tandby Diesel 4000 No N/A N/A

Northern VA S tandby Diesel 10000 No N/A N/A

Northern VA S tandby Diesel 5000 No N/A N/A

Hampton Roads S tandby Diesel 12000 No N/A N/A

West Point S tandby Unknown 50000 No N/A N/A

Northern VA S tandby Diesel 100 No N/A N/A

Herndon S tandby Diesel 18100 No N/A N/A

VA Merchant RDF 60000 No N/A N/A

S tafford S tandby Diesel 3000 No N/A N/A

Chesterfield S tandby Diesel 750 No N/A N/A

Henrico S tandby Diesel 750 No N/A N/A

Richmond S tandby Diesel 5150 No N/A N/A

Culpepper S tandby Diesel 7000 No N/A N/A

Richmond S tandby Diesel 8000 No N/A N/A

Northern VA S tandby Diesel 2000 No N/A N/A

Northern VA S tandby Diesel 6000 No N/A N/A

Northern VA S tandby Diesel 500 No N/A N/A

Northern VA S tandby NG 50000 No N/A N/A
AP ‐ 21

Appendix 3B Cont. – Other Generation Units

(5) These units are provided for informational purposes, they are not part of the 2014 Plan.

Company Name: Virginia Ele ctric and Powe r Company Schedule 14b

UNIT PERFORMANCE DATA

Existing Supply‐Side Resources (kW)

Unit Name Location Unit Class Primary

Fuel Type

kW

Summer

Capacity

Resource

Contract

Start

Contract

Expiration

Customer Owned(5)

Hampton Roads S tandby Unknown 4000 No N/A N/A

Northern VA S tandby Diesel 10000 No N/A N/A

Northern VA S tandby Diesel 13000 No N/A N/A

S outhside VA S tandby Water 227000 No N/A N/A

Northern VA S tandby Diesel 300 No N/A N/A

Northern VA S tandby Diesel 1000 No N/A N/A

Richmond S tandby Diesel 1500 No N/A N/A

Richmond S tandby Diesel 30 No N/A N/A

Newport News S tandby Diesel 1000 No N/A N/A

Hampton S tandby Diesel 12000 No N/A N/A

Newport News S tandby Natural gas 3000 No N/A N/A

Newport News S tandby Diesel 2000 No N/A N/A

Petersburg S tandby Diesel 1750 No N/A N/A

V arious S tandby Diesel 3000 No N/A N/A

V arious S tandby Diesel 30000 No N/A N/A

Northern VA S tandby Diesel 5000 No N/A N/A

Northern VA S tandby Diesel 2000 No N/A N/A

Ashburn S tandby Diesel 16000 No N/A N/A

Northern VA S tandby Diesel 6450 No N/A N/A

Virginia Beach S tandby Diesel 2000 No N/A N/A

Ashburn S tandby Diesel 12 ‐ 2000 No N/A N/A

Innsbrook‐Richmond S tandby Diesel 6050 No N/A N/A

Northern VA S tandby Diesel 150 No N/A N/A

Henrico S tandby Diesel 500 No N/A N/A

Virginia Beach S tandby Diesel 1500 No N/A N/A

Ahoskie S tandby Diesel 2550 No N/A N/A

Tillery S tandby Diesel 585 No N/A N/A

Whitakers S tandby Diesel 10000 No N/A N/A

Columbia S tandby Diesel 400 No N/A N/A

Grandy S tandby Diesel 400 No N/A N/A

Kill Devil Hills S tandby Diesel 500 No N/A N/A

Moyock S tandby Diesel 350 No N/A N/A

Nags Head S tandby Diesel 400 No N/A N/A

Nags Head S tandby Diesel 450 No N/A N/A

Roanoke Rapids S tandby Diesel 400 No N/A N/A

Conway S tandby Diesel 500 No N/A N/A

Conway S tandby Diesel 500 No N/A N/A

Roanoke Rapids S tandby Diesel 500 No N/A N/A

Corolla S tandby Diesel 700 No N/A N/A

Kill Devil Hills S tandby Diesel 700 No N/A N/A

Rocky Mount S tandby Diesel 700 No N/A N/A

Roanoke Rapids S tandby Coal 30000 No N/A N/A

Manteo S tandby Diesel 300 No N/A N/A

Conway S tandby Diesel 800 No N/A N/A

Lewiston S tandby Diesel 4000 No N/A N/A

Roanoke Rapids S tandby Diesel 1200 No N/A N/A

Weldon S tandby Diesel 750 No N/A N/A

Tillery S tandby Diesel 450 No N/A N/A

Elizabeth City S tandby Unknown 2000 No N/A N/A

Greenville S tandby Diesel 1800 No N/A N/A
AP ‐ 22

Appendix 3C – Equivalent Availability Factor (%)

Company Name: Virginia Electric and Powe r Company Schedule 8

UNIT PERFORMANCE DATA

Equivalent Availability Factor (%)

(ACTUAL) (PROJECTED)

Unit Name 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029

Altavista                                                                            ‐ ‐                         55               80              93           92           93           92           93           92           93           92           93           92           93           92           93           92           93

Bath County Units 1‐6                                                 84           86           84 N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A

Bear Garden                                                                  88           87           91               81              90           90           84           90           90           81           90           90           81           90           90           81           90           90           87

Bellemeade                                                                    82           84           85               86              89           84           87           86           90           90           89           90           84           90           90           90           90           90           90

Bremo 3                                                                        98           85           62               60              93           90           90           90           90           90           90           90           90           90           90           90           90           90           90

Bremo 4                                                                        84           83           56               59              92           88           88           88           88           88           88           88           88           88           88           88           88           88           88

Brunswick                                                                         ‐ ‐               ‐               ‐                   ‐                            90           90           90           85           90           90           84           90           90           84           90           90           90           90

Chesapeake 1                                                                85           90           96                ‐ 94                  ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐              

Chesapeake 2                                                                86           91           93                ‐ 94                  ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐              

Chesapeake 3                                                                83           85           86                ‐ 91                  ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐              

Chesapeake 4                                                                88           91           86                ‐ 92                  ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐              

Chesapeake CT 1, 2, 4, 6                                              80           75           96               88              88           88           88           88            ‐ 88               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐              

Chesterfield 3                                                               68           41           83               81              91           85           85           91           87           87           87           87           87           87           87           87           87           87           87

Chesterfield 4                                                               66           90           68               84              84           84           84           74           85           85           85           85           85           85           85           85           85           85           85

Chesterfield 5                                                               53           85           71               83              88           83           88           90           83           94           83           94           83           94           83           94           83           94           83

Chesterfield 6                                                               94           74           87               77              87           89           79           91           87           87           87           87           87           87           87           87           87           87           87

Chesterfield 7                                                               92           87           91               83              96           91           96           89           96           89           85           88           89           96           91           89           91           89           96

Chesterfield 8                                                               91           73           94               86              89           96           88           96           85           96           91           96           83           89           96           85           89           89           89

Clover 1                                                                        96           76           98               96              78           94           94           86           96           96           86           96           96           86           96           96           86           96           96

Clover 2                                                                        89           94           94               83              94           94           83           94           96           96           94           96           86           96           96           96           96           96           86

Covanta Fairfax                                                            92           92           86               72               ‐ 95               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐              

Cushaw Hydro                                                             31           39           62               83              83           83           83           83           83           83           83           83           83           83           83           83           83           83           83

Darbytown 1                                                                98           94           96               94              94           94           94           83           92           92           92           92           92           92           92           92           92           92           92

Darbytown 2                                                                92           97           98               94              94           94           94           87           90           92           92           92           92           92           92           92           92           92           92

Darbytown 3                                                                99           97           99               94              94           94           90           87           92           92           92           92           92           92           92           92           92           92           92

Darbytown 4                                                                99           96           97               94              94           94           94           83           92           92           92           92           92           92           92           92           92           92           92

Doswell Complex                                                         84           86           87               74              84           84            ‐ 95               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐              

Edgecombe Genco (Rocky Mountain)                        96           96           94               89               ‐ 96               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐              

Elizabeth River 1                                                          98           96           93               93              90           90           90           90           90           90           90           90           90           90           90           90           90           90           90

Elizabeth River 2                                                          97           98           93               93              67           90           90           90           90           90           90           90           90           90           90           90           90           90           90

Elizabeth River 3                                                          98           98           94               93              67           90           90           90           90           90           90           90           90           90           90           90           90           90           90

Existing Solar NC NUGs with PPAs                               ‐ ‐               ‐                             21              21           21           21           21           21           21           21           21           21           21           21           21           21            ‐ 21              

Future Solar NC Nugs               ‐ ‐               ‐               ‐                                21           22           21           21           21           22           21           21           21           22           21           21           21           22           21

Gaston Hydro                                                               78           86           86               15              15           15           15           15           15           15           15           15           15           15           15           15           15           15           15

Generic CC 2019               ‐ ‐               ‐               ‐                   ‐                  ‐               ‐               ‐                         88           88           88           88           88           88           88           88           88           88           88

Generic CC 2029               ‐ ‐               ‐               ‐                   ‐                  ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐                         88

Generic CT 2022               ‐ ‐               ‐               ‐                   ‐                  ‐               ‐               ‐               ‐               ‐               ‐                         88           88           88           88           88           88           88           88

Generic CT 2023               ‐ ‐               ‐               ‐                   ‐                  ‐               ‐               ‐               ‐               ‐               ‐               ‐                         88           88           88           88           88           88           88

Gordonsville 1                                                              93           92           94               84              84           88           85           96           91           96           89           91           96           85           96           90           91           91           96

Gordonsville 2                                                              93           87           94               90              96           91           88           85           91           96           91           85           94           91           84           94           91           96           94

Gravel Neck 1‐2                                                            94           93           96               88              88           88           88           88            ‐ 88               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐              

Gravel Neck 3                                                               93           97           72               94              94           94           94           94           94           94           94           89           94           94           94           94           94           94           94

Gravel Neck 4                                                               73           97           98               92              94           94           94           94           94           89           94           94           94           94           94           94           94           94           94

Gravel Neck 5                                                               97           92           98               92              94           94           94           94           94           89           94           94           94           94           94           94           94           94           94

Gravel Neck 6                                                               92           72           98               94              94           94           94           94           94           94           94           89           94           94           94           94           94           94           94

Hopewell                                                                       95           87           39               90              88           92           93           93           92           92           92           92           92           92           92           92           92           92           92

Hopewell Cogen                                                           85           88           83               86               ‐ 94               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐              

Ladysmith 1                                                                  88           95           81               90              90           90           90           90           90           90           90           90           81           90           90           90           92           90           89

Ladysmith 2                                                                  95           94           80               90              90           90           90           90           90           90           90           81           90           90           90           90           90           90           89

Ladysmith 3                                                                  91           94           94               89              90           90           90           90           90           90           90           90           90           90           90           90           90           90           89

Ladysmith 4                                                                  92           95           94               89              90           90           90           87           90           90           90           90           90           90           90           90           90           90           89

Ladysmith 5                                                                  92           96           95               90              90           90           90           90           87           90           90           90           90           90           90           90           90           90           89

Lowmoor CT 1‐4                                                        100           98         100               88              88            ‐ 88               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐              
AP ‐ 23

Appendix 3C Cont. – Equivalent Availability Factor (%)

Company Name: Virginia Electric and Powe r Company Schedule 8

UNIT PERFORMANCE DATA

Equivalent Availability Factor (%)

(ACTUAL) (PROJECTED)

Unit Name 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029

Mecklenburg 1                                                             98           94           97               95              90           95           92           95           91           92           95           92           95           91           95           91           95           91           95

Mecklenburg 2                                                             96           94           98               90              95           95           92           95           91           95           91           95           92           95           91           95           91           95           91

Mount Storm 1                                                            92           87           74               90              84           83           89           90           83           89           89           81           89           89           81           89           89           81           89

Mount Storm 2                                                            76           80           83               73              84           81           83           91           89           89           81           89           89           81           89           89           81           89           89

Mount Storm 3                                                            93           59           79               91              84           66           91           91           91           81           91           91           81           91           91           81           91           91           81

Mount Storm CT                                                         87           98           92               88              88            ‐ 88               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐              

North Anna 1                                                               77           85           90               98              92           89           98           90           91           98           91           91           98           91           91           98           91           91           98

North Anna 2                                                               74           96           86               89              98           91           90           98           91           91           98           91           91           98           91           91           98           91           91

North Anna Hydro                                                           ‐ ‐               ‐                             30              30           29           30           30           30           29           30           30           30           29           30           30           30           29           30

Northern Neck CT 1‐4                                                 99           99           98               88              88           88            ‐ 88               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐              

Pittsylvania                                                                   81           76           78               91              95           93           93           93           92           93           93           93           93           93           93           93           93           93           93

Possum Point 3                                                             70           67           89               83              91           87           87           91           91           82           91           91           91           87           91           91           91           82           91

Possum Point 4                                                             87           63           92               80              91           85           87           91           91           87           91           91           91           85           91           91           91           87           91

Possum Point 5                                                             75           77           70               39              77           69           77           77           85           78           85           69           85           78           85           78           85           69           85

Possum Point 6                                                             78           90           89               88              81           88           88           81           89           89           82           89           89           82           89           89           89           89           89

Possum Point CT 1‐6                                                   99           98         100               88               ‐ 88               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐              

Remington 1                                                                 92           86           90               86              90           90           90           90           90           90           90           90           90           90           90           90           90           90           89

Remington 2                                                                 97           88           87               90              87           90           90           90           90           90           90           90           90           90           90           90           90           90           89

Remington 3                                                                 97           87           90               90              90           90           87           90           90           90           90           90           90           90           90           90           90           90           89

Remington 4                                                                 94           86           91               86              90           90           90           90           90           90           90           90           90           90           90           90           90           90           89

Roanoke Rapids Hydro                                                94           93           94               34              34           34           34           34           34           34           34           34           34           34           34           34           34           34           34

Roanoke Valley II                                                         85           89           87               89              86           89           89           87           89            ‐ 97               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐              

Roanoke Valley Project                                                89           80           85               88              87           87           87           87            ‐ 95               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐              

Rosemary                                                                      89           86           85               85              89           96           89           96           96           96           96           96           91           96           96           91           96           96           91

SEI Birchwood                                                              78           91           87               87              87           82           87           87           87           87            ‐ 82               ‐               ‐               ‐               ‐               ‐               ‐               ‐              

Solar Partnership Program                                              ‐ ‐               ‐                             18              13           14           14           14           14           14           14           14           14           14           14           14           14           14           14

Southampton                                                               90           85           46               86              93           93           93           93           93           93           93           93           93           88           93           93           93           93           93

Spruance Genco, Facility 1 (Richmond 1)                  94           95           95               88              90           90            ‐ 96               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐              

Spruance Genco, Facility 2 (Richmond 2)                  91           94           91               93              89           89            ‐ 95               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐              

Surry 1                                                                          98           90           91               98              90           92           98           91           91           98           91           91           98           91           91           98           91           91           98

Surry 2                                                                          76           90         100               89              90           98           92           91           98           91           91           98           91           91           98           91           91           98           90

Virginia City Hybrid Energy Center                              ‐           57           78               84              84           84           84           84           81           92           88           84           92           88           84           92           88           84           92

Warren                                                                              ‐ ‐               ‐                             97              87           88           88           84           90           97           88           90           90           85           90           90           85           90           90

Yorktown 1                                                                   73           71           78               84              89            ‐ 89               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐              

Yorktown 2                                                                   73           76           81               87              93            ‐ 93               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐               ‐              

Yorktown 3                                                                   54           57           58               39              73           61           73           77           85           78           85           78           85           78           85           78           85           78           85
AP ‐ 24

Appendix 3D – Net Capacity Factor

Company Name: Virginia Electric and Powe r Company Schedule 9

UNIT PERFORMANCE DATA

Net Capacity Factor (%)

(ACTUAL) (PROJECTED)

Unit Name 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029

Altavista                                                              ‐ ‐                    45.1             80.4        93.3      91.4        93.3        91.4        93.3        91.4        93.3        91.4        93.3        91.4        93.3        91.4        93.3        91.4        93.3

Bath County Units 1‐6                                  16.2        15.8        14.7 N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A

Bear Garden                                                   64.4        78.2        72.2             57.2        72.0      67.5        58.5        62.0        54.8        49.3        52.5        50.2        44.2        48.0        47.9        42.6        46.1        45.2        36.9

Bellemeade                                                    22.2        52.0        12.7             23.0        18.8      16.3        15.6        16.4        15.0        14.8        15.5        15.5        13.6        15.0        14.7        14.2        15.0        13.6        12.1

Bremo 3                                                         18.2          9.9          9.7               4.1          6.6        5.3          4.3          5.1          4.9          5.3          5.3          4.4          3.7          3.8          3.7          3.8          4.0          3.9          3.8

Bremo 4                                                         51.6        21.2        30.9             18.5        16.2      11.7          9.7        11.9        10.1        10.4        10.3        10.8        10.7        10.8        10.7        10.6        11.1        10.3          9.2

Brunswick                                                          ‐ ‐             ‐             ‐                  ‐                  49.4        79.3        78.4        70.5        74.2        73.6        67.9        68.2        68.5        64.9        68.0        67.5        67.5        60.4

Chesapeake 1                                                36.0        14.3        18.1              ‐ 14.8             ‐           ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐            

Chesapeake 2                                                39.5        20.4        18.2              ‐ 16.3             ‐           ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐            

Chesapeake 3                                                60.0        56.5        60.0              ‐ 67.1             ‐           ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐            

Chesapeake 4                                                68.1        17.6        23.4              ‐ 22.4             ‐           ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐            

Chesapeake CT 1, 2, 4, 6                                0.2          0.1          0.1               0.9          0.8        0.7          0.5           ‐ 0.4             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐            

Chesterfield 3                                                16.5          8.6          7.1             37.5        22.2      20.5        26.0        33.3        27.7        25.5        28.2        23.9        22.0        22.2        23.0        21.5        23.4        21.0        18.8

Chesterfield 4                                                44.3        19.0        36.6             49.9        26.1      32.1        32.6        36.5        35.7        37.1        38.1        32.7        29.0        29.4        31.6        29.4        30.5        27.5        25.9

Chesterfield 5                                                39.2        51.6        57.8             59.6        43.2      44.8        51.4        59.5        51.1        57.3        52.8        50.3        41.3        45.6        45.6        46.2        44.8        45.7        38.9

Chesterfield 6                                                60.0        30.7        63.3             59.2        50.6      55.9        53.6        67.6        59.2        60.0        60.8        56.0        49.9        51.0        54.4        50.8        54.2        50.4        46.8

