integrated resource plan

Transcription

INTEGRATED RESOURCE PLAN
DOMINION NORTH CAROLINA POWER
AND DOMINION VIRGINIA POWER
Before the North Carolina Utilities Commission and the
Virginia State Corporation Commission
Filed on August 29, 2014
Offshore Wind Development
North Anna Power Station
Brunswick County Power Station
Old Dominion University Solar
Electric transmission
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
2014 Plan ..................................................................................................................................... 4
1.4
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
Supply-Side Resources .......................................................................................................... 22
3.1
3.1.1
Existing Generation ........................................................................................ 22
Figure 3.1.1.1 - Existing Generation Resources ......................................... 22
Figure 3.1.1.2 - Generation Fleet Demographics....................................... 23
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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
Demand-Side Resources ........................................................................................................ 31
3.2
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
Transmission Resources ........................................................................................................ 41
3.3
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
Renewable Energy .................................................................................................................. 45
4.3
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
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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
Commodity Price Assumptions............................................................................................ 48
4.4
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
Future Supply-Side Resources ............................................................................................. 61
5.1
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
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Generation under Development .......................................................................................... 71
5.3
Figure 5.3.1 - Generation under Development ......................................... 73
Emerging and Renewable Energy Technology Development........................................ 73
5.4
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
Future DSM Initiatives .......................................................................................................... 79
5.5
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
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
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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
Alternative Plan NPV Comparison.................................................................................... 102
6.6
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
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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
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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
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LIST OF ACRONYMS
Acronym
Meaning
2013 Plan
2013 Integrated Resource Plan
2014 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
President's 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
Company
CPCN
CS
CSP
Combined Construction Permit and Operating License
Virginia Electric and Power Company d/b/a Dominion North Carolina Power and Dominion Virginia Power
Certificate of Public Convenience and Necessity
Curtailable Service
Concentrating Solar Power
CT
Combustion Turbine
DC
Direct Current
DG
Distributed Generation
DMME
DOE
DOM LSE
DOM Zone
DSI
DSM
EM&V
Department of Mines, Minerals and Energy
Department of Energy
Dominion Load Serving Entity
Dominion Zone within the PJM Interconnection, L.L.C. Regional Transmission Organization
Dry Sorbent Injection
Demand-Side Management
Evaluation, Measurement, and Verification
EPA
Environmental Protection Agency
EPRI
Electric Power Research Institute
ESBWR
EV
FERC
Economic Simplified Boiling Water Reactor
Electric Vehicle
Federal Energy Regulatory Commission
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Acronym
Meaning
Fluor
Fluor Enterprises, Inc.
GEH
GE-Hitachi Nuclear Energy Americas LLC
GHG
Greenhouse Gas
GSP
GWh
Hg
HVAC
IBGS
ICF
IDR
IGCC
Gross State Product
Gigawatt Hour(s)
Mercury
Heating, Ventilating, and Air Conditioning
Inward Battered Guide Structures
ICF International, Inc.
Interval Data Recorder
Integrated-Gasification Combined-Cycle
IRM
Installed Reserve Margin
IRP
Integrated Resource Planning
KBR
kV
kW
kWh
Kellogg, Brown and Root
Kilovolt(s)
Kilowatt(s)
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
NNS
North American Electric Reliability Corporation
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
ix
Acronym
PC
PHEV
Meaning
Pulverized Coal
Plug-in Hybrid Electric Vehicle
PJM
PJM Interconnection, L.L.C.
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
SCPC
SCR
SG
SMR
SNCR
Virginia State Corporation Commission
Super Critical Pulverized Coal
Selective Catalytic Reduction
Standby Generation
Small Modular Reactors
Selective Non-Catalytic Reduction
SO2
Sulfur Dioxide
SPP
Solar Partnership Program
SRP
Stakeholder Review Process
STAP
Strategist
Short-Term Action Plan
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
VOW
VOWDA
VOWTAP
WEA
Virginia City Hybrid Energy Center
Virginia Offshore Wind Coalition
Virginia Offshore Wind Development Authority
Virginia Offshore Wind Technology Advancement Project
Wind Energy Area
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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 costeffective 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
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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
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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 Companyowned 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
xiii
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 costeffective 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.
xiv
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 timeconsuming, 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.
xv
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 GEHitachi 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.
xvi
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).
1
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
Company's 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 MidAtlantic 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.
2
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)
26,000
24,000
22,000
Capacity
Gap
Approved DSM
MW
20,000
18,000
3,570
425
Generation
Under Construction
NUGs
2,716
36
16,000
14,000
12,000
16,519
Existing Generation1
10,000
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.
3
Figure 1.3.2 - Current Company Energy Position (2015 – 2029)
120,000
110,000
100,000
GWh
90,000
Energy
Gap
33,196
Approved DSM
80,000
70,000
Generation Under
Construction
NUGs
693
12,521
60,000
50,000
176
58,647
40,000
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
4
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.
5
Figure 1.4.1(a) - 2014 Base Plan
Supply-side Resources
New
Demand-side
New
Year Conventional
Renew able
Retrofit
Repow er
3
2015
Warren
SLR NUG/SPP
2016
Brunswick
SLR NUG/SPP3
Retire
CEC 1-4
Approved DSM
YT 1-2
Proposed & Future
DSM
2017
2018
2019
Resources1
PP5 – SNCR
583 MW by 2029
YT3 – SNCR
3,063 GWh by 2029
CC
2020
2021
2022
CT
2023
CT
2024
2025
2026
2027
2028
2029
CC
Figure 1.4.1(b) - 2014 Fuel Diversity Plan
New
Demand-side
New
Year Conventional
Renew able
Retrofit
3
2015
Warren
SLR NUG/SPP
2016
Brunswick
SLR NUG/SPP3
2017
OFFD/SLR
CC
CEC 1-4
Approved DSM
YT 1-2
Proposed & Future
PP5 – SNCR
583 MW by 2029
YT3 – SNCR
3,063 GWh by 2029
WND/SLR
TAG/SLR
2021
WND/SLR
CT
WND/SLR
2023
SLR
2024
SLR
2025
SLR
2026
SLR
2027
2028
Resources1
SLR
2020
2022
Retire
DSM
SLR TAG/SLR
2018
2019
Repow er
SLR
North Anna 3
2029
2
SLR
SLR
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.
6
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:
1
•
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;
All references regarding new CT units throughout this document refer to installation of a bank of two CT units.
7
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:
8
Figure 1.4.2 - New Renewable Resources
Resource Name
Year
Type
Nameplate
Capacity
(MW)
Firm
Capacity
(MW)
Plan
Solar NUG
2014
Solar
100
38
A, B
2014
Distributed Solar
0.63
0.18
A, B
A, B
Solar NUG
2015
Solar
50
19
2015
Distributed Solar
7.4
2.1
A, B
Solar NUG
2016
Solar
50
19
A, B
2016
Distributed Solar
4.9
1.4
A, B
Solar
2017
Solar
40
15
B
Solar Tag
Solar
Offshore Wind Demonstration Project
Solar
2017
2018
2018
2019
Solar
Solar
Wind
Solar
4
40
12
40
2
15
2
15
B
B
B
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
1,030.43
323.56
Total
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).
9
Figure 1.4.3(a) - Plan A: Base Plan – Capacity (2015 - 2029)
26,000
24,000
Market Purchases
2,480
22,000
Potential Generation
Generation Under
Development
Proposed and Future DSM
MW
20,000
1,566
158
Approved DSM
18,000
NUGs
425
Generation
Under Construction
2,716
36
16,000
14,000
16,519
12,000
10,000
Figure 1.4.3(b) - Plan B: Fuel Diversity Plan – Capacity (2015 – 2029)
26,000
24,000
457
Market Purchases
22,000
MW
20,000
Generation Under
Development
3,265
158
425
Approved DSM
Generation
Under Construction
18,000
NUGs
2,716
36
16,000
14,000
16,519
12,000
10,000
Note: 1) Accounts for unit retirements and rating changes to existing units in the Plan, and reflects summer ratings.
10
Figure 1.4.4(a) - Plan A: Base Plan – Energy Projection (2015 – 2029)
120,000
110,000
100,000
12,052
Market Purchases
GWh
90,000
9,129
80,000
Generation
Under Development
9,470
2,370
Approved DSM
70,000
693
Generation Under
Construction
NUGs
12,521
60,000
176
50,000
58,647
40,000
Figure 1.4.4(b) - Plan B: Fuel Diversity Plan – Energy Projection (2015 – 2029)
120,000
110,000
8,052
100,000
191
Market Purchases
GWh
90,000
80,000
Generation
Under Development
22,873
2,370
70,000
693
Approved DSM
Generation Under
Construction
NUGs
12,697
60,000
50,000
176
40,000
Note: 1) Accounts for unit retirements and rating changes to existing units in the Plan.
11
58,004
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.
12
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.
13
Figure 1.4.5(a) - Changes between the 2013 and 2014 Base Plans
New
Year Conventional
Renew able
2013
SPP
2014
SPP/SLR NUG
2015
Warren
2016
Brunswick
Demand-side
New
Retrofit
Repow er
Retire
Resources
1
AV, HW, SH –
Approved DSM
Biomass
Proposed & Future
BR3 – Gas
DSM
BR4 – Gas
SPP/EEP
CEC 1-4
SLR NUG/EP&S
YT1, YT2
SLR NUG/SPP
2017
PP5 – SNCR
2018
2019
YT3 – SNCR
CC
2020
2021
CT
2022
CT
2023
CT
2024
2025
2026
2027
CC
2028
2029
CC
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.
14
Figure 1.4.5(b) - Changes between the 2013 and 2014 Fuel Diversity Plans
New
Year Conventional
Renew able
2013
SPP
2014
SPP/SLR NUG
2015
Warren
2016
Brunswick
Approved DSM
Biomass
Proposed & Future
BR3 – Gas
DSM
BR4 – Gas
SLR NUG/SPP
PP5 – SNCR
YT3 – SNCR
SLR
SLR TAG/SLR
2021
SLR
CT
WND /SLR
2023
WND /SLR
2024
WND /SLR
2025
Resources1
AV, HW, SH –
CEC 1-4
OFFD/SLR
2022
Retire
YT1, YT2
2018
CC
Repow er
SLR NUG/EP&S
SLR TAG/SLR
2020
Retrofit
SPP/EEP
2017
2019
Demand-side
New
North Anna 3
SLR
SLR
2026
2027
CT
SLR
2028
CT
SLR
2029
SLR
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.