Chesterfield 7                                                74.7        85.8        86.5             61.9        65.6      56.4        50.6        42.9        40.7        35.0        33.5        32.6        30.9        34.8        31.9        30.4        31.6        30.5        27.4

Chesterfield 8                                                64.9        73.8        92.8             63.7        68.0      69.1        57.1        60.5        43.9        48.6        44.9        44.2        37.8        38.1        41.4        38.4        36.8        36.6        30.6

Clover 1                                                         71.4        52.4        80.3             84.1        55.6      78.9        84.5        79.0        85.6        84.9        74.1        80.5        75.4        67.8        75.1        72.7        69.3        70.7        69.1

Clover 2                                                         64.9        62.8        75.1             73.7        70.7      80.9        75.6        86.9        88.7        86.9        82.5        84.0        69.8        78.4        76.7        75.7        78.4        73.2        67.6

Covanta Fairfax                                           114.5      104.9      100.1              ‐ 63.6             ‐           ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐            

Cushaw Hydro                                              27.7        48.6        78.9             83.1        83.1      82.9        83.1        83.1        83.1        82.9        83.1        83.1        83.1        82.9        83.1        83.1        83.1        82.9        83.1

Darbytown 1                                                   3.4          4.3          5.7               3.8          3.5        3.1          3.2          3.3          3.4          3.6          3.5          3.1          2.7          2.6          2.6          2.6          2.6          2.5          2.5

Darbytown 2                                                   2.9          3.2          4.8               4.3          3.9        3.5          3.6          3.5          3.9          4.0          3.9          3.4          2.9          2.9          2.8          2.9          2.9          2.8          2.8

Darbytown 3                                                   2.8          3.4          5.7               4.0          3.7        3.3          3.4          3.3          3.6          3.8          3.7          3.3          2.8          2.8          2.7          2.8          2.8          2.7          2.6

Darbytown 4                                                   3.3          4.4          6.4               3.6          3.3        3.0          3.0          2.8          3.2          3.4          3.4          3.0          2.5          2.5          2.5          2.5          2.5          2.4          2.4

Doswell Complex                                          48.8        56.8        54.2             50.8        43.3       ‐ 34.0             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐            

Edgecombe Genco (Rocky Mountain)        42.1        12.0          9.1             75.8         ‐ 58.5           ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐            

Elizabeth River 1                                             5.3          4.5          1.7               3.0          2.8        2.5          2.5          2.6          2.8          2.9          2.9          2.6          2.2          2.2          2.2          2.2          2.2          2.1          2.1

Elizabeth River 2                                             4.4          3.3          1.9               2.8          2.2        2.2          2.3          2.3          2.5          2.7          2.7          2.4          2.1          2.0          2.0          2.1          2.0          2.0          2.0

Elizabeth River 3                                             4.5          4.9          1.1               3.2          2.8        2.7          2.7          2.8          3.0          3.1          3.1          2.7          2.4          2.3          2.3          2.3          2.3          2.3          2.3

Existing Solar NC NUGs with PPAs                 ‐ ‐             ‐                         21.5        21.5      21.5        21.5        21.5        21.5        21.5        21.5        21.5        21.5        21.5        21.5        21.5        21.5         ‐ 21.5            

Future Solar NC Nugs             ‐ ‐             ‐             ‐                         21.5      21.5        21.5        21.5        21.5        21.5        21.5        21.5        21.5        21.5        21.5        21.5        21.5        21.5        21.5

Gaston Hydro                                                10.4          8.9        15.6             15.2        15.2      15.1        15.2        15.2        15.2        15.1        15.2        15.2        15.2        15.1        15.2        15.2        15.2        15.1        15.2

Generic CC 2019             ‐ ‐             ‐             ‐                  ‐             ‐           ‐             ‐                    74.4        74.4        73.9        72.4        70.4        70.6        70.2        70.1        69.2        69.6        69.0

Generic CC 2029             ‐ ‐             ‐             ‐                  ‐             ‐           ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐                    63.6

Generic CT 2022             ‐ ‐             ‐             ‐                  ‐             ‐           ‐             ‐             ‐             ‐             ‐                      5.5          4.5          4.6          4.6          4.6          4.9          4.8          4.4

Generic CT 2023             ‐ ‐             ‐             ‐                  ‐             ‐           ‐             ‐             ‐             ‐             ‐             ‐                      6.0          6.2          6.2          6.2          6.6          6.3          5.7

Gordonsville 1                                               48.6        69.5        48.1             43.5        38.5      44.0        27.7        29.3        23.0        23.6        21.6        22.9        22.4        21.3        23.0        21.4        22.8        21.2        18.9

Gordonsville 2                                               31.1        65.2        48.1             46.1        42.5      42.1        26.0        24.5        19.5        21.4        21.3        19.2        20.0        20.8        18.6        20.1        20.4        20.1        16.7

Gravel Neck 1‐2                                              0.1          0.1          0.0               1.0          0.8        0.7          0.5           ‐ 0.5             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐            

Gravel Neck 3                                                  1.7          0.9          1.3               2.5          2.5        2.2          2.1          2.2          2.4          2.5          2.5          2.1          1.9          1.9          1.9          1.9          1.9          1.9          1.9

Gravel Neck 4                                                  2.0          4.1          4.6               2.7          2.8        2.4          2.3          2.4          2.5          2.7          2.6          2.3          2.0          2.0          2.0          2.0          2.0          2.0          2.0

Gravel Neck 5                                                  3.7          3.9          4.0               1.3          1.0        0.9          0.6          0.6          0.7          0.7          0.7          0.7          0.7          0.7          0.7          0.7          0.7          0.8          0.8

Gravel Neck 6                                                  1.5          0.4          1.6               1.2          0.9        0.8          0.5          0.5          0.7          0.7          0.7          0.7          0.6          0.7          0.7          0.7          0.7          0.7          0.8

Hopewell                                                       12.1          4.5        21.8             89.5        87.7      91.4        93.3        93.3        91.7        91.7        91.7        91.6        91.4        91.0        90.7        91.7        90.5        91.4        91.6

Hopewell Cogen                                            31.9        40.0        26.0             41.8         ‐ 20.5           ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐            

Ladysmith 1                                                    5.9          8.4        10.2             12.5        10.4        9.6          9.9        10.5          9.9          9.7          9.8        10.3          8.4        10.1          9.5          9.7        10.1          8.9          8.1

Ladysmith 2                                                    5.0          7.9          9.2             14.8        11.7      10.8        11.2        12.0        11.1        11.1        11.3        10.9        10.8        10.9        10.5        10.4        10.8          9.8          9.0

Ladysmith 3                                                    5.8          8.8        10.8             15.6        12.4      11.1        12.1        13.1        11.8        11.8        12.1        12.4        11.7        11.8        11.6        11.2        11.7        10.7          9.7

Ladysmith 4                                                    6.0          8.3        14.2             13.7        11.0        9.8        10.5        11.2        10.3        10.4        10.6        11.0        10.5        10.6        10.4        10.1        10.5          9.6          8.8

Ladysmith 5                                                    6.7          9.1        12.9             12.9        10.5        9.1          9.7        10.3          9.6        10.1          9.8        10.2          9.8        10.0          9.7          9.5          9.9          9.0          8.3

Lowmoor CT 1‐4                                             0.0          0.1          0.1               1.0           ‐ 0.8           ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐             ‐            
AP ‐ 25

Appendix 3D Cont. – Net Capacity Factor

Company Name: Virginia Electric and Powe r Company Schedule 9

UNIT PERFORMANCE DATA

Net Capacity Factor (%)

(ACTUAL) (PROJECTED)

Unit Name 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029

Mecklenburg 1                                              19.4        16.2        30.3             50.1        25.9      30.6        26.7        34.5        28.1        24.4        28.9        23.5        22.3        22.1        24.4        22.0        24.9        22.2        20.0

Mecklenburg 2                                              16.5        12.0        31.0             46.0        24.8      24.1        24.6        31.5        25.1        24.8        25.7        23.7        20.5        21.9        22.7        21.5        22.9        21.5        18.4

Mount Storm 1                                             70.9        75.4        63.4             79.0        57.3      66.9        80.7        82.8        77.3        80.6        78.7        69.5        71.9        70.7        66.2        70.6        72.7        63.4        68.9

Mount Storm 2                                             54.8        69.5        66.7             67.8        67.8      73.8        78.9        85.9        84.7        83.4        75.2        81.4        77.8        72.4        76.6        77.2        73.1        74.9        76.2

Mount Storm 3                                             64.4        37.3        64.6             77.5        56.8      53.1        77.5        79.7        78.7        69.2        74.2        74.8        60.2        67.8        69.2        62.4        70.1        64.5        60.3

Mount Storm CT                                            0.1          0.1          0.2               0.9           ‐          ‐            ‐ 0.7             ‐            ‐            ‐             ‐            ‐            ‐            ‐             ‐            ‐            ‐             ‐           

North Anna 1                                                77.2        87.9        92.6             99.8        93.4      90.5        99.8        91.5        92.2        99.8        92.0        92.2        99.8        92.0        92.2        99.8        92.0        92.2        99.8

North Anna 2                                                75.8        98.4        88.6             90.4        99.7      92.2        91.0        99.7        91.9        92.1        99.7        92.0        92.1        99.7        91.9        92.1        99.7        91.9        92.1

North Anna Hydro                                            ‐            ‐            ‐             29.5        29.5      29.4        29.5        29.5        29.5        29.4        29.5        29.5        29.5        29.4        29.5        29.5        29.5        29.4        29.5

Northern Neck CT 1‐4                                    0.1          0.1          0.1               1.1          0.8        0.7 ‐            ‐             ‐            ‐            ‐             ‐            ‐            ‐            ‐             ‐            ‐            ‐             ‐           

Pittsylvania                                                    54.0        46.8        50.8             38.3        14.0      11.7        36.0        47.2        64.1        63.7        56.9        67.6        76.3        82.8        83.9        81.9        80.1        77.5        77.7

Possum Point 3                                               3.1          6.4          3.9             11.9        10.5        7.0          5.4          6.9          6.1          6.3          6.5          7.3          7.4          7.3          7.5          7.5          7.9          7.2          6.7

Possum Point 4                                               5.6          6.6          5.9             14.4        12.3        8.1          6.7          8.6          7.4          7.8          8.5          9.1          9.5          9.2          9.7          9.6        10.2          9.5          8.5

Possum Point 5                                               1.0          1.0          0.5               1.5          1.3        1.1          0.9             ‐            ‐            ‐ ‐             ‐            ‐            ‐            ‐             ‐            ‐            ‐             ‐           

Possum Point 6                                             57.5        79.5        74.0             55.7        57.0      57.5        50.1        44.4        40.7        40.2        34.5        37.1        34.4        33.0        35.3        33.6        34.1        34.2        28.1

Possum Point CT 1‐6                                      0.0          0.1          0.1               1.0             ‐          ‐            ‐ ‐             ‐            ‐            ‐             ‐            ‐            ‐            ‐             ‐            ‐            ‐             ‐           

Remington 1                                                    5.5          6.1        12.3               9.7          7.1        6.1          6.4          6.8          6.6          6.7          6.7          7.2          7.3          7.4          7.2          7.1          7.3          6.8          6.3

Remington 2                                                    4.6          6.4        11.0               8.8          6.2        5.4          5.7          6.1          6.0          6.0          6.0          6.7          6.7          6.8          6.6          6.5          6.8          6.2          5.8

Remington 3                                                    5.0          5.4        10.2             10.3          7.7        6.4          6.8          7.4          7.1          7.2          7.1          7.8          7.6          7.7          7.6          7.4          7.7          7.0          6.5

Remington 4                                                    5.9          4.6        11.0             10.5          8.1        6.8          7.3          7.7          7.4          7.5          7.6          8.0          7.9          7.9          7.7          7.6          7.8          7.2          6.7

Roanoke Rapids Hydro                                 22.6        19.4        36.3             34.0        34.0      33.9        34.0        34.0        34.0        33.9        34.0        34.0        34.0        33.9        34.0        34.0        34.0        33.9        34.0

Roanoke Valley II                                          81.8        86.5        87.5             86.5        86.1      90.2        89.6        88.3         ‐            ‐ 88.9             ‐            ‐            ‐            ‐             ‐            ‐            ‐             ‐           

Roanoke Valley Project                                 88.5        78.1        84.2             86.5        85.4      86.3        86.7         ‐            ‐            ‐ 86.9             ‐            ‐            ‐            ‐             ‐            ‐            ‐             ‐           

Rosemary                                                       10.6          6.2          5.3             10.0          8.0        7.0          5.0          6.4          5.8          6.4          6.6          7.5          7.9          8.6          8.6          8.3          9.1          8.7          7.4

SEI Birchwood                                              24.1        19.3        28.5             61.3        50.8      45.6        42.6        43.9        41.5        45.2        41.5

Solar Partnership Program                                ‐            ‐            ‐             18.2        45.6      47.8        47.8        47.8        47.8        47.8        47.8        47.8        47.8        47.8        47.8        47.8        47.8        47.8        47.8

Southampton                                                17.0          6.8        15.8             85.9        93.3      93.3        93.3        93.3        93.3        93.3        93.3        93.3        93.3        87.7        93.0        93.3        93.0        93.3        93.3

Spruance Genco, Facility 1 (Richmon        55.0        11.7        11.8             79.9        75.7      69.2         ‐ 45.7             ‐            ‐            ‐             ‐            ‐            ‐            ‐             ‐            ‐            ‐             ‐           

Spruance Genco, Facility 2 (Richmon        44.9        11.4        13.1             74.6        62.3      64.1         ‐ 38.7             ‐            ‐            ‐             ‐            ‐            ‐            ‐             ‐            ‐            ‐             ‐           

Surry 1                                                           99.5        91.5        93.1           100.2        92.1      94.0      100.2        93.2        92.3      100.2        92.6        92.3      100.2        92.7        92.3      100.2        92.6        92.3      100.2

Surry 2                                                           76.7        90.5      103.1             91.0        91.7    100.2        94.3        92.3      100.2        92.7        92.3      100.2        92.6        92.3      100.2        92.6        92.3      100.2        92.6

Virginia City Hybrid Energy Center                ‐        42.9        68.7             81.0        72.9      76.8        80.2        81.4        78.9        88.9        83.4        80.2        86.6        82.0        77.7        86.1        83.2        78.4        86.3

Warren                                                                ‐            ‐            ‐                 ‐        72.8      71.7        65.6        63.4        60.3        65.8        59.4        58.9        55.6        51.6        55.5        53.2        48.7        51.7        44.7

Yorktown 1                                                    41.3        42.9        26.5             41.5         ‐          ‐            ‐ 37.9             ‐            ‐            ‐             ‐            ‐            ‐            ‐             ‐            ‐            ‐             ‐           

Yorktown 2                                                    45.1        17.6        32.1             48.0         ‐          ‐            ‐ 50.2             ‐            ‐            ‐             ‐            ‐            ‐            ‐             ‐            ‐            ‐             ‐           

Yorktown 3                                                      2.5        28.5          1.3               2.8          2.3        1.5          1.3          1.8          2.0          2.2          2.2          1.9          1.6          1.7          1.7          1.8          1.9          1.9          2.0
AP ‐ 26

Appendix 3E – Heat Rates

Company Name: Virginia Electric and Powe r Company Schedule 10a

UNIT PERFORMANCE DATA

Average Heat Rate ‐ (mmBtu/MWh)   (At Maximum)

(ACTUAL) (PROJECTED)

Unit Name 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029

Altavista                                                                        ‐ ‐                15.49 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44

Bath County Units 1‐6                                       N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A

Bear Garden                                                               7.02        7.06        7.02 7.18 7.18 7.18 7.18 7.18 7.18 7.18 7.18 7.18 7.18 7.18 7.18 7.18 7.18 7.18 7.18

Bellemeade                                                                8.82        8.52        8.34 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75 8.75

Bremo 3                                                                   12.52      12.83      13.00 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44

Bremo 4                                                                   10.52      10.72      10.76 10.73 10.73 10.73 10.73 10.73 10.73 10.73 10.73 10.73 10.73 10.73 10.73 10.73 10.73 10.73 10.73

Brunswick                                                                    ‐ ‐           ‐           ‐           ‐           6.83 6.83 6.83 6.83 6.83 6.83 6.83 6.83 6.83 6.83 6.83 6.83 6.83 6.83

Chesapeake 1                                                          10.97      10.91      10.66 10.66           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Chesapeake 2                                                          10.73      10.88      10.80 10.57           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Chesapeake 3                                                          10.51      10.61      10.51 10.13           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Chesapeake 4                                                          10.58      10.56      10.86 10.26           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Chesapeake CT 1, 2, 4, 6                                        17.04      17.97      20.42 18.54 18.54 18.54 18.54 18.54 18.54           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Chesterfield 3                                                          12.58      12.56      12.33 11.95 11.95 11.95 11.95 11.95 11.95 11.95 11.95 11.95 11.95 11.95 11.95 11.95 11.95 11.95 11.95

Chesterfield 4                                                            9.33      10.68      10.56 10.52 10.52 10.52 10.52 10.52 10.52 10.52 10.52 10.52 10.52 10.52 10.52 10.52 10.52 10.52 10.52

Chesterfield 5                                                          10.21        9.86      10.08 10.20 10.20 10.20 10.20 10.20 10.20 10.20 10.20 10.20 10.20 10.20 10.20 10.20 10.20 10.20 10.20

Chesterfield 6                                                          10.12      10.04        9.90 10.15 10.15 10.15 10.15 10.15 10.15 10.15 10.15 10.15 10.15 10.15 10.15 10.15 10.15 10.15 10.15

Chesterfield 7                                                            7.16        7.17        7.53 7.50 7.50 7.50 7.50 7.50 7.50 7.50 7.50 7.50 7.50 7.50 7.50 7.50 7.50 7.50 7.50

Chesterfield 8                                                            7.38        7.26        7.32 7.45 7.45 7.45 7.45 7.45 7.45 7.45 7.45 7.45 7.45 7.45 7.45 7.45 7.45 7.45 7.45

Clover 1                                                                   10.19      10.04        9.98 10.00 10.00 10.00 10.00 10.00 10.00 10.00 10.00 10.00 10.00 10.00 10.00 10.00 10.00 10.00 10.00

Clover 2                                                                   10.15      10.01      10.01 9.92 9.92 9.92 9.92 9.92 9.92 9.92 9.92 9.92 9.92 9.92 9.92 9.92 9.92 9.92 9.92

Covanta Fairfax                                                       10.00      10.00      10.00 10.00 10.00           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Cushaw Hydro                                                   N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A

Darbytown 1                                                           12.79      12.66      12.48 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00

Darbytown 2                                                           12.71      12.64      13.07 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00

Darbytown 3                                                           12.77      12.67      12.37 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00

Darbytown 4                                                           12.73      12.57      12.56 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00

Doswell Complex                                                    10.00      10.00      10.00 8.55 8.55 8.55 8.55           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Edgecombe Genco (Rocky Mountain)                   10.00      10.00      10.00 10.00 10.00           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Elizabeth River 1                                                     12.27      12.68      12.63 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15

Elizabeth River 2                                                     12.42      12.79      12.61 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15

Elizabeth River 3                                                     12.16      12.63      12.46 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15

Existing Solar NC NUGs with PPAs                 N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A

Future Solar NC Nugs           ‐ ‐           ‐           N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A

Gaston Hydro                                                     N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A

Generic CC 2019           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           6.76 6.76 6.76 6.76 6.76 6.76 6.76 6.76 6.76 6.76 6.76

Generic CC 2029           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           6.76

Generic CT 2022           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           9.04 9.04 9.04 9.04 9.04 9.04 9.04 9.04

Generic CT 2023           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           9.04 9.04 9.04 9.04 9.04 9.04 9.04

Gordonsville 1                                                           8.25        8.32        8.39 8.52 8.52 8.52 8.52 8.52 8.52 8.52 8.52 8.52 8.52 8.52 8.52 8.52 8.52 8.52 8.52

Gordonsville 2                                                           8.90        8.61        8.41 8.52 8.52 8.52 8.52 8.52 8.52 8.52 8.52 8.52 8.52 8.52 8.52 8.52 8.52 8.52 8.52

Gravel Neck 1‐2                                                      17.71      18.45      17.17 17.40 17.40 17.40 17.40 17.40 17.40           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Gravel Neck 3                                                          12.63      12.82      12.65 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32

Gravel Neck 4                                                          13.18      12.93      12.77 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32

Gravel Neck 5                                                          13.16      13.64      13.40 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32

Gravel Neck 6                                                          12.73      11.77      12.99 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32

Hopewell                                                                 12.32      12.09      14.91 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44

Hopewell Cogen                                                      10.00      10.00      10.00 8.47 8.47           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Ladysmith 1                                                            10.34      10.78      10.61 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51

Ladysmith 2                                                              9.98      10.51      10.33 10.46 10.46 10.46 10.46 10.46 10.46 10.46 10.46 10.46 10.46 10.46 10.46 10.46 10.46 10.46 10.46

Ladysmith 3                                                            10.08      10.56      10.50 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51

Ladysmith 4                                                            10.09      10.53      10.42 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51

Ladysmith 5                                                            10.03      10.48      10.44 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51 10.51

Lowmoor CT 1‐4                                                     17.65      16.98      17.19 16.76 16.76 16.76           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          
AP ‐ 27

Appendix 3E Cont. – Heat Rates

Company Name: Virginia Electric and Powe r Company Schedule 10a

UNIT PERFORMANCE DATA

Average Heat Rate ‐ (mmBtu/MWh)   (At Maximum)

(ACTUAL) (PROJECTED)

Unit Name 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029

Mecklenburg 1                                                        12.17      11.55      12.12 11.52 11.52 11.52 11.52 11.52 11.52 11.52 11.52 11.52 11.52 11.52 11.52 11.52 11.52 11.52 11.52

Mecklenburg 2                                                        12.27      11.89      12.37 11.67 11.67 11.67 11.67 11.67 11.67 11.67 11.67 11.67 11.67 11.67 11.67 11.67 11.67 11.67 11.67

Mount S torm 1                                                       10.03      10.18        9.84 9.79 9.79 9.79 9.79 9.79 9.79 9.79 9.79 9.79 9.79 9.79 9.79 9.79 9.79 9.79 9.79

Mount S torm 2                                                         9.76        9.87        9.79 9.81 9.81 9.81 9.81 9.81 9.81 9.81 9.81 9.81 9.81 9.81 9.81 9.81 9.81 9.81 9.81

Mount S torm 3                                                       10.14      10.42      10.24 10.27 10.27 10.27 10.27 10.27 10.27 10.27 10.27 10.27 10.27 10.27 10.27 10.27 10.27 10.27 10.27

Mount S torm CT                                                    23.59      21.80      15.97 20.36 20.36 20.36           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

North Anna 1                                                               ‐ ‐           ‐           10.60 10.60 10.60 10.60 10.60 10.60 10.60 10.60 10.60 10.60 10.60 10.60 10.60 10.60 10.60 10.60

North Anna 2                                                               ‐ ‐           ‐           10.64 10.64 10.64 10.64 10.64 10.64 10.64 10.64 10.64 10.64 10.64 10.64 10.64 10.64 10.64 10.64

North Anna Hydro                                            N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A

Northern Neck CT 1‐4                                            16.27      17.29      17.17 16.83 16.83 16.83 16.83           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Pittsylvania                                                              15.61      15.69      15.77 15.47 15.47 15.47 15.47 15.47 15.47 15.47 15.47 15.47 15.47 15.47 15.47 15.47 15.47 15.47 15.47

Possum Point 3                                                       11.27      11.19      11.39 11.09 11.09 11.09 11.09 11.09 11.09 11.09 11.09 11.09 11.09 11.09 11.09 11.09 11.09 11.09 11.09

Possum Point 4                                                       10.86      11.09      11.32 10.78 10.78 10.78 10.78 10.78 10.78 10.78 10.78 10.78 10.78 10.78 10.78 10.78 10.78 10.78 10.78

Possum Point 5                                                       11.63      11.23      10.86 10.77 10.77 10.77 10.77 10.77 10.77 10.77 10.77 10.77 10.77 10.77 10.77 10.77 10.77 10.77 10.77

Possum Point 6                                                         7.00        7.08        7.18 7.30 7.30 7.30 7.30 7.30 7.30 7.30 7.30 7.30 7.30 7.30 7.30 7.30 7.30 7.30 7.30

Possum Point CT 1‐6                                              17.27      16.69      16.64 16.76 16.76           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Remington 1                                                            10.22      10.87      10.62 10.71 10.71 10.71 10.71 10.71 10.71 10.71 10.71 10.71 10.71 10.71 10.71 10.71 10.71 10.71 10.71

Remington 2                                                            10.26      10.98      10.70 10.70 10.70 10.70 10.70 10.70 10.70 10.70 10.70 10.70 10.70 10.70 10.70 10.70 10.70 10.70 10.70

Remington 3                                                            10.44      11.01      10.78 10.71 10.71 10.71 10.71 10.71 10.71 10.71 10.71 10.71 10.71 10.71 10.71 10.71 10.71 10.71 10.71

Remington 4                                                            10.29      10.91      10.67 10.70 10.70 10.70 10.70 10.70 10.70 10.70 10.70 10.70 10.70 10.70 10.70 10.70 10.70 10.70 10.70

Roanoke Rapids Hydro                                      N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A

Roanoke Valley II                                                    10.00      10.00      10.00 10.00 10.00 10.00 10.00 10.00 10.00 10.00           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Roanoke Valley Project                                           10.00      10.00      10.00 10.00 10.00 10.00 10.00 10.00 10.00           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Rosemary                                                                   9.71        9.60        9.64 8.76 8.76 8.76 8.76 8.76 8.76 8.76 8.76 8.76 8.76 8.76 8.76 8.76 8.76 8.76 8.76

SEI Birchwood                                                        10.00      10.00      10.00 9.61 9.61 9.61 9.61 9.61 9.61 9.61 9.61           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Solar Partnership Program                                N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A

Southampton                                                          12.14      13.66      16.39 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44

Spruance Genco, Facility 1 (Richmond 1)             10.00      10.00      10.00 10.00 10.00 10.00 10.00           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Spruance Genco, Facility 2 (Richmond 2)             10.00      10.00      10.00 10.00 10.00 10.00 10.00           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Surry 1                                                                          ‐ ‐           ‐           10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54

Surry 2                                                                          ‐ ‐           ‐           10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54

Virginia City Hybrid Energy Center                          ‐      14.93      10.22 9.41 9.41 9.41 9.41 9.41 9.41 9.41 9.41 9.41 9.41 9.41 9.41 9.41 9.41 9.41 9.41

Warren                                                                          ‐ ‐           ‐           6.94 6.94 6.94 6.94 6.94 6.94 6.94 6.94 6.94 6.94 6.94 6.94 6.94 6.94 6.94 6.94

Yorktown 1                                                              10.46      10.48      10.72 10.58 10.58 10.58           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Yorktown 2                                                                9.87        9.79      10.16 10.23 10.23 10.23           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Yorktown 3                                                              11.73      10.77      10.48 10.64 10.64 10.64 10.64 10.64 10.64 10.64 10.64 10.64 10.64 10.64 10.64 10.64 10.64 10.64 10.64
AP ‐ 28

Appendix 3E Cont. – Heat Rates

Company Name: Virginia Ele ctric and Powe r Company Schedule 10b

UNIT PERFORMANCE DATA

Average Heat Rate ‐ (mmBtu/MWh)   (At Minimum)

(ACTUAL) (PROJECTED)

Unit Name 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029

Altavista                                                    N/A N/A N/A 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44

Bath County Units 1‐6                             N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A

Bear Garden                                             N/A N/A N/A 7.56 7.56 7.56 7.56 7.56 7.56 7.56 7.56 7.56 7.56 7.56 7.56 7.56 7.56 7.56 7.56

Bellemeade                                               N/A N/A N/A 9.51 9.51 9.51 9.51 9.51 9.51 9.51 9.51 9.51 9.51 9.51 9.51 9.51 9.51 9.51 9.51

Bremo 3                                                    N/A N/A N/A 14.50 14.50 14.50 14.50 14.50 14.50 14.50 14.50 14.50 14.50 14.50 14.50 14.50 14.50 14.50 14.50

Bremo 4 N/A N/A N/A 11.87 11.87 11.87 11.87 11.87 11.87 11.87 11.87 11.87 11.87 11.87 11.87 11.87 11.87 11.87 11.87

Brunswick                                                N/A N/A N/A           ‐ ‐           6.91 6.91 6.91 6.91 6.91 6.91 6.91 6.91 6.91 6.91 6.91 6.91 6.91 6.91

Chesapeake 1                                           N/A N/A N/A 10.93           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Chesapeake 2                                           N/A N/A N/A 10.85           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Chesapeake 3                                           N/A N/A N/A 10.41           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Chesapeake 4                                           N/A N/A N/A 10.33           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Chesapeake CT 1, 2, 4, 6                         N/A N/A N/A 18.54 18.54 18.54 18.54 18.54 18.54           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Chesterfield 3                                           N/A N/A N/A 14.22 14.22 14.22 14.22 14.22 14.22 14.22 14.22 14.22 14.22 14.22 14.22 14.22 14.22 14.22 14.22

Chesterfield 4                                           N/A N/A N/A 11.31 11.31 11.31 11.31 11.31 11.31 11.31 11.31 11.31 11.31 11.31 11.31 11.31 11.31 11.31 11.31

Chesterfield 5                                           N/A N/A N/A 11.54 11.54 11.54 11.54 11.54 11.54 11.54 11.54 11.54 11.54 11.54 11.54 11.54 11.54 11.54 11.54

Chesterfield 6                                           N/A N/A N/A 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54

Chesterfield 7                                           N/A N/A N/A 9.31 9.31 9.31 9.31 9.31 9.31 9.31 9.31 9.31 9.31 9.31 9.31 9.31 9.31 9.31 9.31

Chesterfield 8                                           N/A N/A N/A 9.27 9.27 9.27 9.27 9.27 9.27 9.27 9.27 9.27 9.27 9.27 9.27 9.27 9.27 9.27 9.27

Clover 1                                                    N/A N/A N/A 11.70 11.70 11.70 11.70 11.70 11.70 11.70 11.70 11.70 11.70 11.70 11.70 11.70 11.70 11.70 11.70

Clover 2 N/A N/A N/A 11.53 11.53 11.53 11.53 11.53 11.53 11.53 11.53 11.53 11.53 11.53 11.53 11.53 11.53 11.53 11.53

Covanta Fairfax                                        N/A N/A N/A 10.00 10.00           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Cushaw Hydro                                         N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A

Darbytown 1                                            N/A N/A N/A 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00

Darbytown 2                                            N/A N/A N/A 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00

Darbytown 3                                            N/A N/A N/A 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00

Darbytown 4                                            N/A N/A N/A 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00 12.00

Doswell Complex                                    N/A N/A N/A 8.55 8.55 8.55 8.55           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Edgecombe Genco (Rocky Mountain)   N/A N/A N/A 10.00 10.00           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Elizabeth River 1                                      N/A N/A N/A 12.86 12.86 12.86 12.86 12.86 12.86 12.86 12.86 12.86 12.86 12.86 12.86 12.86 12.86 12.86 12.86

Elizabeth River 2                                      N/A N/A N/A 12.86 12.86 12.86 12.86 12.86 12.86 12.86 12.86 12.86 12.86 12.86 12.86 12.86 12.86 12.86 12.86

Elizabeth River 3                                      N/A N/A N/A 12.86 12.86 12.86 12.86 12.86 12.86 12.86 12.86 12.86 12.86 12.86 12.86 12.86 12.86 12.86 12.86

Existing Solar NC NUGs with PPAs       N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A

Future Solar NC Nugs N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A

Gaston Hydro                                           N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A

Generic CC 2019 N/A N/A N/A           ‐ ‐           ‐           ‐           ‐           7.65 7.65 7.65 7.65 7.65 7.65 7.65 7.65 7.65 7.65 7.65

Generic CC 2029 N/A N/A N/A           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           7.65

Generic CT 2022 N/A N/A N/A           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           11.92 11.92 11.92 11.92 11.92 11.92 11.92 11.92

Generic CT 2023 N/A N/A N/A           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           11.92 11.92 11.92 11.92 11.92 11.92 11.92

Gordonsville 1                                          N/A N/A N/A 8.52 8.52 8.52 8.52 8.52 8.52 8.52 8.52 8.52 8.52 8.52 8.52 8.52 8.52 8.52 8.52

Gordonsville 2                                          N/A N/A N/A 8.63 8.63 8.63 8.63 8.63 8.63 8.63 8.63 8.63 8.63 8.63 8.63 8.63 8.63 8.63 8.63

Gravel Neck 1‐2                                       N/A N/A N/A 17.40 17.40 17.40 17.40 17.40 17.40           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Gravel Neck 3                                          N/A N/A N/A 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32

Gravel Neck 4                                          N/A N/A N/A 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32

Gravel Neck 5                                          N/A N/A N/A 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32

Gravel Neck 6                                          N/A N/A N/A 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32 12.32

Hopewell                                                  N/A N/A N/A 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44

Hopewell Cogen                                      N/A N/A N/A 8.47 8.47           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Ladysmith 1                                             N/A N/A N/A 12.09 12.09 12.09 12.09 12.09 12.09 12.09 12.09 12.09 12.09 12.09 12.09 12.09 12.09 12.09 12.09

Ladysmith 2                                             N/A N/A N/A 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15 12.15

Ladysmith 3                                             N/A N/A N/A 12.08 12.08 12.08 12.08 12.08 12.08 12.08 12.08 12.08 12.08 12.08 12.08 12.08 12.08 12.08 12.08

Ladysmith 4                                             N/A N/A N/A 12.09 12.09 12.09 12.09 12.09 12.09 12.09 12.09 12.09 12.09 12.09 12.09 12.09 12.09 12.09 12.09

Ladysmith 5                                             N/A N/A N/A 12.09 12.09 12.09 12.09 12.09 12.09 12.09 12.09 12.09 12.09 12.09 12.09 12.09 12.09 12.09 12.09

Lowmoor CT 1‐4                                     N/A N/A N/A 16.76 16.76 16.76           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          
AP ‐ 29

Appendix 3E Cont. – Heat Rates

Company Name: Virginia Ele ctric and Powe r Company Schedule 10b

UNIT PERFORMANCE DATA

Average Heat Rate ‐ (mmBtu/MWh)   (At Minimum)

(ACTUAL) (PROJECTED)

Unit Name 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029

Mecklenburg 1                                        N/A N/A N/A 13.39 13.39 13.39 13.39 13.39 13.39 13.39 13.39 13.39 13.39 13.39 13.39 13.39 13.39 13.39 13.39

Mecklenburg 2                                        N/A N/A N/A 13.55 13.55 13.55 13.55 13.55 13.55 13.55 13.55 13.55 13.55 13.55 13.55 13.55 13.55 13.55 13.55

Mount Storm 1                                        N/A N/A N/A 10.50 10.50 10.50 10.50 10.50 10.50 10.50 10.50 10.50 10.50 10.50 10.50 10.50 10.50 10.50 10.50

Mount Storm 2                                        N/A N/A N/A 10.47 10.47 10.47 10.47 10.47 10.47 10.47 10.47 10.47 10.47 10.47 10.47 10.47 10.47 10.47 10.47

Mount Storm 3                                        N/A N/A N/A 10.65 10.65 10.65 10.65 10.65 10.65 10.65 10.65 10.65 10.65 10.65 10.65 10.65 10.65 10.65 10.65

Mount Storm CT                                     N/A N/A N/A 20.36 20.36 20.36           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

North Anna 1                                           N/A N/A N/A 10.60 10.60 10.60 10.60 10.60 10.60 10.60 10.60 10.60 10.60 10.60 10.60 10.60 10.60 10.60 10.60

North Anna 2                                           N/A N/A N/A 10.64 10.64 10.64 10.64 10.64 10.64 10.64 10.64 10.64 10.64 10.64 10.64 10.64 10.64 10.64 10.64

North Anna Hydro                                  N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A

Northern Neck CT 1‐4                            N/A N/A N/A 16.83 16.83 16.83 16.83           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Pittsylvania                                               N/A N/A N/A 15.47 15.47 15.47 15.47 15.47 15.47 15.47 15.47 15.47 15.47 15.47 15.47 15.47 15.47 15.47 15.47

Possum Point 3                                        N/A N/A N/A 12.46 12.46 12.46 12.46 12.46 12.46 12.46 12.46 12.46 12.46 12.46 12.46 12.46 12.46 12.46 12.46

Possum Point 4                                        N/A N/A N/A 12.11 12.11 12.11 12.11 12.11 12.11 12.11 12.11 12.11 12.11 12.11 12.11 12.11 12.11 12.11 12.11