15
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,
16
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.
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
26,000
24,000
22,000
HISTORY
FORECAST
2014 Actual Winter Peak has
been included.
20,000
18,000
16,000
14,000
SUMMER
PEAK
12,000
WINTER
PEAK
10,000
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
PEAK DEMAND (MW)
2.2
17
Figure 2.2.2 - DOM Zone Annual Energy
130,000
ANNUAL ENERGY (GWh)
120,000
HISTORY
FORECAST
110,000
100,000
90,000
80,000
70,000
60,000
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
50,000
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
Compound
2015
Annual Growth
2029
Rate (%)
2015-2029
DOMINION LSE
TOTAL ENERGY SALES (GWh)
Retail
84,712
101,282
1.3%
82,772
99,011
1.3%
Residential
30,717
37,353
1.4%
Commercial
32,224
42,146
1.9%
-0.6%
Industrial
Public Authorities
8,751
8,050
10,780
11,103
0.2%
301
360
1.3%
1,940
2,271
1.1%
Street and Traffic Lighting
Wholesale (Resale)
SEASONAL PEAK (MW)
Summer
17,670
21,331
1.4%
Winter
14,930
17,568
1.2%
88,174
105,467
1.3%
ENERGY OUTPUT (GWh)
DOMINION ZONE
SEASONAL PEAK (MW)
Summer
20,157
24,333
1.4%
Winter
17,284
20,338
1.2%
100,209
120,064
1.3%
ENERGY OUTPUT (GWh)
Note: All sales and peak load have not been reduced for the impact of DSM.
18
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
28000
26000
HISTORY
FORECAST
PEAK DEMAND (MW)
24000
22000
20000
18000
16000
2013 IRP
2014 IRP
14000
2014 PJM
12000
2013 PJM
2028
2029
2027
2025
2026
2024
2023
2021
2022
2020
2018
2019
2017
2015
2016
2014
2012
2013
2011
2010
2008
2009
2007
2005
2006
2004
2002
2003
2001
1999
2000
10000
Figure 2.2.5 - DOM Zone Annual Energy Comparison
140000
130000
HISTORY
FORECAST
ANNUAL ENERGY (GWh)
120000
110000
100000
90000
80000
2013 IRP
2014 IRP
70000
2014 PJM
60000
2013 PJM
2029
2027
2028
2026
2024
2025
2023
2021
2022
2020
2019
2017
2018
2016
2014
2015
2013
2012
2010
2011
2009
2007
2008
2006
2004
2005
2003
2002
2000
2001
1999
50000
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.
19
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
Compound Annual
2015
2029
Grow th Rate (%)
2015 - 2029
DEMOGRAPHIC:
Customers (000)
Residential
Commercial
Population (000)
2,261
2,638
1.11%
241
276
0.97%
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%
39,983
47,984
1.31%
242
325
2.12%
423
544
1.81%
Income ($)
Per Capita Real disposable
Price Index
Consumer Price (1982-84=100)
VA Gross State Product (GSP)
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.
20
On a long-term basis, the economic outlook for Virginia is positive. Over the next 15 years, real percapita 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.
21
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.
22
Figure 3.1.1.2 - Generation Fleet Demographics
4,500
Renewable
4,000
Oil
TOTAL CAPACITY (MW)
3,500
Pumped Storage
Natural Gas
3,000
Nuclear
Coal
2,500
2,000
1,500
1,000
500
0
<10
10-20
20-30
30-40
40-50
>50
UNIT AGE
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.
23
Figure 3.1.1.3 - 2014 Capacity Resource Mix by Unit Type
Generation Resource Type
Net Summer
Percentage
Capacity (MW)
(%)
Coal
4,964
24.9%
Nuclear
3,349
16.8%
Natural Gas
5,154
25.9%
Pumped Storage
1,802
9.1%
Oil
1,833
9.2%
Renewable
575
2.9%
NUG - Coal
743
3.7%
NUG - Natural Gas Turbine
942
4.7%
NUG - Renewable
63
0.3%
NUG Contracted
1,747
8.8%
Company Owned
17,677
88.8%
Company Owned and NUG Contracted
19,424
97.6%
Purchases
473
Total
19,898
2.4%
100.0%
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.
24
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
25
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 customers' 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.
26
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
Constituent
Hg/HAPS
Key Regulation
Final/Expected
Mercury & Air Toxics Standards
(MATS)
CAIR* - Current & 2015
SO2
July-11
June-10
AIR
Ozone Standard Rev (60-70 ppb)
CAIR* - Current & 2015
WASTE
WATER
June-05
July-11
GHG PSD Rule
May-10
Jan 2015
EGU NSPS (Existing)
EGU NSPS (Modified &
Federal CO2 Program
ASH
CCB's
Water
316b Impingement &
316(b)
Entrainment
Water
May 2012
October-15
CSAPR*
Reconstructed)
Effluent
June-05
SO2 NAAQS
EGU NSPS (New)
CO2
December-11
CSAPR*
Ozone Std Rev (75 ppb)
NOx
Final Rule
June 2015
Jan 2015
Uncertain
December-14
Effluent Discharges
May-14
September-15
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: CrossState 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
27
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
28
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.