Possum Point 5                                        N/A N/A N/A 11.92 11.92 11.92 11.92 11.92 11.92 11.92 11.92 11.92 11.92 11.92 11.92 11.92 11.92 11.92 11.92

Possum Point 6                                        N/A N/A N/A 8.11 8.11 8.11 8.11 8.11 8.11 8.11 8.11 8.11 8.11 8.11 8.11 8.11 8.11 8.11 8.11

Possum Point CT 1‐6                               N/A N/A N/A 16.76 16.76           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Remington 1                                            N/A N/A N/A 12.39 12.39 12.39 12.39 12.39 12.39 12.39 12.39 12.39 12.39 12.39 12.39 12.39 12.39 12.39 12.39

Remington 2                                            N/A N/A N/A 12.43 12.43 12.43 12.43 12.43 12.43 12.43 12.43 12.43 12.43 12.43 12.43 12.43 12.43 12.43 12.43

Remington 3                                            N/A N/A N/A 12.40 12.40 12.40 12.40 12.40 12.40 12.40 12.40 12.40 12.40 12.40 12.40 12.40 12.40 12.40 12.40

Remington 4                                            N/A N/A N/A 12.41 12.41 12.41 12.41 12.41 12.41 12.41 12.41 12.41 12.41 12.41 12.41 12.41 12.41 12.41 12.41

Roanoke Rapids Hydro                           N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A

Roanoke Valley II                                     N/A N/A N/A 10.00 10.00 10.00 10.00 10.00 10.00 10.00           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Roanoke Valley Project                            N/A N/A N/A 10.00 10.00 10.00 10.00 10.00 10.00           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Rosemary                                                 N/A N/A N/A 9.61 9.61 9.61 9.61 9.61 9.61 9.61 9.61 9.61 9.61 9.61 9.61 9.61 9.61 9.61 9.61

SEI Birchwood                                         N/A N/A N/A 11.73 11.73 11.73 11.73 11.73 11.73 11.73 11.73           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Solar Partnership Program                      N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A

Southampton                                           N/A N/A N/A 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44 13.44

Spruance Genco, Facility 1 (Richmond N/A N/A N/A 10.00 10.00 10.00 10.00           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Spruance Genco, Facility 2 (Richmond N/A N/A N/A 10.00 10.00 10.00 10.00           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Surry 1                                                     N/A N/A N/A 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54

Surry 2 N/A N/A N/A 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54 10.54

Virginia City Hybrid Energy Center       N/A N/A N/A 9.76 9.76 9.76 9.76 9.76 9.76 9.76 9.76 9.76 9.76 9.76 9.76 9.76 9.76 9.76 9.76

Warren                                                     N/A N/A N/A 7.76 7.76 7.76 7.76 7.76 7.76 7.76 7.76 7.76 7.76 7.76 7.76 7.76 7.76 7.76 7.76

Yorktown 1                                              N/A N/A N/A 12.25 12.25 12.25           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Yorktown 2                                              N/A N/A N/A 11.12 11.12 11.12           ‐ ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐           ‐          

Yorktown 3                                              N/A N/A N/A 11.49 11.49 11.49 11.49 11.40 11.40 11.40 11.40 11.40 11.40 11.40 11.40 11.40 11.40 11.40 11.40
AP ‐ 30

Appendix 3F – Existing Capacity

(1) Net dependable installed capability during peak season.

(2) Each item in Section I as a percent of line n (Total).

Company Name: Virginia Electric and Powe r Company 

CAPACITY DATA

(ACTUAL) (PROJECTED)

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 

I. Installed Capacity (MW)(1)

a. Nucle ar 3,329 3,349 3,362 3,349 3,349 3,349 3,349 3,349 3,349 3,349 3,349 3,349 3,349 3,349 3,349 b. Coal 4,658 5,248 5,373 4,964 4,380 4,048 4,042 4,036 4,030 4,024 4,020 4,020 4,020 4,020 4,020 c. Heavy Fuel Oil 1,589 1,589 1,575 1,576 1,576 1,576 1,576 1,576 1,576 1,576 1,576 1,576 1,576 1,576 1,576 d. Light Fuel Oil 596 596 596 257 185 126 79 79               ‐ ‐               ‐               ‐               ‐               ‐               ‐               

 

e. Natural Gas‐Boile r 316 316 316 543 543 543 543 543 543 543 543 543 543 543 543 f. Natural Gas‐Combined Cycle 2,188 2,187 2,187 2,196 3,533 4,908 4,908 4,908 6,474 6,474 6,474 6,474 6,474 6,474 6,474 g. Natural Gas‐Turbine 2,053 2,053 2,053 2,415 2,415 2,415 2,415 2,415 2,415 2,415 2,415 2,872 3,329 3,329 3,329 h. Hydro‐Conventional 317 317 317 321 321 321 321 321 321 321 321 321 321 321 321 i. Pumped Storage 1,802 1,802 1,802 1,802 1,802 1,802 1,802 1,802 1,802 1,802 1,802 1,802 1,802 1,802 1,802 j. Renewable 83 83 83 254 263 273 279 285 292 298 301 301 301 301 301 k. Total Company Installed 16,931 17,540 17,665 17,677 18,366 19,361 19,314 19,314 20,801 20,801 20,801 21,257 21,714 21,714 21,714 l. Othe r (NUG) 1,787 1,787 1,787 1,785 1,741 1,308 702 502 336 292 291 73 73 73 72 n. Total 18,718 19,327 19,451 19,462 20,107 20,668 20,016 19,815 21,137 21,092 21,092 21,331 21,787 21,787 21,786 

II. Installed Capacity Mix (%)(2)

a. Nucle ar 17.8% 17.3% 17.3% 17.2% 16.7% 16.2% 16.7% 16.9% 15.8% 15.9% 15.9% 15.7% 15.4% 15.4% 15.4% b. Coal 24.9% 27.2% 27.6% 25.5% 21.8% 19.6% 20.2% 20.4% 19.1% 19.1% 19.1% 18.8% 18.5% 18.5% 18.5% c. Heavy Fuel Oil 8.5% 8.2% 8.1% 8.1% 7.8% 7.6% 7.9% 8.0% 7.5% 7.5% 7.5% 7.4% 7.2% 7.2% 7.2% d. Light Fuel Oil 3.2% 3.1% 3.1% 1.3% 0.9% 0.6% 0.4% 0.4%               ‐ ‐               ‐               ‐               ‐               ‐               ‐               

 

e. Natural Gas‐Boile r 1.7% 1.6% 1.6% 2.8% 2.7% 2.6% 2.7% 2.7% 2.6% 2.6% 2.6% 2.5% 2.5% 2.5% 2.5% f. Natural Gas‐Combined Cycle 11.7% 11.3% 11.2% 11.3% 17.6% 23.7% 24.5% 24.8% 30.6% 30.7% 30.7% 30.4% 29.7% 29.7% 29.7% g. Natural Gas‐Turbine 11.0% 10.6% 10.6% 12.4% 12.0% 11.7% 12.1% 12.2% 11.4% 11.4% 11.4% 13.5% 15.3% 15.3% 15.3% h. Hydro‐Conventional 1.7% 1.6% 1.6% 1.6% 1.6% 1.6% 1.6% 1.6% 1.5% 1.5% 1.5% 1.5% 1.5% 1.5% 1.5% i. Pumped Storage 9.6% 9.3% 9.3% 9.3% 9.0% 8.7% 9.0% 9.1% 8.5% 8.5% 8.5% 8.4% 8.3% 8.3% 8.3% j. Renewable 0.4% 0.4% 0.4% 1.3% 1.3% 1.3% 1.4% 1.4% 1.4% 1.4% 1.4% 1.4% 1.4% 1.4% 1.4% k. Total Company Installed 90.5% 90.8% 90.8% 90.8% 91.3% 93.7% 96.5% 97.5% 98.4% 98.6% 98.6% 99.7% 99.7% 99.7% 99.7% l. Other (NUG) 9.5% 9.2% 9.2% 9.2% 8.7% 6.3% 3.5% 2.5% 1.6% 1.4% 1.4% 0.3% 0.3% 0.3% 0.3% n. Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 
AP ‐ 31

Appendix 3G – Energy Generation by Type (GWh)

(1) Include current estimates for renewable energy generation by VCHEC.(2) Payback Energy is accounted for in Total Generation.

(3) Include all sales or delivery transactions with other electric utilities, i.e., firm or economy sales, etc.

Company Name: Virginia Electric and Powe r Company

GENERATION

(ACTUAL) (PROJECTED)

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 

I. System Output (GWh)

a. Nucle ar 24,096 27,186 27,669 27,969 27,635 27,715 28,244 27,618 27,617 28,287 27,615 27,617 28,207 27,699 27,618 

b. Coal 21,831 18,480 24,863 27,574 21,182 22,350 24,007 25,951 24,699 25,029 24,102 23,469 21,965 22,061 22,211 c. He avy Fuel Oil 250 164 119 300 245 179 150 174 205 222 224 195 175 183 184 d. Light Fuel Oil 85 74 45 22 14 9 4 3 1               ‐ ‐               ‐               ‐               ‐               ‐               e. Natural Gas‐Boile r 135 180 146 656 588 408 334 418 362 379 393 410 415 410 420 f. Natural Gas‐Combined Cycle 9,152 13,214 11,715 10,239 18,688 24,201 25,537 25,043 32,904 33,775 32,596 31,638 30,389 30,302 30,291 g. Natural Gas‐Turbine 925 1,179 1,640 1,741 1,393 1,242 1,295 1,371 1,319 1,345 1,345 1,582 1,703 1,751 1,711 h. Hydro‐Conventional 661 580 1,025 601 601 601 601 601 601 601 601 601 601 601 601 i. Hydro‐Pumped Storage 2,523 2,500 2,421 1,981 1,241 1,771 1,596 1,927 1,111 1,122 1,433 1,493 1,534 1,642 1,694 j. Renewable(1) 393 341 666 1,552 1,492 1,565 1,806 1,927 2,083 2,171 2,118 2,170 2,275 2,268 2,278 k. Total Generation 60,050 63,897 70,308 72,637 73,079 80,040 83,574 85,033 90,903 92,931 90,427 89,175 87,264 86,918 87,008 l. Purchased Powe r 28,276 22,633 17,561 18,525 19,069 14,605 11,145 10,537 7,476 6,780 8,420 10,358 12,775 13,611 14,537 m. Total Payback Ene rgy(2)               ‐ ‐ 12 11 10 17 19 21 22 20 21 21 21 22 n. Le ss Pumping Ene rgy ‐3,151 ‐3,097 ‐3,015 ‐2,489 ‐1,559 ‐2,225 ‐2,005 ‐2,421 ‐1,395 ‐1,409 ‐1,800 ‐1,876 ‐1,928 ‐2,063 ‐2,128 o. Le ss Othe r Sale s(3) ‐847 ‐1,219 ‐1,166 ‐3,165 ‐3,507 ‐3,424 ‐2,495 ‐2,075 ‐5,442 ‐5,844 ‐4,047 ‐3,689 ‐3,221 ‐2,565 ‐2,228 p. Total System Firm Energy Req. 84,328 82,214 83,688 85,508 87,082 88,996 90,218 91,075 91,542 92,458 93,000 93,968 94,890 95,901 97,190 

II. Energy Supplied by Competitive

Se rvice Provide rs N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 
AP ‐ 32

Appendix 3H – Actual Energy Generation by Type (%) 

(1) Economy energy.

Company Name: Virginia Electric and Powe r Company

GENERATION

(ACTUAL) (PROJECTED)

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 

III. System Output Mix (%)

a. Nucle ar 28.6% 33.1% 33.1% 32.7% 31.7% 31.1% 31.3% 30.3% 30.2% 30.6% 29.7% 29.4% 29.7% 28.9% 28.4% 

b. Coal 25.9% 22.5% 29.7% 32.2% 24.3% 25.1% 26.6% 28.5% 27.0% 27.1% 25.9% 25.0% 23.1% 23.0% 22.9% c. He avy Fuel Oil 0.3% 0.2% 0.1% 0.4% 0.3% 0.2% 0.2% 0.2% 0.2% 0.2% 0.2% 0.2% 0.2% 0.2% 0.2% d. Light Fuel Oil 0.1% 0.1% 0.1% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% e. Na tural Gas‐Boile r 0.2% 0.2% 0.2% 0.8% 0.7% 0.5% 0.4% 0.5% 0.4% 0.4% 0.4% 0.4% 0.4% 0.4% 0.4% f. Na tural Gas‐Combined Cycle 10.9% 16.1% 14.0% 12.0% 21.5% 27.2% 28.3% 27.5% 35.9% 36.5% 35.0% 33.7% 32.0% 31.6% 31.2% g. Na tural Gas‐Turbine 1.1% 1.4% 2.0% 2.0% 1.6% 1.4% 1.4% 1.5% 1.4% 1.5% 1.4% 1.7% 1.8% 1.8% 1.8% h. Hydro‐Conventional 0.8% 0.7% 1.2% 0.7% 0.7% 0.7% 0.7% 0.7% 0.7% 0.7% 0.6% 0.6% 0.6% 0.6% 0.6% i. Hydro‐Pumped Storage 3.0% 3.0% 2.9% 2.3% 1.4% 2.0% 1.8% 2.1% 1.2% 1.2% 1.5% 1.6% 1.6% 1.7% 1.7% j. Renewable Resources 0.5% 0.4% 0.8% 1.8% 1.7% 1.8% 2.0% 2.1% 2.3% 2.3% 2.3% 2.3% 2.4% 2.4% 2.3% k. Total Generation 71.2% 77.7% 84.0% 84.9% 83.9% 89.9% 92.6% 93.4% 99.3% 100.5% 97.2% 94.9% 92.0% 90.6% 89.5% l. Purchased Powe r 33.5% 27.5% 21.0% 21.7% 21.9% 16.4% 12.4% 11.6% 8.2% 7.3% 9.1% 11.0% 13.5% 14.2% 15.0% m. Direct Load Control (DLC) 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% n. Less Pumping Ene rgy ‐3.7% ‐3.8% ‐3.6% ‐2.9% ‐1.8% ‐2.5% ‐2.2% ‐2.7% ‐1.5% ‐1.5% ‐1.9% ‐2.0% ‐2.0% ‐2.2% ‐2.2% o. Less Othe r Sales(1) ‐1.0% ‐1.5% ‐1.4% ‐3.7% ‐4.0% ‐3.8% ‐2.8% ‐2.3% ‐5.9% ‐6.3% ‐4.4% ‐3.9% ‐3.4% ‐2.7% ‐2.3% 

p. Total System Output 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% IV. System Load Factor 53.8% 54.8% 57.5% 55.3% 54.8% 54.2% 53.9% 56.8% 56.5% 56.4% 55.8% 55.8% 55.6% 55.6% 55.5% 
AP ‐ 33

Appendix 3I – Planned Changes to Existing Generation Units

(1) Peak net dependable capability as of this filing. Incremental uprates shown as positive (+) and decremental derates shown as negative (‐)

Company Name: Virginia Electric and Powe r Company Schedule 13a

UNIT PERFORMANCE DATA(1)

Unit Size (MW) Uprate and Derate

(ACTUAL) (PROJECTED)

Unit Name 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029

Altavista                                                                             ‐ ‐              ‐12              ‐ ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Ba th County Units 1‐6                                                 ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Be ar Garden                                                              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Belleme ade                                                               ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Bremo 3                                                                  ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Bremo 4                                                                  ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Brunswick                                                                             ‐ ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Chesape ake 1                                                             ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Chesape ake 2                                                             ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Chesape ake 3                                                             ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Chesape ake 4                                                             ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Chesape ake CT 1, 2, 4, 6                                            ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Cheste rfield 3                                                           ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Cheste rfield 4                                                           ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Cheste rfield 5                                                           9              ‐ ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Cheste rfield 6                                                           ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Cheste rfield 7                                                           ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Cheste rfield 8                                                           ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Clove r 1                                                                 ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Clove r 2                                                                 ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Covanta Fairfax                                                          ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Cushaw Hydro                                                             ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Darbytown 1                                                              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Darbytown 2                                                              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Darbytown 3                                                              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Darbytown 4                                                              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Doswell Complex                                                         ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Edgecombe Genco (Rocky Mountain)                    ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Elizabe th Rive r 1                                                        ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Elizabe th Rive r 2                                                        ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Elizabe th Rive r 3                                                        ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Existing Solar NC NUGs with PPAs                          ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Future Solar NC Nugs              ‐ ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Gaston Hydro              ‐ ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Gene ric CC 2019              ‐ ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Gene ric CC 2029              ‐ ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Gene ric CT 2022              ‐ ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Gene ric CT 2023              ‐ ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Gordonsville 1                                                           ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Gordonsville 2                                                           ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Gravel Neck 1‐2                                                          ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Gravel Neck 3                                                            ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Gravel Neck 4                                                            ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Gravel Neck 5                                                            ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Gravel Neck 6                                                            ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Hopewell                                                                 ‐              ‐              ‐12              ‐ ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Hopewell Cogen                                                          ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Incremental Ne t Me te r                                              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Ladysmith 1                                                              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Ladysmith 2                                                              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Ladysmith 3                                                              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Ladysmith 4                                                              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Ladysmith 5                                                              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Lowmoor CT 1‐4                                                           ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             
AP ‐ 34

Appendix 3I Cont. – Planned Changes to Existing Generation Units

(1) Peak net dependable capability as of this filing. Incremental uprates shown as positive (+) and decremental derates shown as negative (‐)  

Unit Name 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029

Me cklenburg 1                                                            ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Me cklenburg 2                                                            ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Mount Storm 1                                                            ‐              ‐              30              ‐ ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Mount Storm 2                                                            31              ‐ ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Mount Storm 3                                                            ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Mount Storm CT                                                          ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

North Anna 1                                                             ‐              23              ‐ ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

North Anna 2                                                             ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

North Anna Hydro                                                       ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Northe rn Neck CT 1‐4                                                 ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Pittsylvania                                                             ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Possum Point 3                                                           ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Possum Point 4                                                           ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Possum Point 5                                                           ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Possum Point 6                                                           ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Possum Point CT 1‐6                                                   ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Remington 1                                                              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Remington 2                                                              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Remington 3                                                              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Remington 4                                                              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Roanoke Rapids Hydro                                              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Roanoke Valley II                                                       ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Roanoke Valley Project                                              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Rosemary                                                                 ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

SEI Birchwood                                                            ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Solar Partne rship Program                                       ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Southampton                                                              ‐              ‐              ‐12              ‐ ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Spruance Genco, Facility 1 (Richmond 1)               ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Spruance Genco, Facility 2 (Richmond 2)               ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Surry 1                                                                  ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Surry 2                                                                  40              ‐ ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Virginia City Hybrid Ene rgy Cente r                        ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Warren                                                                   ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Yorktown 1                                                               ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Yorktown 2                                                               ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             

Yorktown 3                                                               ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐             
AP ‐ 35

Appendix 3I Cont. – Planned Changes to Existing Generation Units

(1) Peak net dependable capability as of this filing.