29
Figure 3.1.5.1 - Generation under Construction
Forecasted
Unit Name
Location
Primary Fuel
Unit Type
2015
Warren County Power Station
Warren County, VA
Natural Gas
2015
VA
Solar
2016
VA
2016
Brunsw ick, VA
1
COD
Capacity (Net MW)
Summer
Winter
Intermediate/ Baseload
1,337
1,437
Intermittent
8
8
Solar
Intermittent
5
5
Natural Gas
1,375
1,509
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
30
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 supplyside 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
31
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
Voltage Conservation Program
Standby Generator Tariff
Curtailable Service Tariff
Status (VA/NC)
Approved/Approved
Program
Status (VA/NC)
Air Conditioner Cycling Program
Residential Low Income Program
Residential Lighting Program
Commercial Lighting Program
Commercial HVAC Upgrade
Non-Residential Distributed Generation Program
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
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
Note: * Alternative Redesigned Program under consideration.
32
Approved/Approved
Completed/Completed
Closed/Pending Closure
Approved/Rejected
Approved/Approved
Approved/Approved
Approved/Proposed
Proposed/Future
Future/Future
Rejected and Currently Not
Under Consideration
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 customer's 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.
33
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.
34
Figure 3.2.2.1 - Estimated Load Response Data
Tariff
Summer 2013
Number of Estimated MW
Winter 2013
Number of Estimated
Events
Reduction
Events
MW
Standby Generation
13
3
1
2
Curtailable Service
4
3
4
2
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.
35
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 DP2 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.
36
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-carolinapower/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/customerconnection.jsp.
37
Twitter ® and Facebook
State:
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:
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:
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:
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
38
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:
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 NonResidential 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
39
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.
40
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.
41
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/committeesgroups/committees/mrc/20131024/20131024-item-04-irm-study.ashx for PJM’s 2013 Reserve Requirement Study.
42
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.
43
Figure 4.2.2.1 - Peak Load Forecast & Reserve Requirements
PJM Installed
Year
Reserve Margin
Requirements
1
DVP Effective
Total System
Summer
Reserve Margin
2
Peak
MW
Reserve
Total Resource
Requirement
Requirement
MW
MW
3
%
%
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
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 industry's 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.
44
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
Year
Percent of REPS
Annual GWh 1
2012
3% of 2011 DNCP Retail Sales
125
2013
123
2014
129
2015
248
2016
252
2017
256
2018
429
2019
431
2020
434
2021
12.5% of 2020 DNCP Retail Sales
547
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.
45
Figure 4.3.1.2 - North Carolina Solar Requirements
Year
Requirement Target (%)
Annual GWh 1
2010
0.81 2
2011
0.87 2
2012
2.93 2
2013
2014
2.88 3
3.02
2015
5.79
2016
5.89
2017
5.96
2018
8.58
2019
8.62
2020
8.67
2021
8.75
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
Dominion Market
Annual
Share (Est.)
GWh 1
Year
Target
2012
Eliminated
3.19%
2013
Requirement Delayed
3.22%
2014
0.07% of 2013 NC Retail Sales
2.91%
3.02
2015
2.90%
2.90
2016
2.90%
5.89
2017
2.88%
5.96
2018
2.84%
6.01
2019
2.82%
8.62
2020
2.80%
8.67
2021
2.80%
8.75
Note: 1) Annual GWh is an estimate based on the latest forecast sales.
46
Figure 4.3.1.4 - North Carolina Poultry Waste Requirements
Target1
Dominion Market
Annual
(GWh)
Share (Est.)
GWh 1
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
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
Year
Percent of RPS
Annual GWh 1
2010
4% of Base Year Sales
1,733
2011-2015
Average of 4% of Base Year Sales
1,733
2016
3,032
2017-2021
3,032
2022
5,198
2023-2024
5,198
2025
6,497
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,
47
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 Companyowned 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
VA RPS
7,000
NC REPS
Total RPS
6,000
5,000
GWh
4,000
3,000
2,000
1,000
0
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029
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
48
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
$9
$8
Nominal $/MMbtu
$7
$6
$5
$4
$3
$2
$1
$0
DOM Zn 2014
Henry Hub 2014
49
DOM Zn 2013
Henry Hub 2013
Figure 4.4.1.2 - Fuel Price Forecasts - Coal
5.00
4.50
4.00
Nominal $/MMbtu
3.50
3.00
2.50
2.00
1.50
1.00
0.50
0.00
CAPP CSX 12,500 1% FOB (2014)
CAPP CSX 12,500 1% FOB (2013)
Figure 4.4.1.3 - Fuel Price Forecasts - Oil
$30
$25
Nominal $/MMbtu
$20
$15
$10
$5
$0
No 2 NYMEX (2014)
Resid (6 Oil) NYH 1% (2014)
No 2 NYMEX (2013)
Resid (6 Oil) NYH 1% (2013)
50
Figure 4.4.1.4 - Price Forecasts – SO2 & NOX
$60
$50
Nominal $/Ton
$40
$30
$20
$10
$0
CAIR/CSAPR SO2 Group 1 (2014)
CAIR/CSAPR NOX (2014)
CAIR SO2 Group 1 (2013)
CAIR NOX (2013)
Figure 4.4.1.5 - Price Forecasts - CO2
$20
$18
$16
Nominal $/Ton
$14
$12
$10
$8
$6
$4
$2
$0
Carbon (2014)
Carbon (2013)
51
Figure 4.4.1.6 - Power Price Forecasts
$90
$80
Nominal $/MWh
$70
$60
$50
$40
$30
$20
$10
$0
DOM Zn VP On Peak (2014)
DOM Zn VP Off Peak (2014)
DOM Zn VP On Peak (2013)
DOM Zn VP Off Peak (2013)
Figure 4.4.1.7 - PJM RTO Capacity Price Forecasts
$140
$120
Nominal $/KW-Year
$100
$80
$60
$40
$20
$0
RTO Capacity Price (2014)
RTO Capacity Price (2013)
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
52
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
Planning Period Comparison
Average Value (Nominal $)
2013 Plan
2014 Plan
3
Basecase 3
Basecase
Fuel Price
Henry Hub Natural Gas 1 ($/MMbtu)
5.94
6.02
DOM Zone Delivered Natural Gas 1 ($/MMbtu)
6.15
6.01
CAPP CSX: 12,500 1%S FOB ($/MMbtu)
3.29
2.86
No. 2 Oil ($/MMbtu)
21.82
22.43
1% No. 6 Oil ($/Mmbtu)
14.81
15.24
PJM-DOM On-Peak ($/MWh)
67.02
63.26
PJM-DOM Off-Peak ($/MWh)
53.04
54.38
PJM Tier 1 REC Prices ($/MWh)
12.88
18.16
RTO Capacity Prices 2 ($/KW-yr)
73.86
76.20
Electric and REC Prices
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
53
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.
54
Figure 4.4.2.1 - 2014 Plan Scenarios Fuel & Power Price Comparison
2015 - 2029 Average Value (Nominal $ )
Basecase
High Fuel Cost Low Fuel Cost
No CO 2 Cost
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 ($/Mmbtu)
15.24
17.02
14.27
15.24
PJM-DOM On-Peak ($/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
Electric and REC Prices
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 enduse are developed. The difference between the more efficient energy end-use and the standard enduse 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.
55
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 Company's 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
56
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
57
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.
58
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
59
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.
60
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 nondispatchable 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
61
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.
62
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
11
Retrieved from: http://www.nrel.gov/geothermal/.
63
Hydro
Facilities powered by falling water have been operating for over a century. Construction of largescale 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 sitespecific 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
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
64
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.
65
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 cell's
output and efficiency depends on various components, such as its design and materials, the intensity
of the solar radiation hitting the cell, and the cell's 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.
66
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 utilitygrade 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.
67
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
Resource
Dispatchable
Intermediate
Yes
Varies
No
Baseload
Yes
Renewable
Yes
Intermediate/Baseload
Yes
Natural Gas
Yes
Baseload
Yes
Coal
No
Coal (SCPC) w/ CCS
Intermediate
Yes
Coal
Yes
Coal (SCPC) w/o CCS
Baseload
Yes
Coal
Yes
Peak
Yes
Natural Gas
Yes
Yes
Battery/Pumped Storage
Biomass
CC 3x1
CFB
CT
Primary Fuel
Busbar
Unit Type
Resource
Fuel Cell
Baseload
Yes
Natural Gas
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
Intermittent
No
Renewable
Yes
Offshore Wind
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
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.
68
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)
$2,800
$2,600
$2,400
$2,200
$2,000
IGCC w/CCS
$/kW-YEAR
$1,800
SCPC w/CCS
$1,600
IGCC without CCS
FUEL CELL
$1,400
BIOMASS
$1,200
NUCLEAR
$1,000
SCPC without CCS
$800
CT
$600
3X1 CC
$400
$200
$0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
90%
100%
Capacity Factor
Figure 5.2.2 - Non-Dispatchable Levelized Busbar Costs (2019 COD)
$2,800
$2,600
$2,400
$2,200
$2,000
$/kW-YEAR
$1,800
$1,600
$1,400
OFF SHORE WIND
$1,200
$1,000
$800
ON SHORE WIND
$600
SOLAR TRACKING
$400
SOLAR FIXED TILT
$200
SOLAR TAG
$0%
10%
20%
30%
40%
50%
60%
70%
80%
Capacity Factor
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.
69
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
Resource Type
Nameplate
Firm Capacity
Onshore Wind
247
32
Offshore Wind
504
84
Solar PV
520
197
Solar Tag
39
15
12.9
3.7
Figure 5.2.4 identifies some basic capacity and energy differences between dispatchable resources
and non-dispatchable resources.
70
Figure 5.2.4 - Comparison of Resources by Capacity and Annual Energy
Resource Type
Onshore Wind
Nameplate
Firm
Capacity
Capacity
Estimated
(MW)
(MW)
(%)
1,000
130
42%
Estimated
Capacity Factor Annual Energy
(MWh)
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
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.