Company Name: Virginia Electric and Power Company Schedule 13b

UNIT PERFORMANCE DATA(1)

Planned Changes to Existing Generation Units

Station / Unit Name Uprate/Derate Description

Expected 

Removal 

Date

Expected 

Return 

Date

Base 

Rating

Revised 

Rating MW

Bremo 3 Fuel Switch N/A May-14 71 71 - 

Bremo 4 Fuel Switch N/A Jun-14 156 156 - 
AP ‐ 36

Appendix 3J – Potential Unit Retirements

(1) Reflects retirement assumptions used for planning purposes, not firm Company commitments.

Company Name: Schedule 19

UNIT PERFORMANCE DATA

Planned Unit Retirements(1)

Unit Name Location

Unit

Type

P rimary

Fuel Type

P rojected

Retirement

Year

MW

Summer

MW

Winter

Possum Point CT                             Dumfries, VA CombustionTurbine Light Fuel Oil 2015 72 96

      Possum Point GT1 12

      Possum Point GT2 12

      Possum Point GT3 12

      Possum Point GT4 12

      Possum Point GT5 12

      Possum Point GT6 12

Chesapeake Energy Center               Chesapeake, VA Steam‐ Cycle Coal 2015 578 578

      Chesapeake 1                                 111

      Chesapeake 2 111

      Chesapeake 3 149

      Chesapeake 4 207

Yorktown 1                                          Yorktown, VA Steam‐Cycle Coal 2016 159 160

Yorktown 2                                          Yorktown, VA Steam‐Cycle Coal 2016 164 164

Lowmoor CT                                    Covington, VA CombustionTurbine Light Fuel Oil 2016 48 64

      Lowmoor GT1 12

      Lowmoor GT2 12

      Lowmoor GT3 12

      Lowmoor GT4 12

Mount Storm CT                                Mt. Storm, WV CombustionTurbine Light Fuel Oil 2016 11 12

      Mt. S torm GT1 11

Northern Neck CT                             Warsaw, VA CombustionTurbine Light Fuel Oil 2017 47 63

      Northern Neck GT1 12

      Northern Neck GT2 11

      Northern Neck GT3 12

      Northern Neck GT4 12

Chesapeake CT 1                               Chesapeake, VA CombustionTurbine Light Fuel Oil 2019 15 20

      Chesapeake GT1 15

Chesapeake CT 2 Chesapeake, VA CombustionTurbine Light Fuel Oil 2019 36 49

      Chesapeake GT2 12

      Chesapeake GT4 12

      Chesapeake GT6 12

Gravel Neck 1                                     Surry, VA CombustionTurbine Light Fuel Oil 2019 28 38

      Gravel Neck GT1 12

      Gravel Neck GT2 16

Virginia Electric and Powe r Company
AP ‐ 37

Appendix 3K – Generation under Construction

(1) Commercial Operation Date.

(2) Phase 1 to be completed by 2015; Phase 2 to be completed by 2016.

(3) Firm capacity.

Company Name: Virginia Electric and Power Company Schedule 15a

UNIT PERFORMANCE DATA

Planned Supply‐Side Resources (MW)

Unit Name Location Unit Type Primary Fuel

Type C.O.D.(1) MW

Summer(3)

MW

Nameplate

Under Construction

Solar Partnership Program Distributed Intermittent Solar   2016(2) 4 13

Warren County Powe r Station                 Warren County, VA Inte rmedia te / Baseload Na tural Gas Dec‐2014 1,337 1,337

Brunswick County Powe r Sta tion             Brunswick County, VA Inte rmedia te / Baseload Na tural Gas May‐2016 1,375 1,375
AP ‐ 38

Appendix 3L – Wholesale Power Sales Contracts

(1) Full requirements contracts do not have a specific contracted capacity amount. MWs are included in the Company’s load forecast.

(2) VMEA contract reflects values.

Virginia Electric and Powe r Company 

WHOLESALE POWER SALES CONTRACTS

(Actual) (Projected)

Entity Contract Length Contract Type 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 202

North Carolina

ElectricMembe rshipCoop 12/31/2014

Non‐Firm

Partial Requirements 150 150 150 150              ‐ ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              ‐              

         

Craig‐Bote tourtElectric Coop

12‐Month

Te rmina tionNotice

FullRequirements(1) 667 6 6666666666

Town of Windsor,

North Carolina

12‐Month

Te rmina tionNotice

FullRequirements(1) 9 9 9 11 11 11 11 11 11 11 11 12 12 12 

VirginiaMunicipalElectricAssocia tion

5/31/2031with annual renewal

FullRequirements(1) 358 344 338 338 339 341 345 350 355 359 365 369 374 378 

Company Name:
AP ‐ 39

Appendix 3M – Description of Approved DSM Programs

Air Conditioner Cycling Program

Branded Name:    Smart Cooling Rewards

State:       North Carolina & Virginia

Target Class:      Residential

NC Program Type:   Peak‐Shaving

VA Program Type: Peak‐Shaving

NC Duration:     Ongoing

VA Duration:     Ongoing

Program Description:  

This Program provides participants with an external radio frequency cycling switch that operates on

central air conditioners and heat pump systems.  Participants allow the Company to cycle their

central air conditioning and heat pump systems during peak load periods.  The cycling switch is

installed by a contractor and located on or near the outdoor air conditioning unit(s).  The Company

remotely signals the unit when peak load periods are expected, and the air conditioning or heat

pump system is cycled off and on for short intervals.

Program Marketing:

Door to door marketing is currently the most effective marketing technique for this Program.  The

Company also uses other enrollment methods including business reply cards, online enrollment,

and call centers.  

Residential Low Income Program

Branded Name:    Income Qualifying Home Improvement Program  

State:       North Carolina & Virginia

Target Class:   Residential

NC Program Type:   Energy Efficiency

VA Program Type: Energy Efficiency

NC Duration:     Ongoing

VA Duration:     Ongoing

Program Description:  

The Low Income Program provides an energy audit for residential customers who meet the low

income criteria defined by state social service agencies.  A certified technician performs an audit of

participating residences to determine potential energy efficiency improvements.  Specific energy

efficiency measures applied may include, but are not limited to: envelope sealing, water heater

temperature set point reduction, installation of insulation wrap around the water heater and pipes,

installation of low flow shower head(s), replacement of incandescent lighting with efficient lighting,

duct sealing, attic insulation, and air filter replacement.  
AP ‐ 40

Appendix 3M cont. – Description of Approved DSM Programs

Program Marketing:

The Company markets this Program using a neighborhood canvassing approach in prescreened

areas targeting income qualifying customers.  To ensure neighborhood security and program

legitimacy, community posters, truck decals, yard signs, and authorization forms have been

produced and are displayed in areas where the Program has current activity.  

Non‐Residential Distributed Generation Program

Branded Name:    Distributed Generation

State:       Virginia

Target Class:      Commercial and Industrial

VA Program Type: Demand‐Side Management

VA Duration:     2012 – 2038  

Program Description:  

As part of this Program, a third‐party contractor will dispatch, monitor, maintain and operate

customer‐owned generation when called upon by the Company at anytime for up to a total of 120

hours per year.  The Company will supervise and implement the Non‐Residential Distributed

Generation Program through the third‐party implementation contractor.  Participating customers

will receive an incentive in exchange for their agreement to reduce electrical load on the Company’s

system when called upon to do so by the Company.  The incentive is based upon the amount of load

curtailment delivered during control events.  At least 80% of the program participation incentive is

required to be passed through to the customer, with 100% of fuel and operations and maintenance

compensation passed along to the customer.  When not being dispatched by the Company, the

generators may be used at the participants’ discretion or to supply power during an outage,

consistent with applicable environmental restrictions.   

Program Marketing:

Marketing will be handled by the Company’s implementation vendor.
AP ‐ 41

Appendix 3M cont. – Description of Approved DSM Programs

Non‐Residential Energy Audit Program

Target Class:      Non‐residential

NC Program Type:   Energy Efficiency

VA Program Type:   Energy Efficiency  

NC Duration:     2014 – 2038

VA Duration:     2012 – 2038   

Program Description:  

As part of this Program, an energy auditor will perform an on‐site energy audit of a non‐residential

customer’s facility. The customer will receive a report showing the projected energy and cost

savings that could be anticipated from implementation of options identified during the audit. Once a

qualifying customer provides documentation that some of the recommended energy efficiency

improvements have been made at the customer’s expense, a portion of the audit value will be

refunded depending upon the measures installed.

Program Marketing:  

The Company has a number of marketing activities planned for its recently approved DSM

Programs, including but not limited to: direct mail, bill inserts, web content, social media and

outreach events.  Because these programs are implemented using a contractor network, customers

will enroll in the program by contacting a participating contractor. The Company will utilize the

contractor network to market the programs to customers as well.   

Non‐Residential Duct Testing & Sealing Program

Target Class:      Non‐Residential

NC Program Type:   Energy Efficiency

VA Program Type: Energy Efficiency  

NC Duration:     2014 – 2038

VA Duration:     2012 – 2038   

   

Program Description:  

This Program will promote testing and general repair of poorly performing duct and air distribution

systems in non‐residential facilities.  The Program provides incentives to qualifying customers to

have a contractor seal ducts in existing buildings using program‐approved methods, including:

aerosol sealant, mastic, or foil tape with an acrylic adhesive.  Such systems include air handlers, air

intake, return and supply plenums, and any connecting duct work.   

   
AP ‐ 42

Appendix 3M cont. – Description of Approved DSM Programs

Program Marketing:  

The Company uses a number of marketing activities to promote its approved DSM Programs,

including but not limited to: direct mail, bill inserts, web content, social media and outreach events.

Because these programs are implemented using a contractor network, customers will enroll in the

program by contacting a participating contractor. The Company will utilize the contractor network

to market the programs to customers as well.   

Residential Bundle Program

Target Class:      Residential  

NC Program Type:   Energy Efficiency  

VA Program Type:   Energy Efficiency  

NC Duration:     2014 – 2038  

VA Duration:     2012 – 2038   

The Residential Bundle Program includes the four DSM Programs described below.

Program Marketing:  

The Company uses a number of marketing activities to promote its approved DSM Programs,

including but not limited to: direct mail, bill inserts, web content, social media and outreach events.  

Because these programs are implemented using a contractor network, customers will enroll in the

program by contacting a participating contractor.  The Company will utilize the contractor network

to market the programs to customers as well.   

Residential Home Energy Check‐Up Program

Program Description:  

The purpose of this Program is to provide owners and occupants of single family homes an easy and

low cost home energy audit.  It will include a walk through audit of customer homes, direct install

measures, and recommendations for additional home energy improvements.

Residential Duct Sealing Program

Program Description:  

This Program is designed to promote the testing and repair of poorly performing duct and air

distribution systems.  Qualifying customers will be provided an incentive to have a contractor test

and seal ducts in their homes using methods approved for the Program, such as mastic material or

foil tape with an acrylic adhesive to seal all joints and connections.  The repairs are expected to

reduce the average air leakage of a home’s conditioned floor area to industry standards.

Residential Heat Pump Tune‐Up Program

Program Description:  

This Program provides qualifying customers with an incentive to have a contractor tune‐up their

existing heat pumps once every five years in order to achieve maximum operational performance.  A

properly tuned system should increase efficiency, reduce operating costs, and prevent premature

equipment failures.
AP ‐ 43

Appendix 3M cont. – Description of Approved DSM Programs

Residential Heat Pump Upgrade Program

Program Description:  

This Program provides incentives for residential heat pump (e.g., air and geothermal) upgrades.  

Qualifying equipment must have better Seasonal Energy Efficiency Ratio and Heating Seasonal

Performance Factor ratings than the current nationally mandated efficiency standards.

Non‐Residential Heating & Cooling Efficiency Program

Target Class:     Non‐Residential

VA Program Type: Energy Efficiency

VA Duration:     2014 – 2038

Program Description:

This Program provides qualifying non‐residential customers with incentives to implement new

and upgrade existing HVAC equipment to more efficient HVAC technologies that can produce

verifiable savings.   

Program Marketing:  

The Company uses a number of marketing activities to promote its approved DSM Programs,

including but not limited to: direct mail, bill inserts, web content, social media, and outreach events.

Because these programs are implemented using a contractor network, customers will enroll in the

program by contacting a participating contractor.  The Company will utilize the contractor network

to market the programs to customers as well.   

Non‐Residential Lighting Systems & Controls Program

Target Class:     Non‐Residential

VA Program Type: Energy Efficiency

VA Duration:     2014 – 2038

Program Description:  

This Program provides qualifying non‐residential customers with an incentive to implement

more efficient lighting technologies that can produce verifiable savings.  The Program promotes

the installation of lighting technologies including but not limited to compact fluorescent bulbs, LED‐ 

based bulbs, and lighting control systems.

Program Marketing:  

The Company uses a number of marketing activities to promote its approved DSM Programs,

including but not limited to: direct mail, bill inserts, web content, social media, and outreach events.

Because these programs are implemented using a contractor network, customers will enroll in the

program by contacting a participating contractor.  The Company will utilize the contractor network

to market the programs to customers as well.   
AP ‐ 44

Appendix 3M cont. – Description of Approved DSM Programs

Non‐Residential Window Film Program

Target Class:     Non‐Residential

VA Program Type: Energy Efficiency

VA Duration:      2014 – 2038

Program Description:  

This Program provides qualifying non‐residential customers with an incentive to install solar

reduction window film to lower their cooling bills and improve occupant comfort.  Customers

can receive rebates for installing qualified solar reduction window film in non‐residential facilities

based on the Solar Heat Gain Coefficient (“SHGC”) of window film installed.

Program Marketing:  

The Company uses a number of marketing activities to promote its approved DSM Programs,

including but not limited to: direct mail, bill inserts, web content, social media, and outreach events.

Because these programs are implemented using a contractor network, customers will enroll in the

program by contacting a participating contractor.  The Company will utilize the contractor network

to market the programs to customers as well.   
AP ‐ 45

Appendix 3N – Approved Programs Non‐Coincidental Peak Savings

(kW) (System‐Level)

Note: Residential Bundle Program includes Residential Home Energy Check‐Up Program, Residential Duct & Sealing Program, Residential Heat Pump Tune Up Pr

Pump Upgrade Program.

Programs 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 

Air Conditioner Cycling Program 104,928 122,243 139,558 156,873 174,188 191,503 198,896 201,519 201,204 196,939 192,365 193,407 194,43

Residential Low Income Program 3,737 3,910 3,910 3,910 3,910 3,910 3,910 3,910 3,910 3,910 3,871 3,335 2,04Residential Lighting 39,958 39,958 38,580 39,958 39,958 38,329 27,798 20,104                   ‐ 9,578                          ‐                          ‐                          ‐                          

Commercial Lighting 14,873 14,873 14,873 14,873 14,873 14,873 13,460 10,010                   ‐ 3,466                          ‐                          ‐                          ‐                          

Commercial Heating Vent and AC 673 673 673 673 673 673 673 673 673 673 673 591 44

Non‐Residential Energy Audit Program 5,447 11,175 17,482 19,785 20,125 21,323 21,937 23,059 23,235 23,410 23,586 23,761 23,93

Non‐Residential Duct & Sealing Program 5,750 10,280 15,390 17,720 17,995 18,274 18,471 18,604 18,733 18,858 18,981 19,102 19,22

Non‐Residential Distributed Generation Program 21,125 20,509 15,844 17,956 20,069 22,181 23,237 24,294 25,350 26,406 27,462 28,519 29,57

Residential Bundle Program 21,740 41,104 61,675 87,433 94,350 104,723 117,144 118,302 119,424 120,615 121,610 122,679 123,73

Residential Home Energy Check‐Up Program 624 1,053 1,507 1,709 1,736 1,764 1,784 1,798 1,812 1,917 1,840 1,854 1,86

Residential Duct & Sealing Program 1,141 2,994 5,059 6,018 6,130 6,243 6,327 6,387 6,446 6,505 6,564 6,622 6,67

Residential Heat Pump Tune Up Program 9,035 15,908 23,145 32,611 35,373 41,480 49,871 50,327 50,771 51,210 51,649 52,088 52,51

Residential Heat Pump Upgrade Program 10,941 21,149 31,964 47,094 51,112 55,237 59,163 59,790 60,394 60,983 61,556 62,115 62,66

Non‐Residential Window Film Program 395 2,766 7,244 12,954 19,173 20,983 21,073 21,226 21,422 21,615 21,804 21,991 22,17

Non‐Residential Heating Vent 1,299 5,780 11,701 18,394 25,190 28,823 29,179 29,458 29,733 30,003 30,268 30,530 30,79

Non‐Residential Lighting 2,567 8,546 14,649 20,841 28,038 28,235 28,468 28,752 29,026 29,294 29,557 29,816 30,07
AP ‐ 46

Appendix 3O – Approved Programs Coincidental Peak Savings

(kW) (System‐Level)

Note: Residential Bundle Program includes Residential Home Energy Check‐Up Program, Residential Duct & Sealing Program, Residential Heat Pump Tune Up Pr

Pump Upgrade Program.

Programs 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 

Air Conditioner Cycling Program 102,042 119,357 136,672 153,987 171,302 188,617 195,893 195,117 193,329 191,943 192,188 193,234 194,261 

Residential Low Income Program 1,503 1,657 1,657 1,657 1,657 1,657 1,657 1,657 1,657 1,657 1,551 1,168 760 Residential Lighting 26,045 26,045 26,045 26,045 26,045 22,329 16,496 10,298                   ‐ 3,122                          ‐                          ‐                          ‐                          

Commercial Lighting 14,873 14,873 14,873 14,873 14,873 14,873 13,452 7,776                   ‐ 1,853                          ‐                          ‐                          ‐                          

Commercial Heating Vent and AC 673 673 673 673 673 673 673 673 673 673 673 586 342 

Non‐Residential Energy Audit Program 4,277 10,493 16,769 19,634 19,973 21,097 21,653 22,879 23,054 23,228 23,402 23,575 23,746 

Non‐Residential Duct & Sealing Program 5,616 10,280 15,390 17,720 17,995 18,274 18,471 18,604 18,733 18,858 18,981 19,102 19,221 

Non‐Residential Distributed Generation Program 20,865 16,812 14,963 17,076 19,188 21,301 22,797 23,854 24,910 25,966 27,022 28,079 29,135 

Residential Bundle Program 10,903 26,276 43,186 52,557 56,822 62,001 64,699 65,342 65,967 66,580 67,182 67,774 68,360 

Residential Home Energy Check‐Up Program 504 966 1,476 1,709 1,736 1,764 1,784 1,798 1,812 1,826 1,840 1,854 1,868 

Residential Duct & Sealing Program 1,046 2,957 5,059 6,018 6,130 6,243 6,327 6,387 6,446 6,505 6,564 6,622 6,679 

Residential Heat Pump Tune Up Program 2,054 4,421 7,025 8,497 9,611 11,555 12,575 12,688 12,799 12,909 13,019 13,128 13,235 

Residential Heat Pump Upgrade Program 7,299 17,932 29,626 36,333 39,345 42,439 44,013 44,469 44,910 45,340 45,759 46,169 46,578 

Non‐Residential Window Film Program 142 2,091 5,903 11,010 16,679 19,266 19,393 19,506 19,687 19,865 20,040 20,212 20,384 

Non‐Residential Heating Vent 556 5,399 11,493 17,781 24,163 27,069 27,392 27,654 27,910 28,163 28,412 28,657 28,902 

Non‐Residential Lighting 737 6,082 12,160 18,342 25,150 28,226 28,443 28,729 29,003 29,272 29,536 29,795 30,051 

Total 188,232 240,039 299,785 351,355 394,521 425,382 431,019 422,087 409,896 406,204 408,985 412,181 415,160 
AP ‐ 47

Appendix 3P – Approved Programs Energy Savings

(MWh) (System‐Level)

Note: Residential Bundle Program includes Residential Home Energy Check‐Up Program, Residential Duct & Sealing Program, Residential Heat Pump Tune Up Pr

Pump Upgrade Program.

Programs 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 

Air Conditioner Cycling Program                       ‐                          ‐                           ‐                            ‐                            ‐                            ‐                             ‐                             ‐                            ‐                               ‐                               ‐                              ‐                               ‐Residential Low Income Program 9,166 9,964 9,964 9,964 9,964 9,964 9,964 9,964 9,964 9,964 9,355 7,031 4,310 

Residential Lighting 276,824 276,824 276,824 276,824 276,824 240,142 177,744 112,436                 ‐ 36,496                          ‐                          ‐                          ‐                          

Commercial Lighting 121,206 121,206 121,513 121,206 121,206 121,206 110,634 65,709                 ‐ 16,403                          ‐                          ‐                          ‐                          

Commercial Heating Vent and AC 3,656 3,656 3,660 3,656 3,656 3,656 3,660 3,656 3,656 3,656 3,660 3,227 1,947 

Non‐Residential Energy Audit Program 20,249 49,652 80,068 95,092 96,733 101,951 104,661 111,075 111,924 112,770 113,616 114,457 115,287 

Non‐Residential Duct & Sealing Program 20,221 37,337 56,261 65,309 66,323 67,351 68,246 68,586 69,060 69,522 70,134 70,422 70,861 

Non‐Residential Distributed Generation Program 98 1 1 7 13 3 7 15 15 11 18 28 42 

Residential Bundle Program 37,655 94,523 157,717 198,020 215,382 237,979 252,399 254,896 257,322 259,701 262,040 264,340 266,615 

Residential Home Energy Check‐Up Program 1,861 3,627 5,584 6,576 6,680 6,786 6,865 6,921 6,975 7,029 7,083 7,137 7,189 

Residential Duct & Sealing Program 1,384 4,094 7,089 8,589 8,748 8,910 9,032 9,118 9,203 9,287 9,371 9,455 9,536 

Residential Heat Pump Tune Up Program 10,694 24,458 39,791 49,906 55,927 66,880 74,413 75,084 75,740 76,393 77,046 77,694 78,329 

Residential Heat Pump Upgrade Program 23,717 62,344 105,252 132,949 144,028 155,404 162,089 163,774 165,404 166,992 168,539 170,055 171,561 

Non‐Residential Window Film Program 673 8,112 23,255 43,714 66,503 77,532 78,076 78,510 79,240 79,956 80,661 81,355 82,047 

Non‐Residential Heating Vent 884 6,762 14,393 22,268 30,259 33,899 34,303 34,631 34,952 35,269 35,580 35,888 36,194 

Non‐Residential Lighting 3,027 20,591 42,047 63,877 87,783 99,716 100,457 101,468 102,439 103,389 104,321 105,238 106,142 

Total 493,658 628,627 785,702 899,935 974,645 993,398 940,150 840,947 721,472 674,238 679,384 681,987 683,444 
AP ‐ 48

Appendix 3Q – Approved Programs Penetrations

(System‐Level)

Note: Residential Bundle Program includes Residential Home Energy Check‐Up Program, Residential Duct & Sealing Program, Residential Heat Pump Tune Up Pr

Pump Upgrade Program.

Programs 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 

Air Conditioner Cycling Program 95,632 112,132 128,632 145,132 161,632 178,132 179,334 180,443 181,511 182,549 183,563 184,549 185,521 

Residential Low Income Program 12,090 12,090 12,090 12,090 12,090 12,090 12,090 12,090 12,090 12,090 10,659 6,539 4,003 

Residential Lighting 7,798,234 7,798,234 7,798,234 7,798,234 7,798,234 5,890,547 4,259,629           ‐ 2,243,150                       ‐                          ‐                          ‐                          ‐                          

Commercial Lighting 2,435 2,435 2,435 2,435 2,435 2,435 2,036                       ‐ 728                       ‐                          ‐                          ‐                          ‐                          

Commercial Heating Vent and AC 127 127 127 127 127 127 127 127 127 127 127 99                           

40 

Non‐Residential Energy Audit Program 1,555 3,015 4,553 4,633 4,715 5,119 5,464 5,506 5,548 5,590 5,631 5,673 5,713 

Non‐Residential Duct & Sealing Program 874 1,462 2,079 2,111 2,144 2,177 2,193 2,209 2,224 2,239 2,253 2,267 2,281 

Non‐Residential Distributed Generation Program 20 13 15 17 19 21 22 23 24 25 26 27 28 

Residential Bundle Program 94,615 180,148 270,237 289,821 327,243 382,121 385,757 389,284 392,751 396,201 399,630 402,999 406,309 

Residential Home Energy Check‐Up Program 4,187 7,230 10,451 10,617 10,785 10,956 11,046 11,134 11,220 11,307 11,394 11,479 11,562 

Residential Duct & Sealing Program 5,711 12,298 19,233 19,591 19,954 20,322 20,520 20,713 20,903 21,093 21,284 21,471 21,653 

Residential Heat Pump Tune Up Program 61,915 114,960 170,821 183,904 214,657 262,694 265,103 267,447 269,759 272,074 274,392 276,666 278,887 

Residential Heat Pump Upgrade Program 22,802 45,660 69,732 75,709 81,847 88,149 89,087 89,991 90,869 91,727 92,561 93,383 94,207 

Non‐Residential Window Film Program 133,086 862,040 2,086,859 3,549,755 5,100,436 5,176,943 5,180,688 5,229,584 5,277,558 5,324,752 5,371,084 5,416,968 5,462,894 

Non‐Residential Heating Vent 261 1,055 1,889 2,739 3,599 3,653 3,689 3,723 3,758 3,791 3,824 3,857 3,890 

Non‐Residential Lighting 687 2,287 3,920 5,577 7,503 7,532 7,611 7,685 7,757 7,828 7,898 7,967 8,034 

Total 8,139,616 8,975,038 10,311,070 11,812,671 13,420,177 11,660,897 10,038,639 8,074,552 5,883,347 5,935,192 5,984,695 6,030,944 6,078,714 
AP ‐ 49

Appendix 3R – Proposed Programs Non‐Coincidental Peak Savings

(kW) (System‐Level)

Programs 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 

Income & Age Qualifying Home Improvement Program ‐ 427 1,274 2,121 2,972 4,084 5,136 5,193 5,247 5,300 5,352 5,403 5,45

Residential Appliance Recycling Program ‐ 876 2,253 3,631 5,121 6,672 7,279 7,357 7,433 7,507 7,579 7,649 7,72

Qualifying Small Business Improvement Program ‐ 5,739 15,569 28,284 43,296 60,100 67,800 68,448 69,081 69,704 70,315 70,919 71,52
AP ‐ 50

Appendix 3S – Proposed Programs Coincidental Peak Savings

(kW) (System‐Level)

Programs 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 

Income & Age Qualifying Home Improvement Program                       ‐                      100 756 1,450 2,147 2,845 3,156 3,189 3,222 3,254 3,286 3,316 3,34

Residential Appliance Recycling Program ‐ 283 1,902 3,462 5,022 6,582 7,279 7,357 7,433 7,507 7,579 7,649 7,720 

Qualifying Small Business Improvement Program ‐ 2,381 15,215 28,284 43,296 60,100 67,800 68,448 69,081 69,704 70,315 70,919 71,520 

Total ‐ 2,765 17,872 33,196 50,465 69,527 78,234 78,994 79,736 80,465 81,180 81,885 82,58
AP ‐ 51

Appendix 3T– Proposed Programs Energy Savings

(MWh) (System‐Level)

Programs 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 

Income & Age Qualifying Home Improvement Program                       ‐                      508 3,100 6,130 9,168 12,213 13,759 13,907 14,051 14,191 14,327 14,461 14,59

Residential Appliance Recycling Program ‐ 1,790 9,941 18,342 26,742 35,143 39,178 39,600 40,009 40,407 40,795 41,175 41,55

Qualifying Small Business Improvement Program ‐ 3,925 21,522 40,409 62,139 86,473 98,515 99,457 100,379 101,284 102,174 103,052 103,92

Total ‐ 6,223 34,563 64,881 98,050 133,829 151,451 152,964 154,438 155,882 157,296 158,688 160,07
AP ‐ 52

Appendix 3U – Proposed Programs Penetrations

(System‐Level)

Programs 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 

Income & Age Qualifying Home Improvement Program                       ‐                   2,110 6,290 10,470 14,670 18,870 19,079 19,280 19,476 19,666 19,852 20,035 20,21

Residential Appliance Recycling Program ‐ 6,564 16,891 27,218 37,545 47,872 48,402 48,912 49,408 49,892 50,363 50,828 51,29

Qualifying Small Business Improvement Program ‐ 976 2,357 3,994 5,838 7,894 7,971 8,046 8,120 8,192 8,263 8,333 8,40

Total ‐ 9,650 25,538 41,682 58,053 74,636 75,452 76,238 77,003 77,751 78,479 79,197 79,91
 

AP ‐ 53

Appendix 3V– Generation Interconnection Projects under Construction

Warren V2‐030 500 3,424 7.8 Dec‐14 VA

Carson ‐ Wake X2‐076 500 3,424 89.1 May‐15 VA

Location Line Capacity

(MVA)

Interconnection Cost

(Million $)

Line Terminal PJM Queue Target Date

Line Voltage

(kV)
 

AP ‐ 54

Appendix 3W – List of Transmission Lines under Construction

Line Terminal

Line

Voltage

(kV)

Line

Capacity

(MVA)

Target Date Location

Roanoke Industrial Park 115kV DP 115 261 Sep‐14 NC

Dooms to Bremo 230kV Transmission Line Rebuild 115 180 Oct‐14 VA

Rebuild Line #551 (Mt Storm ‐ Doubs) 500 4,334 Dec‐14 VA

Ridge Road Sub and Build Double Circuit 115kV Lines 115 261 Apr‐15 VA

Shawboro – Aydlett Tap 230kV Line 230 751 May‐15 NC

Cloverhill to Liberty ‐ New 230kV Line 230 1,047 May‐15 VA

Line #2020 Rebuild Winfall ‐ Elizabeth City 230 1,047 Jun‐15 NC

Convert Line 64 to 230kV and Install 230kV Capacitor Bank at Winfall 230

775 (#2131)  

840(#2126) Jun‐15 NC

Line #22 Rebuild  Kerr Dam ‐ Eatons Ferry 115 262 Jun‐15 VA/NC

2nd 230kV Line Harrisonburg to Endless Caverns 230 1,047 Jun‐15 VA

Line #30 Rebuild (Altivista to Skimmer) 115 239 Jun‐15 VA

Line #17 Uprate Shockoe ‐ Northeast and Terminate Line #17 at Northeast 115 231 Jul‐15 VA

New 115kV DP to Replace Pointon 34.5kV DP ‐ SEC 115 230 Jul‐15 VA

Burton Switching Station and 115 kV Line to Oakwood 115 233 Dec‐15 VA

Rebuild Dooms to Lexington 500 kV Line 500 4,000 Jun‐16 VA

New 230kV Line Dooms to Lexington 230 1,047 Jun‐16 VA

Line #33 Rebuild and Halifax 230kV Ring Bus 115 353 Jun‐16 VA
AP ‐ 55

Appendix 4A –ICF Commodity Pric

Forecasts for DominVirginia Power

June 2014 Forecast
Copyrighted page(s) removed. Copyrighted 

material is not available in Regulations.gov since 

it may not be reproduced without consent of the 

copyright holder. 

Removed pages can be viewed at the USEPA 

Docket Center, Public Reading Room. 

Address: 1301 Constitution Ave, NW 

Room 3334 

Washington, DC 20004 

Telephone: 202-566-1744 

Email: docket-customerservice@epa.gov
AP ‐ 71

Appendix 4B – Delivered Fuel Data

(1) Delivered fuel price for CAPP CSX (12,500, 1% FOB), No. 2 Oil, No. 6 Oil, DOM Zone Delivered Natural Gas are used to represent Coal, Heavy Fuel, Light Fuel respectively.(2) Light fuel oil is used for reliability only at dual‐fuel facilities.

(3) Per definition of § 56‐576 of the Code of Virginia.

(4) Primary Fuel Expenses for Nuclear, Coal, Heavy Fuel Oil, Natural Gas and Renewable are based on North Anna 1, Chesterfield 6, Yorktown 3, Possum Point 6, 

(5) Average of NUGs Fuel Expenses.

(6) Average cost of Market Energy Purchases.

Company Name: Virginia Electric and Powe r Company 

FUEL DATA

(ACTUAL) (PROJECTED)

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 

I. Delivered Fuel Price ($/mmBtu)(1)

a. Nucle ar 0.63 0.68 0.72 0.63 0.62 0.64 0.66 0.67 0.68 0.69 0.70 0.71 0.73 0.75 0.76 b. Coal 3.21 3.15 3.00 2.62 2.70 2.77 2.87 2.93 3.00 3.06 3.11 3.16 3.21 3.28 3.34 c. He avy Fuel Oil 16.04 15.27 14.44 15.11 14.45 13.45 12.76 12.94 13.23 13.56 13.90 14.49 15.11 15.74 16.40 d. Light Fuel Oil(2) 19.70 19.89 20.79 20.86 20.60 19.45 18.80 19.17 19.60 20.07 20.57 21.43 22.33 23.26 24.22 e. Na tural Gas 4.51 3.07 4.11 4.65 4.15 4.37 4.90 5.13 5.34 5.53 5.75 5.97 6.20 6.44 6.71 

f. Renewable(3) 2.13 1.85 2.55 3.18 3.36 3.39 3.18 3.23 3.28 3.34 3.41 3.48 3.56 3.63 3.70 

II. Primary Fuel Expenses (cents/kWh)(4)

a. Nucle ar 0.66 0.71 0.74 0.68 0.65 0.67 0.72 0.73 0.73 0.75 0.76 0.77 0.79 0.81 0.82 b. Coal 3.36 3.22 3.21 3.37 3.44 3.49 3.51 3.56 3.65 3.72 3.78 3.87 3.95 4.03 4.11 c. He avy Fuel Oil 10.69 13.91 14.30 13.18 10.49 13.43 20.87 17.55 17.47 16.78 14.34 15.63 18.94 20.08 20.41 d. Light Fuel Oil(2) 12.92 4.57 17.93 N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A e. Na tural Gas 3.86 2.76 3.45 3.66 3.12 3.23 3.62 3.82 3.95 4.08 4.26 4.43 4.59 4.78 4.99 f. Renewable(3) 3.37 2.95 0.55 4.90 5.49 5.56 4.87 4.94 5.02 5.09 5.19 5.31 5.42 5.53 5.64 g. NUG(5) 3.64 3.02 3.46 3.23 2.83 2.64 2.38 1.88 2.19 3.01 3.17 N/A N/A N/A N/A i. Economy Ene rgy Purchase s(6) 4.62 3.78 4.04 3.06 2.83 3.00 3.25 3.41 3.37 3.43 3.67 3.99 4.16 4.35 4.55 j. Capacity Purchase s ($/kW‐Ye ar) 49.93 20.24 8.42 31.04 48.12 33.32 34.58 44.31 57.15 73.40 94.15 94.46 94.41 94.64 94.65 
AP ‐ 72

Appendix 5A ‐ Tabular Results of Busbar

$/kW‐Year 0% 10% 20% 30% 40% 50% 60% 70% 80% 

CT $67 $161 $255 $348 $442 $536 $630 $724 $818 CC 3x1 $139 $204 $268 $333 $397 $462 $527 $591 $656 Nuclear $1,136 $1,146 $1,157 $1,168 $1,179 $1,190 $1,200 $1,211 $1,222 Fuel Cell $1,040 $1,101 $1,161 $1,222 $1,282 $1,343 $1,404 $1,464 $1,525 Biomass $909 $957 $1,005 $1,054 $1,102 $1,151 $1,199 $1,248 $1,296 Solar ‐ Fixed Tilt $329 $320 $312 $303 N/A N/A N/A N/A N/A 

Solar ‐ Tracking $362 $353 $344 $335 N/A N/A N/A N/A N/A 

Solar ‐ Tag $275 $266 $257 $248 N/A N/A N/A N/A N/A Onshore Wind $647 $652 $658 $663 $668 N/A N/A N/A N/A Offshore Wind $1,324 $1,314 $1,304 $1,295 $1,285 N/A N/A N/A N/A 

IGCC with CCS $1,386 $1,502 $1,617 $1,732 $1,847 $1,962 $2,077 $2,192 $2,307 

SCPC with CCS $754 $878 $1,001 $1,125 $1,248 $1,371 $1,495 $1,618 $1,741 IGCC without CCS $881 $939 $997 $1,055 $1,113 $1,171 $1,228 $1,286 $1,344 

SCPC without CCS $465 $531 $598 $664 $731 $797 $864 $930 $997 

Capacity Factor (%)
AP ‐ 73

Appendix 5B ‐ Busbar Assumptions

(1) Variable cost for Biomass, Solar ‐ Fixed Tilt, Solar ‐ Tracking, Solar Tag, Onshore Wind or Offshore Wind include value for RECs.