71
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
72
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
Forecasted
Unit
COD
Location
Primary Fuel
Unit Type
Nameplate
Capacity (Net MW)
Capacity (MW) Summer Winter
2017
Solar
VA
Renewable
Intermittent
40
15
2017
Solar Tag
VA
Renewable
Intermittent
4
2
2
2018
Solar
VA
Renewable
Intermittent
40
15
15
2018
VA
Wind
Intermittent
2019
Combined Cycle
VA
Natural Gas
15
12
2
2
1,566
1,566
1,614
15
2019
Solar
VA
Renewable
Intermittent
40
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
15
2023
Solar
VA
Renewable
Intermittent
40
15
2024
Wind 3
VA
Renewable
Intermittent
46
6
6
2024
Solar
VA
Renewable
Intermittent
40
15
15
15
2025
Solar
VA
Renewable
Intermittent
40
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
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,
73
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.
74
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.
75
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 Haliade™ 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 ("VOWDA") 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
76
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 Motor's first plug-in hybrid
electric vehicle (“PHEV"), 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.
77
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 headend 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 15minute 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
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%
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
78
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
79
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, PUE2009-00081, 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
80
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
Program
2029 MW
2029 GWh
Reduction
Reduction
0.50
0
1,916
0.70
74
289
Participant
Utility
TRC
RIM
N/A
2.39
2.39
2.15
1.87
1.45
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 costeffectiveness 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
Program
2029 MW
2029 GWh
Reduction
Reduction
0.50
0
1,916
1.57
0.76
74
289
2.14
0.54
74
2,206
Participant
Utility
TRC
RIM
N/A
2.39
2.39
2.15
2.03
12.25
2.30
Portfolio Results
5.5.4 REJECTED DSM PROGRAMS
The Company has evaluated a wide variety of DSM programs for both the residential and nonresidential 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.
81
Figure 5.5.4.1- IRP Rejected DSM Programs
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
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
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
82
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
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
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.
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Figure 5.5.5.1- Curtailable Service Program
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
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
3,500,000
3,000,000
2,500,000
MWh
2,000,000
Total All
Total Approved/Proposed
1,500,000
Total Future
1,000,000
500,000
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
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.
84
Figure 5.5.7.2 - DSM Demand Reductions
700,000
600,000
500,000
400,000
kW
Total All
Total Approved/Proposed
300,000
Total Future
200,000
100,000
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
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.
85
Figure 5.5.8.1 - Load Duration Curve 2015
20,000
Without DSM
With DSM
MW
15,000
10,000
5,000
20,000
Without DSM
With DSM
MW
15,000
10,000
5,000
86
25,000
Without DSM
With DSM
MW
20,000
15,000
10,000
5,000
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.
87
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 demandside 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
88
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.
89
Figure 6.2.1 - Current Company Capacity Position (2015 – 2029)
26,000
24,000
22,000
Capacity
Gap
Approved DSM
MW
20,000
18,000
3,570
425
Generation
Under Construction
NUGs
2,716
36
16,000
14,000
12,000
16,519
10,000
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.
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.
90
Figure 6.2.2 - Actual Reserve Margin with Existing Resources and
Generation under Construction
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%
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.
91
Figure 6.2.3 - Current Company Energy Position (2015 – 2029)
120,000
110,000
100,000
GWh
90,000
Energy
Gap
33,196
Approved DSM
80,000
70,000
Generation Under
Construction
NUGs
693
12,521
60,000
50,000
176
58,647
40,000
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.
92
Figure 6.3.1 - Supply-Side Resources Available in Strategist
Dispatchable
Biomass
CC 2x1
CC 3x1
Coal w/CCS
CT
Fuel Cell
IGCC w/CCS
Nuclear (NA3)
Non Dispatchable
Offshore Wind
Onshore Wind
Solar NUG
Solar PV
Solar Tag
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 demandside 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.
93
Figure 6.3.2 - Plan Development Process
94
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).
95
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:
•
•
500 MW (nameplate) of offshore wind;
•
•
1,300 MW (nameplate) of generic solar;
• 39 MW (nameplate) of solar tag.
And selects:
•
•
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).
96
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:
•
•
•
39 MW (nameplate) of solar tag;
•
1,453 MW North Anna 3 nuclear facility;
• 1,300 MW (nameplate) of generic solar.
And selects:
•
•
914 MW of CT capacity.
97
Figure 6.4.1 - Alternative Plans
Year
Plan A
Plan B
Plan C
Base
Fuel Diversity
Renewable
Traditional Renewable/ DSM
2015
App.DSM/ SPP/ SLR
Warren
NUG
2016 Brunswick
2017
2018
2019
SLR NUG/SPP/
Fut.DSM
CC
Traditional Renewable/ DSM Traditional Renewable/ DSM
App.DSM/ SPP/
Warren
SLR NUG
Brunswick
Brunswick
CT
Fut.DSM
SLR2/ SLR TAG
SLR/ OFFD
SLR2/ OFFD
SLR2
CC
SLR/ WND/
CT
SLR NUG
SLR NUG/SPP/
SLR/ SLR TAG
CC
SLR2/ WND/
SLR TAG
SLR TAG
SLR/ WND
SLR2/ WND
SLR/ WND
SLR2/ WND
SLR
CT
CT
SLR2
CT
SLR2/ OFF
SLR
SLR
SLR2
SLR
2028
2029
Fut.DSM
SLR
2020
2021
2022
2023
2024
2025
2026
2027
SLR NUG/SPP/
App.DSM/ SPP/
Warren
NA3
CC
SLR2
SLR
SLR2
SLR
SLR2
SLR
SLR2
Plan D
Plan E
Plan F
Coal
Offshore Wind
EPA GHG Plan
Year
Traditional Renewable/ DSM Traditional Renewable/ DSM Traditional Renewable/ DSM
2015
Warren
2016 Brunswick
2017
2018
2019
App.DSM/ SPP/
SLR NUG
SLR NUG/SPP/
Fut.DSM
App.DSM/ SPP/
Warren
SLR NUG
Brunswick
SLR NUG/SPP/
Fut.DSM
Warren
Brunswick
App.DSM/ SPP/ SLR
NUG
SLR NUG/SPP/
Fut.DSM
SLR2/ SLR TAG
OFFD
CC
CC
2028 COAL CCS
CT
2029
SLR2
SLR2/ WND/
2020
2021
2022
2023
2024 COAL CCS
2025
2026 COAL CCS
2027
SLR2/ OFFD
CC
CT
SLR TAG
SLR2/ WND
CT
CT
SLR2/ WND
SLR2
SLR2
CT
OFF
SLR2
SLR2
SLR2
NA3
SLR2
SLR2
CC
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.
98
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.
99
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
Year
Peak (MW)
Energy (GWh)
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
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.
100
High and Low Transmission and Distribution (“T&D”) Cost Sensitivities (9 - 10)
The Company assumed that a portion of the benefits from the Company's 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
Year
Energy Capacity Coincident Peak
(GWh)
(MW)
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
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.
101
Figure 6.5.3 - Summary of Electric Vehicle Sensitivity
Base Forecast
Year
EV Count
EV Sensitivity
Peak
Energy
(MW)
(GWh)
EV Count
Peak
Energy
(MW)
(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
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).
102
Figure 6.6.1 - Alternative Plan Comparison
Plan A:
Base
Plan B:
Plan C:
Plan D:
Plan E:
Plan F:
Fuel
Renew able
Coal
Offshore
EPA GHG
Wind
Plan
Scenarios and Sensitivities
Diversity
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
Base Case
7.73%
13.11%
12.73%
10.38%
9.52%
-16.61%
-7.35%
-3.63%
-3.05%
-6.20%
-3.71%
High Fuel Cost Scenario
7.93%
14.81%
20.45%
20.55%
18.05%
16.70%
Low Fuel Cost Scenario
-6.25%
2.27%
7.38%
6.58%
4.36%
4.13%
High Load Growth
11.29%
18.99%
24.36%
24.11%
21.66%
20.44%
Low Load Growth
-8.46%
-0.66%
4.71%
4.24%
2.00%
1.64%
High Construction Cost
0.64%
11.52%
17.11%
15.88%
13.59%
13.63%
Low Construction Cost
-0.64%
3.94%
9.11%
9.57%
7.18%
5.41%
High T&D Costs
-0.09%
7.63%
13.01%
12.63%
10.29%
9.42%
Low T&D Costs
0.09%
7.82%
13.20%
12.82%
10.48%
9.61%
Net Metering
-0.24%
7.50%
12.88%
12.49%
10.15%
9.29%
Electric Vehicles
3.12%
10.83%
16.21%
15.85%
13.49%
12.46%
No REC Sales
0.50%
8.57%
14.42%
13.23%
11.15%
10.58%
High REC Sales
-0.64%
6.75%
11.67%
12.09%
9.49%
8.32%
High Cost Combination
24.24%
23.49%
21.05%
20.57%
No CO2 Cost Scenario
8.35%
18.39%
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%
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
103
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.
104
Figure 6.6.1.1 – Portfolio Evaluation Scorecard
Objective
Rate Stability
Basecase Cost
System Cost
Compared to
A. Base (%)
Portfolio
Fuel Supply
GHG Emissions
Concentration
2029
2014 - 2039
Period
Cost Increase Cost increase in
Total System Reliance on Single
CO2
High Cost
in High Fuel
Intensity CO2 Emission Fuel Source (Percent
Cost Scenario Combination (short ton/ Compared to
of Energy from
(%)
Sensitivity (%) 1,000 kWh)
Base (%)
Natural Gas and
Market Purchases)
A. Base
0.0%
7.9%
8.4%
0.43
0.0%
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%
9.5%
6.6%
10.1%
0.37
-14.0%
36.6%
F. EPA GHG Plan (884 limit between
2020 and 2029, and 810 limit after 2030)
48.5%
Figure 6.6.1.2 – Portfolio Evaluation Scorecard with Scores
Portfolio
System Cost
Compared to
A. Base (%)
Cost Increase Cost increase in
CO2
Total System Reliance on Single
in High Fuel
High Cost
Intensity CO2 Emission Fuel Source (Percent
Cost Scenario Combination (short ton/ Compared to
of Energy from
(%)
Base (%)
Natural Gas and
Sensitivity (%) 1,000 kWh)
Market Purchases)
Total
Score
A. Base
1
-1
1
-1
-1
-1
-2
B. Fuel Diversity
0
0
0
0
0
1
1
C. Renewable
-1
1
0
0
0
0
0
D. Coal
0
0
0
0
0
0
0
E. Offshore Wind
0
0
0
0
0
0
0
0
0
-1
1
1
0
1
F. EPA GHG Plan (884 limit between
2020 and 2029, and 810 limit after 2030)
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
105
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.