Heat Rate

Variable

Cost (1) Fixed Cost Book Life 2014 Real $

MMBtu/MWh $/MWh $/kW‐Year Years $/kW

CT 9.04 107.15 66.85 36 467

CC 3x1 6.65 73.75 138.91 36 833

Nuclear 10.50 12.36 1,135.51 60 8,442

Fuel Cell 8.75 69.18 1,040.03 20 5,699

Biomass 13.00 64.31 908.56 40 5,442

Solar ‐ Fixed Tilt ‐ (10.19) 329.39 25 2,611

Solar ‐ Tracking ‐ (10.19) 362.09 25 2,812

Solar ‐ Tag ‐ (10.19) 274.64 25 2,120

Onshore Wind ‐ 5.87 647.23 25 4,795

Offshore Wind                          ‐ ‐ 1,323.90 20 7,050

IGCC CCS 10.88 131.43 1,386.44 40 10,431

SCPC CCS 11.06 140.80 754.49 55 5,755

IGCC without CCS 8.70 66.13 880.90 40 6,572

SCPC without CCS 8.85 75.90 464.88 55 3,497

Nominal $
 

AP ‐ 74

Appendix 5C – Planned Generation under Development

(1) Commercial Operation Date.

(2) Estimated Commercial Operation Date.

(3) Accounts for line losses.

Company Name: Schedule 15c

UNIT PERFORMANCE DATA

Planned Supply‐Side Resources (MW)

Unit Name Location Unit Type Primary Fuel

Type C.O.D.(2) MW

Summer

MW

Nameplate

Under Development(1)

Offshore Wind Demonstra tion Proje ct VA Inte rmittent Wind 2018 2 11(3)

Gene ric CC 2019 N/A Inte rmedia te / Baseload Na tural Gas‐CC 2019 1,566 1,566

North Anna 3                                                  Mine ral, VA Baseload Nucle ar 2028 1,453 1,453

Solar Tag 2017 N/A Inte rmittent Solar 2017 2 4

Solar Tag 2020 N/A Inte rmittent Solar 2020 13 35

Solar 2017                                                        N/A Inte rmittent Solar 2017 15 40

Solar 2018 N/A Inte rmittent Solar 2018 15 40

Solar 2019 N/A Inte rmittent Solar 2019 15 40

Solar 2020 N/A Inte rmittent Solar 2020 15 40

Solar 2021 N/A Inte rmittent Solar 2021 15 40

Solar 2022 N/A Inte rmittent Solar 2022 15 40

Solar 2023 N/A Inte rmittent Solar 2023 15 40

Solar 2024 N/A Inte rmittent Solar 2024 15 40

Solar 2025 N/A Inte rmittent Solar 2025 15 40

Solar 2026 N/A Inte rmittent Solar 2026 15 40

Solar 2027 N/A Inte rmittent Solar 2027 15 40

Solar 2028 N/A Inte rmittent Solar 2028 15 40

Solar 2029 N/A Inte rmittent Solar 2029 15 40

Wind 1: 2022 N/A Inte rmittent Wind 2022 16 120

Wind 2: 2023 N/A Inte rmittent Wind 2023 10 81

Wind 3: 2024 N/A Inte rmittent Wind 2024 6 46

Virginia Electric and Powe r Company
 

AP ‐ 75

Appendix 5D – Standard DSM Test Descriptions

Participant Test

The Participant test is the measure of the quantifiable benefits and costs to program participants due

to enrollment in a program.  This test indicates whether the program or measure is economically

attractive to the customer enrolled in the program.  Benefits include the participant’s retail bill

savings over time plus any incentives offered by the utility, while costs include only the participant’s

costs.  A result of 1.0 or higher indicates that a program is beneficial for the participant.

Utility Cost Test

The Utility Cost test compares the cost to the utility to implement a program to the cost that is

expected to be avoided as a result of the program implementation.  The Utility Cost test measures

the net costs and benefits of a DSM program as a resource option, based on the costs and benefits

incurred by the utility including incentive costs and excluding any net costs incurred by the

participant.  The Utility Cost test ignores participant costs, meaning that a measure could pass the

Utility Cost test, but may not be cost‐effective from a more comprehensive perspective.  A result of

1.0 or higher indicates that a program is beneficial for the utility.

Total Resource Cost Test

The TRC test compares the total costs and benefits to the utility and participants, relative to the costs

to the utility and participants.  It can also be viewed as a combination of the Participant and Utility

Cost tests, measuring the impacts to the utility and all program participants as if they were treated

as one group.  Additionally, this test considers customer incentives as a pass‐through benefit to

customers and, therefore, does not include customer incentives.  If a program passes the TRC test,

then it is a viable program absent any equity issues associated with non‐participants.  A result of 1.0

or higher indicates that a program is beneficial for both participants and the utility.

Ratepayer Impact Measure Test

The RIM test considers equity issues related to programs.  This test determines the impact the DSM

program will have on non‐participants and measures what happens to customer bills or rates due to

changes in utility revenues and operating costs attributed to the program.  A score on the RIM test of

greater than 1.0 indicates the program is beneficial for both participants and non‐participants,

because it should have the effect of lowering bills or rates even for customers not participating in the

program.  Conversely, a score on the RIM test of less than 1.0 indicates the program is not as

beneficial because the costs to implement the program exceed the benefits shared by all customers,

including non‐participants.   
AP ‐ 76

Appendix 5E – DSM Programs Energy Savings

(MWh)

(System‐Level)

(1) The Program types have been categorized by the Virginia definitions of peak shaving, energy efficiency, and demand response.

(2) Implementation date.

(3) State expected life of facility or duration of purchase contract. The Company used Program Life (Years).

(4) The kWs reflected as of 2029.(5) Reductions available during on‐peak hours.

(6) Residential Bundle is comprised of the Residential Home Energy Check‐Up Program, Residential Duct Testing & Sealing Program, Residential Heat Pump Tune

Heat Pump Upgrade Program.

Company Name: Virginia Electric & Power Company 

Energy Efficiency/Energy Efficiency‐ Demand Response/Peak Shaving/Demand Side Management (MWh)

Program Type (1) Program Name Date (2) Life/ Duration (3) Size (kW) (4) 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 

Peak Shaving Air Conditioner Cycling Program 2010 2029 197,317                ‐                ‐ ‐               ‐                ‐                   ‐                   ‐ ‐ ‐ ‐                   ‐ ‐ ‐ ‐ 

Sub‐total 197,317                ‐                ‐ ‐               ‐                ‐                   ‐                   ‐ ‐ ‐ ‐                   ‐ ‐ ‐ ‐ Energy Efficiency ‐ Demand Response Non‐Residential Distributed Generation Program 2010 2029 32,304 609

                ‐               ‐

98 1 1 1 7 13 3 7 15 15 11 18 28 

Standby Generation & Curtailable Service (Pricing Tariffs) (5) 1987 2029 5 308 355 227 227 227 227 227 227 227 227 227 227 227 227 227 

Sub‐total 32,309 917 355 227 325 228 228 234 240 230 234 242 242 238 245 255 

Energy Efficiency Residential Low Income Program 2010 2028 ‐ 2,831 4,053 5,300 9,166 9,964 9,964 9,964 9,964 9,964 9,964 9,964 9,964 9,964 9,355 7,03

Residential Lighting Program 2010 2022 ‐ 228,892 228,892 228,892 276,824 276,824 276,824 276,824 276,824 240,142 177,744 112,436 36,496                      ‐ ‐                     

               

Commercial Lighting Program 2010 2022 ‐ 51,149 72,620 72,620 121,206 121,206 121,513 121,206 121,206 121,206 110,634 65,709               ‐ 16,403                      ‐                     

               

Commercial HVAC Program 2010 2027 ‐ 5,113 5,936 5,936 3,656 3,656 3,660 3,656 3,656 3,656 3,660 3,656 3,656 3,656 3,660 3,22Non‐Residential Energy Audit Program 2010 2029 24,250 ‐ 29 3,613 20,249 49,652 80,068 95,092 96,733 101,951 104,661 111,075 111,924 112,770 113,616 114,4

Non‐Residential Duct & Sealing Program 2012 2029 19,575 ‐ 70 1,659 20,221 37,337 56,261 65,309 66,323 67,351 68,246 68,586 69,060 69,522 70,134 70,42Residential Bundle Program 6) 2010 2029 70,090 ‐ 526 11,359 37,655 94,523 157,717 198,020 215,382 237,979 252,399 254,896 257,322 259,701 262,040 264,3

Residential Home Energy Check‐Up Program 2012 2029 1,908 ‐ 20 945 1,861 3,627 5,584 6,576 6,680 6,786 6,865 6,921 6,975 7,029 7,083 7,13

Residential Duct & Sea ing Program 2012 2029 6,847 ‐ 8 105 1,384 4,094 7,089 8,589 8,748 8,910 9,032 9,118 9,203 9,287 9,371 9,45

Residential Heat Pump Tune Up Program 2012 2029 13,548 ‐ 328 4,474 10,694 24,458 39,791 49,906 55,927 66,880 74,413 75,084 75,740 76,393 77,046 77,69

Residential Heat Pump Upgrade Program 2012 2029 47,788 ‐ 170 5,835 23,717 62,344 105,252 132,949 144,028 155,404 162,089 163,774 165,404 166,992 168,539 170,0

Non‐Residential Solar Window Film Program 2014 2029 20,896                ‐                ‐ ‐               673 8,112 23,255 43,714 66,503 77,532 78,076 78,510 79,240 79,956 80,661 81,35

Non‐Residential Lighting Systems & Controls Program 2014 2029 30,814                ‐                ‐ ‐               3,027 20,591 42,047 63,877 87,783 99,716 100,457 101,468 102,439 103,389 104 321 105,2

Non‐Residential Heating & Cooling Efficiency Program 2014 2029 29,629                ‐                ‐ ‐               884 6,762 14,393 22,268 30,259 33,899 34,303 34,631 34,952 35,269 35,580 35,88

Voltage Conservation Program 2014 2029 ‐ 5,923 25,195 21,862 35,104 40,757 40,757 87,824 342,777 660,151 977,526 1,294,900 1,612,275 1,919,246 2,064,390 1,916,3

Non‐Residential Custom Incentive Program 2014 2029 73,589              ‐              ‐ ‐             ‐              ‐                 23,845 73,387 136,539 200,562 264,585 271,115 273,425 275,736 278,050 280,3

Residential Appliance Recycling 2014 2029 7,928              ‐              ‐ ‐             ‐              1,790 9,941 18,342 26,742 35,143 39,178 39,600 40,009 40,407 40,795 41,17

Non Residential Small Business Audit 2014 2029 73,310              ‐              ‐ ‐             ‐              3,925 21,522 40,409 62,139 86,473 98,515 99,457 100,379 101,284 102,174 103,0

Residential Low Income Program 2014 2029 3,437                ‐                ‐ ‐               ‐                508 3,100 6,130 9,168 12,213 13,759 13,907 14,051 14,191 14,327 14,46

Sub‐total 353,518 293,908 337,321 351,241 528,665 0 675,607 884,868 1,126,020 1,551,997 1,987,937 2,333,705 2,559,911 2,761,594 3,025,090 3,179,102 3,037,3

Total Demand Side Management 583,144 294,825 337,676 351,468 528,989 0 675,835 885,095 1,126,253 1,552,237 1,988,167 2,333,939 2,560,153 2,761,836 3,025,328 3,179,347 3,037,6

ACTUAL ‐ MWh (PROJECTED ‐ MWh)
 

AP ‐ 77

Appendix 5F – Description of Future DSM Programs

Voltage Conservation

Target Class:     All Classes

NC Program Type: Energy Efficiency

VA Program Type: Energy Efficiency

NC Duration:    2016 – 2038

VA Duration:    2009 – 2038

Program Description:  

Since 2009, the Company began a voltage conservation demonstration in areas of Virginia.  This

program involves managing the voltage on the distribution circuits adjusting the load tap changing

transformers and the circuit voltage regulators during off‐peak load conditions, while maintaining

the minimum voltage levels for customers at the end of the circuit.  The objective of this program is

to conserve energy by reducing voltage for residential, commercial and industrial customers served

within the allowable band of 114 to 126 volts at the customer meter (for normal 120‐volt service)

during off‐peak hours.   

Non‐Residential Custom Incentive Program

Target Class:     Non‐Residential

NC Program Type:   Energy Efficiency

VA Program Type:   Energy Efficiency  

NC Duration:     2016 – 2038

VA Duration:     2015 – 2038  

Program Description:  

This Program will support non‐residential customers in identifying and implementing site‐specific

and unique cost‐effective retrofit and new construction energy efficiency opportunities through

measures not addressed by other offerings.  Calculated incentives will be paid based on measures

implemented or equipment installed.   

Income and Age Qualifying Home Improvement Program

Target Class:     Residential  

NC Program Type:   Energy Efficiency

VA Program Type:   Energy Efficiency  

NC Duration:     2016 – 2038

VA Duration:     2015 – 2038  

Program Description:  

This Program provides income and age‐qualifying residential customers with energy assessments

and direct install measures at no cost to the customer. 
 

AP ‐ 78

Appendix 5F Cont. – Description of Future DSM Programs

Residential Appliance Recycling Program

Target Class:     Residential  

NC Program Type: Energy Efficiency

VA Program Type: Energy Efficiency  

NC Duration:     2016 – 2038

VA Duration:     2015 – 2038  

Program Description:  

This program provides incentives to residential customers to recycle specific types of qualifying

appliances.  Appliance pick‐up and proper recycling services are included.  

Qualifying Small Business Improvement Program

Target Class:     Non‐Residential  

NC Program Type: Energy Efficiency

VA Program Type: Energy Efficiency  

NC Duration:     2016 – 2038

VA Duration:     2015 – 2038  

Program Description:  

This program provides low‐cost energy assessments, direct install measures and incentives for

energy efficiency improvements to small businesses meeting certain size and need‐based

requirements.
AP ‐ 79

Appendix 5G – Future Programs Non‐Coincidental Peak Savings

(kW) (System‐Level)

Programs 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 

Voltage Conservation Program 6,860 7,965 7,690 17,162 66,984 129,004 184,437 253,044 315,064 375,051 389,504 374,488 374,48

Non‐Residential Custom Incentive                    ‐ ‐ 7,593 23,369 43,479 63,867 84,254 86,334 87,069 87,805 88,542 89,270 89,98
AP ‐ 80

Appendix 5H – Future Programs Coincidental Peak Savings

(kW) (System‐Level)

Programs 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 

Voltage Conservation Program                       ‐                          ‐                           ‐                            ‐                            ‐                            ‐                             ‐                             ‐                            ‐                               ‐                               ‐                              ‐                               ‐Non‐Residential Custom Incentive                    ‐ ‐ 6,066 18,669 34,735 51,022 67,310 68,971 69,559 70,147 70,735 71,317 71,889 

Total                    ‐ ‐ 6,066 18,669 34,735 51,022 67,310 68,971 69,559 70,147 70,735 71,317 71,889 
AP ‐ 81

Appendix 5I – Future Programs Energy Savings

(MWh) (System‐Level)

Programs 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 

Voltage Conservation Program 35,104 40,757 40,757 87,824 342,777 660,151 977,526 1,294,900 1,612,275 1,919,246 2,064,390 1,916,362 1,916,362 

Non‐Residential Custom Incentive                    ‐ ‐ 23,845 73,387 136,539 200,562 264,585 271,115 273,425 275,736 278,050 280,336 282,586 Total 35,104 40,757 64,603 161,211 479,316 860,713 1,242,111 1,566,015 1,885,699 2,194,982 2,342,440 2,196,698 2,198,949 
AP ‐ 82

Appendix 5J – Future Programs Penetrations

(System‐Level)

Programs 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 

Voltage Conservation Program 77,273 77,273 77,273 195,045 666,131 1,137,217 1,608,304 2,079,390 2,550,476 2,903,791 2,946,240 2,946,240 2,946,240 

Non‐Residential Custom Incentive                    ‐ ‐ 219 674 1,254 1,842 2,430 2,490 2,511 2,532 2,554 2,575 2,595 

Total 77,273 77,273 77,492 195,719 667,385 1,139,059 1,610,734 2,081,880 2,552,987 2,906,323 2,948,793 2,948,814 2,948,835 
 

AP ‐ 83

Appendix 5K – Planned Generation Interconnection Projects  

*Subject to change based on receipt of applicable regulatory approval(s).

* North Anna – Ladysmith Q‐65 500 4,300 48 Apr‐24 VA

Location Target

Date

Interconnection Cost

(Million $)

Line

Capacity

Line Terminal PJM Queue Line Voltage

(kV)
 

AP ‐ 84

Appendix 5L – List of Planned Transmission Lines

Note: Asterisk reflects planned transmission addition subject to change based on inclusion in future PJM RTEP and/or receipt of applicable

regulatory approval(s).

Line Terminal Line Voltage

(kV)

Line Capacity

(MVA) Target Date Location

Roanoke Industrial Park 115kV DP 115 261 Sep‐14 NC

Dooms to Bremo 230kV Transmission Line Rebuild 115 180 Oct‐14 VA

Cannon Branch to Cloverhill ‐ New 230kV Line 230 1,047 Dec‐14 VA

Rebuild Line #551 (Mt Storm ‐ Doubs) 500 4,334 Dec‐14 VA

Ridge Road Sub and Build Double Circuit 115kV Lines 115 261 Apr‐15 VA

Uprate Line 2022 ‐ Possum Point to Dumfries Substation 230 797 May‐15 VA

Line #262 Rebuild (Yadkin ‐ Chesapeake EC) 230 1,047 May‐15 VA

Shawboro – Aydlett Tap 230kV Line 230 751 May‐15 NC

Cloverhill to Liberty ‐ New 230kV Line 230 1,047 May‐15 VA

Yadkin ‐ Chesapeake increase 115 kV Capacity 115 398 Jun‐15 VA

Convert Line 64 to 230kV and Install 230kV Capacitor Bank at Winfall 230

775 (#2131)       

840(#2126) Jun‐15 NC

Line 32 Rebuild 115 240 Jun‐15 VA

Line #2020 Rebuild Winfall ‐ Elizabeth City 230 1,047 Jun‐15 NC

Line #22 Rebuild  Kerr Dam ‐ Eatons Ferry 115 262 Jun‐15 NC/VA

Line #30 Rebuild (Altivista to Skimmer) 115 239 Jun‐15 VA

2nd 230kV Line Harrisonburg to Endless Caverns 230 1,047 Jun‐15 VA

Line #17 Uprate Shockoe ‐ Northeast and Terminate Line #17 at Northeast 115 231 Jul‐15 VA

Line #222 Uprate from Northwest to Southwest 230 706 Jul‐15 VA

New 115kV DP to Replace Pointon 34.5kV DP ‐ SEC 115 230 Jul‐15 VA

Line #201 Rebuild 230 1,200 Nov‐15 VA

Burton Switching Station and 115 kV Line to Oakwood 115 233 Dec‐15 VA

Surry ‐ Skiffes Creek 500 kV Line 500 4,325 Apr‐16 VA

Skiffes Creek ‐ Whealton 230 kV Line 230 1,047 Apr‐16 VA

Line #2090 Uprate 230 1,195 May‐16 VA

Line #2032 Uprate (Elmont ‐ Four Rivers) 230 1,195 May‐16 VA

Loudoun – Pleasant View Line #558 Rebuild 500 4,000 May‐16 VA

Line #2104 Reconductor and Upgrade 230 1,047 May‐16 VA

Rebuild Line #2027 (Bremo ‐ Midlothian) 230 1,047 May‐16 VA

230kV Line Extension to new Pacific Substation 230 1,047 May‐16 VA

Line #11 ‐ Rebuild or Reconductor from Gordonsville to Somerset 115 353 May‐16 VA

Rebuild Dooms to Lexington 500 kV Line 500 4,000 Jun‐16 VA

Line #33 Rebuild and Halifax 230kV Ring Bus 115 353 Jun‐16 VA

Line #22 Rebuild Carolina ‐ Eatons Ferry 115 262 Jun‐16 NC

Line #54 Reconductor   Carolina ‐ Woodland 115 306 Jun‐16 NC

New 230kV Line Dooms to Lexington 230 1,047 Jun‐16 VA

230kV Line Extension to new Haymarket Substation 230 1,047 May‐17 VA

*Network Line 2086 from Warrenton 230 1,047 May‐17 VA

*Idylwood to Scotts Run – New 230kV Line and Scotts Run Substation 230 1,047 May‐17 VA

Line #69 Uprate Reams DP to Purdy 115 300 Jun‐17 VA

Line #47 Rebuild 115 353 May‐18 VA

* Reconfigure Line #4 Bremo to Cartersville 115 89 May‐18 VA

Line #553 (Cunningham to Elmont) Rebuild and Uprate 500 4,000 Jun‐18 VA

Rebuild Mt Storm ‐Valley 500 kV Line 500 4,000 Jun‐21 VA

Rebuild Dooms to Valley 500 kV Line 500 4,000 Dec‐21 VA
AP ‐ 85

Appendix 6A – Renewable Resources

(1) Per definition of § 56‐576 of the Code of Virginia.

(2) Commercial Operation Date.(3) Company built, purchased or converted.

(4) Expected life of facility or duration of purchase contract.

(5) Net Summer Capacity for Biomass and Hydro, Nameplate for Solar and Wind.

(6) Dual fired coal & biomass reaching 61 MW in 2021.

Company Name:RENEWABLE RESOURCE GENERATION (GWh)

(ACTUAL) (PROJECTED)

Resource Type(1) Unit Name C.O.D.(2) Build/Purchase/ Convert(3) Life/ Duration(4) Size MW(5) 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 

Hydro

Cushaw Hydro Jan‐30 Build 60 2 5 9 14 15 15 15 15 15 15 15 15 15 15 1

Gaston Hydro Feb‐63 Build 60 220 199 175 301 292 292 292 292 292 292 292 292 292 292 29

North Anna Hydro Dec‐87 Build 60 1 2 3 1 3 3 3 3 3 3 3 3 3 3 

Roanoke Rapids Hydro Sep‐55 Build 60 98 185 159 300 292 292 292 292 292 292 292 292 292 292 29

Sub‐total 321 391 345 616 601 601 601 601 601 601 601 601 601 601 60

Solar

Solar Partnership Program 2013‐2016 Build 20 13               ‐ ‐               ‐ 1 9 16 16 16 16 16 16 16 16 1

Existing Solar NC NUGs with PPAs 2014 Purchase 15 100               ‐ ‐               ‐ 188 187 187 185 184 183 183 181 181 180 17

Future Solar NC Nugs 2015‐2016 Purchase 15 100               ‐ ‐               ‐               ‐ 94 188 187 186 185 184 183 182 181 18

Sub‐total 213               ‐ ‐               ‐ 188 281 375 372 370 368 367 364 363 361 36

Biomass Unit Name

Pittsylvania Jun‐94 Purchase 60 83 393 341 369 278 102 86 262 343 466 465 414 491 555 60

Virginia City Hybrid Energy Center (6) Apr‐12 Build 60 61               ‐ ‐ 11 130 214 267 321 370 401 476 446 429 463 43

Altavista Feb‐92 Convert 30 51               ‐ ‐ 145 359 417 410 417 408 417 410 417 408 417 41

Southampton Mar‐92 Convert 30 51               ‐ ‐ 56 384 417 418 417 417 417 418 417 417 417 39

Hopewell Jul‐92 Convert 30 51               ‐ ‐ 85 400 392 410 417 417 410 411 410 409 408 40

Covanta Fairfax                                             ‐ Purchase ‐ 63 600 580 553 351          ‐ 197               ‐               ‐               ‐               ‐               ‐               ‐               ‐               

           

Sub‐total 360 1,322 1,148 1,219 1,902 1,739 1,590 1,833 1,955 2,110 2,179 2,102 2,154 2,259 2,25

Total Renewables 894 1,713 1,493 1,835 2,692 2,621 2,566 2,806 2,926 3,079 3,148 3,068 3,118 3,221 3,21

Virginia Electric and Powe r Company 
 

AP ‐ 86

Appendix 6B – Potential Supply‐Side Resources

(1) Estimated Commercial Operation Date.

Company Name: Schedule 15b

UNIT PERFORMANCE DATA

Potential Supply‐Side Resources (MW)

Unit Name Location Unit Type Primary Fuel Type C.O.D.(1) MW

Summer

MW

Nameplate

Gene ric CT 2022 N/A Pe ak Na tural Gas‐Turbine 2022 457 457

Gene ric CT 2023 N/A Pe ak Na tural Gas‐Turbine 2023 457 457

Gene ric CC 2029 N/A Inte rmedia te / Baseload Na tural Gas‐CC 2029 1,566 1,566

Virginia Electric and Powe r Company
AP ‐ 87

***Confidential Information Redacted***

Appendix 6C – Summer Capacity Position

(1) Existing DSM programs are included in the load forecast.

(2) Efficiency programs are not part of the Company s calculation of capacity.

(3) Capacity Sale, Purchase, and Adjustments are used for modeling purposes.

(4) Actual historical data based upon measured and verified EM&V results. Projected values represent modeled DSM firm capacity.

Company Name: 

UTILITY CAPACITY POSITION (MW)

(ACTUAL) (PROJECTED)

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 

Exis ting Capacity

Conventional 16,531 17,140 17,265 17,102 16,445 16,054 16,001 15,995 15,910 15,904 15,901 15,901 15,901 15,901 15,901 15,901 

Renewable 400 400 400 575 581 591 597 603 609 615 618 618 618 618 618 618 

Total Existing Capacity 16,931 17,540 17,665 17,677 17,027 16,645 16,598 16,598 16,519 16,519 16,519 16,519 16,519 16,519 16,519 16,519 Gene ra tion Unde r Construction

Conventional           ‐         ‐        ‐        ‐ 1,337 2,712 2,712 2,712 2,712 2,712 2,712 2,712 2,712 2,712 2,712 2,712 Renewable           ‐         ‐        ‐ 0.2 2 4 4 4 4 4 4 4 4 4 4 4 

Total Planned Construction Capacity           ‐         ‐        ‐ 0.2 1,339 2,716 2,716 2,716 2,716 2,716 2,716 2,716 2,716 2,716 2,716 2,716 Gene ra tion Unde r Development

Conventional           ‐         ‐        ‐        ‐ ‐         ‐           ‐        ‐        1,566 1,566 1,566 1,566 1,566 1,566 1,566 1,566 Renewable           ‐         ‐        ‐        ‐ ‐         ‐           ‐        ‐        ‐        ‐        ‐          ‐        ‐        ‐        ‐        ‐        

Total Planned De velopment Capacity           ‐         ‐        ‐        ‐ ‐         ‐           ‐        ‐        1,566 1,566 1,566 1,566 1,566 1,566 1,566 1,566 Potential (Expe cted) New Capacity

Conventional           ‐         ‐        ‐        ‐ ‐         ‐           ‐        ‐        ‐        ‐        ‐          457 914 914 914 914 

Renewable           ‐         ‐        ‐        ‐ ‐         ‐           ‐        ‐        ‐        ‐        ‐          ‐        ‐        ‐        ‐        ‐        

Total Potential New Capacity           ‐         ‐        ‐        ‐ ‐         ‐           ‐        ‐        ‐        ‐        ‐          457 914 914 914 914 Other (NUG) 1,787 1,787 1,787 1,785 1,741 1,308 702 502 336 292 291 73 73 73 72 72 Unforced Availability           ‐         ‐        ‐        ‐ ‐         ‐           ‐        ‐        ‐        ‐        ‐          ‐        ‐        ‐        ‐        ‐        Net Generation Capacity 18,718 19,327 19,451 19,462 20,107 20,668 20,016 19,815 21,137 21,092 21,092 21,331 21,787 21,787 21,786 21,786 Exis ting DSM Reductions

Demand Response 6755 5 55555555555

Conservation/Efficiency           ‐         ‐        ‐        ‐ ‐         ‐           ‐        ‐        ‐        ‐        ‐          ‐        ‐        ‐        ‐        ‐        

Total Existing DSM Reductions(1) 6755 5 55555555555Approved DSM Reductions

Demand Response(4) 51 83 83 123 136 152 171 190 210 219 219 218 218 219 221 223 Conservation/Efficiency(2)(4) 36 40 47 65 104 148 180 204 215 212 203 192 188 190 191 192 

Total Approved DSM Reductions 87 123 130 188 240 300 351 395 425 431 422 410 406 409 412 415 Future DSM Reductions

Demand Response(4)           ‐          ‐          ‐          ‐           ‐ ‐             ‐          ‐          ‐          ‐          ‐          ‐          ‐          ‐          ‐          ‐          

Conservation/Efficiency(2)           ‐          ‐          ‐          ‐ 3 24 52 85 121 146 148 149 151 152 153 154 

Total Future DSM Reductions           ‐         ‐        ‐        ‐ 3 24 52 85 121 146 148 149 151 152 153 154 Total Demand‐Side Reductions(1) 93 130 135 188 243 324 403 480 546 577 570 559 557 561 565 570 Net Generation & Demand‐side 18,811 19,457 19,586 19,651 20,350 20,992 20,419 20,295 21,683 21,669 21,662 21,890 22,344 22,348 22,352 22,356 Capacity Sale(3) ‐ (900) (600) ‐          ‐          ‐          ‐          ‐          ‐          Capacity Purchase(3) 340 139 91 1 1 1 1 168 433 Capacity Adjustment(3)           ‐          ‐          ‐          ‐          ‐          ‐          ‐          ‐          

‐

Capacity Requirement or

PJM Capacity Obligation 20,346 20,586 20,802 21,312 21,550 22,006 22,007 22,176 22,443 

Net Utility Capacity Position 340 (761) (509) 1 1 1 1 168 433 

Virginia Ele ctric and Powe r Company
AP ‐ 88

Appendix 6D – Construction Forecast

(1) Does not include Construction Work in Progress.

(2) The construction expenditure includes both modeled and budgeted expenditures.

Company Name: Virginia Electric and Powe r Company

CONSTRUCTION COST FORECAST (Thousand Dollars)

(PROJECTED)

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 

I. New Traditional Generating Facilities(3)

a. Cons truction Expenditure (Not AFUDC)(2) 725,130 317,990 773,681 637,753 294,394 71,517 205,321 207,602 40,596 4,446 76,976 727,252 646,2b. AFUDC(1) 4,188 5,079 4,238 3,913 5,899 131 569 466 3 13 152 1,523 3,8c. Annual Total 729,318 323,069 777,919 641,666 300,293 71,649 205,890 208,068 40,599 4,459 77,127 728,775 650,10d. Cumulative Total 729,318 1,052,387 1,830,306 2,471,972 2,772,265 2,843,914 3,049,803 3,257,872 3,298,471 3,302,930 3,380,057 4,108,832 4,758,94

II. New Renewable Generating Facilities

a. Cons truction Expenditure (Not AFUDC)         ‐ 12,804                   ‐                   ‐                   ‐                   ‐                    ‐                     ‐                     ‐                     ‐                    ‐                      ‐                     

                

b. AFUDC(1)                   ‐ ‐                  ‐ 2                   ‐                   ‐                    ‐                     ‐                     ‐                     ‐                    ‐                      ‐                     

                

c. Annual Total         ‐ 12,804                  ‐ 2                   ‐                   ‐                    ‐                     ‐                     ‐                     ‐                    ‐                      ‐                     

                

d. Cumulative Total 12,804 12,804 12,806 12,806 12,806 12,806 12,806 12,806 12,806 12,806 12,806 12,806 12,80

III. Other Facilities

a. Transmission 802,060 919,097 660,929 652,976 723,947 854,702 764,795 711,544 732,891 754,877 777,524 800,849 824,8

b. Dis tribution 624,470 600,343 571,157 583,641 612,037 623,050 623,050 623,050 641,741 660,994 680,823 701,248 722,2c. Ene rgy Conse rvation & DR(3) 12,347 15,199 178,724 178,845 154,463 14,441 14,875 15,321 15,781 16,254 16,742 17,244 17,7d. Othe r                   ‐ ‐                   ‐                   ‐                   ‐                   ‐                    ‐                     ‐                     ‐                     ‐                    ‐                      ‐                     

                

e. AFUDC 27,210 31,914 32,104 25,060 33,086 42,325 41,405 33,840 34,855 35,901 36,978 38,087 39,2f. Annual Total 1,466,087 1,566,554 1,442,914 1,440,523 1,523,533 1,534,518 1,444,125 1,383,755 1,425,268 1,468,026 1,512,066 1,557,428 1,604,1g. Cumulative Total 1,466,087 3,032,640 4,475,554 5,916,077 7,439,610 8,974,127 10,418,252 11,802,007 13,227,275 14,695,300 16,207,367 17,764,795 19,368,9

IV. Total Construction Expenditures

a. Annual 2,208,208 1,889,623 2,220,835 2,082,189 1,823,826 1,606,166 1,650,014 1,591,823 1,465,867 1,472,485 1,589,194 2,286,203 2,254,2

b. Cumulative 2,208,208 4,097,831 6,318,667 8,400,855 10,224,681 11,830,847 13,480,862 15,072,685 16,538,552 18,011,036 19,600,230 21,886,433 24,140,6

V. % of Funds for Total Construction

Provided from External Financing N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 
AP ‐ 89

***Confidential Information Redacted***

Appendix 6E – Capacity Position

(1) Net Seasonal Capability.(2) Includes firm commitments from existing Non‐Utility Generation and estimated solar NUGs.(3) Capacity Sale, Purchase, and Adjustments are used for modeling purposes.

(4) Does not include Cold Reserve Capacity and Behind‐the‐Meter Generation MWs.

(5) Actual historical data based upon measured and verified EM&V results. Projected values represent modeled DSM firm capacity.

(6) Included in the winter capacity forecast.

Company Name:

POWER SUPPLY DATA

(ACTUAL) (PROJECTED)

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 

I. Capability (MW)

1. Summe r

a. Installed Ne t Dependable

Capacity(1) 16,931 17,540 17,665 17,677 18,366 19,361 19,314 19,314 20,801 20,801 20,801 21,257 21,714 21,714 21,714 

b. Positive Inte rchange

Commitments(2) 1,749 1,747 1,747 1,785 1,741 1,308 702 502 336 292 291 73 73 73 72 

c. Capability in Cold Re se rve /

Re se rve Shutdown Sta tus(1)          ‐              ‐               ‐               105 ‐                ‐                 ‐                 ‐                 ‐                ‐              ‐              ‐              ‐              ‐              ‐              

  

d. Demand Response ‐ Existing 6 7 5 5 5 5 5 5 5 5 5 5 5 5 5 e. Demand Response ‐ Approved(5) 51 83 83 123 136 152 171 190 210 219 219 218 218 219 221 

f. Demand Response ‐ Future(5)               ‐              ‐               ‐               ‐ ‐                ‐                 ‐                 ‐                 ‐                ‐              ‐              ‐              ‐              ‐              ‐              

  

g. Capacity Sale(3) ‐                 ‐900 ‐600               ‐              ‐              ‐              ‐              

  

‐ 

h. Capacity Purchase(3) 340 139 91 1 1 1 1 168 

i. Capacity Adjustment(3) ‐                 ‐                ‐              ‐              ‐              ‐              ‐              ‐              

  

j. Total Ne t Summe r Capability(4) 20,341 20,581 20,797 21,307 21,545 22,001 22,002 22,171 

2. Winte r

a. Ins talled Ne t Dependable

Capacity(1)               ‐              ‐               ‐ 18,361 19,133 19,189 20,306 20,243 22,702 22,595 22,595 23,058 23,521 23,521 23,521 

b. Positive Interchange

Commitments(2)               ‐              ‐               ‐ 1,943 1,945 1,367 1,367 441 441 273 228 6 6 6 6 

c. Capability in Cold Re se rve /

Rese rve Shutdown Sta tus(1)            ‐              ‐               ‐               77 ‐                ‐                 ‐                 ‐                 ‐                ‐              ‐              ‐              ‐              ‐              ‐              

  

d. Demand Re sponse(5) 10 16 15 21 17 15 17 19 21 23 24 25 26 27 28 e. Demand Re sponse‐Exis ting(6) 8 6 5 5 5 5 5 5 5 5 5 5 5 5 5 f. Total Ne t Winte r Capability(4)               ‐              ‐               ‐ 20,325 21,094 20,571 21,690 20,702 23,164 22,891 22,847 23,089 23,553 23,554 23,555 

Virginia Electric and Powe r Company