106
Figure 6.7.1 - Mass Hub Power Prices
$180.00
$160.00
$140.00
$120.00
$/MWh
$100.00
$80.00
$60.00
$40.00
$20.00
$0.00
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 Power Price Massachusetts Hub (Real Time)
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.
107
Figure 6.7.2(a) - Plan A: Base Plan
New
Demand-side
New
Year Conventional
Renew able
Retrofit
Repow er
3
2015
Warren
SLR NUG/SPP
2016
Brunswick
SLR NUG/SPP3
Retire
CEC 1-4
Approved DSM
YT 1-2
Proposed & Future
DSM
2017
2018
2019
Resources1
PP5 – SNCR
583 MW by 2029
YT3 – SNCR
3,063 GWh by 2029
CC
2020
2021
2022
CT
2023
CT
2024
2025
2026
2027
2028
2029
CC
Figure 6.7.2(b) - Plan B: Fuel Diversity Plan
New
Year Conventional
Demand-side
New
Renew able
Retrofit
Repow er
Retire
Resources1
2015
Warren
SLR NUG/SPP3
CEC 1-4
Approved DSM
2016
Brunswick
SLR NUG/SPP3
YT 1-2
Proposed & Future
2017
2018
2019
OFFD/SLR
CC
583 MW by 2029
YT3 – SNCR
3,063 GWh by 2029
SLR
TAG/SLR
2021
WND/SLR
CT
WND/SLR
2023
SLR
2024
SLR
2025
SLR
2026
SLR
2027
2028
PP5 – SNCR
WND/SLR
2020
2022
DSM
SLR TAG/SLR
SLR
North Anna 3 2
2029
SLR
SLR
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.
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.
108
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.
109
Figure 6.7.3(a) - Plan A: Base Plan – Capacity (2015 - 2029)
26,000
24,000
Market Purchases
2,480
22,000
Generation Under
Development
MW
20,000
1,566
158
Approved DSM
18,000
NUGs
425
Generation
Under Construction
2,716
36
16,000
14,000
16,519
12,000
10,000
Figure 6.7.3(b) - Plan B: Fuel Diversity Plan – Capacity (2015 - 2029)
26,000
24,000
457
Market Purchases
22,000
MW
20,000
Generation Under
Development
3,265
158
425
Approved DSM
Generation
Under Construction
18,000
NUGs
2,716
36
16,000
14,000
16,519
12,000
10,000
110
Figure 6.7.4(a) - Plan A: Base Plan – Energy Projection (2015 – 2029)
120,000
110,000
100,000
12,052
Market Purchases
GWh
90,000
9,129
80,000
Generation
Under Development
9,470
2,370
Approved DSM
70,000
693
Generation Under
Construction
NUGs
12,521
60,000
176
50,000
58,647
40,000
Figure 6.7.4(b) - Plan B: Fuel Diversity Plan – Energy Projection (2015 – 2029)
120,000
110,000
8,052
100,000
191
Market Purchases
GWh
90,000
80,000
Generation
Under Development
22,873
2,370
70,000
693
Approved DSM
Generation Under
Construction
NUGs
12,697
60,000
50,000
176
40,000
111
58,004
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.
112
Figure 6.7.5 - Energy by Source (Base Plan)
Figure 6.7.6 - Energy by Source (Fuel Diversity Plan)
113
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
Year
Demand-side
New
Conventional
New
Renewable
2015
Warren
SPP/ SLR NUG
Approved DSM
2016
Brunswick
SPP/ SLR NUG
Proposed & Future
Resources
2017
DSM
2018
583 MW by 2029
2019
3,063 GWh by 2029
CC
2020
2021
2022
CT
2023
CT
2024
2025
2026
2027
2028
2029
CC
Figure 6.8.2 - Additional Resources under Development from the 2014 Fuel Diversity Plan
Year
New
Conventional
New
Renewable
2015
2016
2017
SLR/ SLR TAG
2018
OFFD/SLR
2019
SLR
WND/ SLR/
2020
SLR TAG
2021
WND/ SLR
2022
WND/ SLR
2023
SLR
2024
SLR
2025
SLR
2026
SLR
2027
2028
2029
SLR
North Anna 3
SLR
SLR
114
Demand-side
Resources
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 Carolinaonly 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.
115
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.
116
•
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:
7.2
•
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.
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.
117
Figure 7.2.1 - DSM Projected Savings By 2019
Program
Projected MW
Projected GWh
Reduction
Savings
189
0
2
10
Residential Lighting
22
240
Commercial Lighting
15
121
1
4
Commercial Heating Vent and AC
Approved/Approved
21
1
21
102
Non-Residential Duct & Sealing Program
18
67
62
238
2
7
Residential Duct & Sealing Program
6
9
12
67
42
155
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
60
86
0
660
51
201
Closed/Pending Closure
Approved/Approved
Completed/Completed
Approved/Rejected
Proposed Non-Residential Small Business Audit
Status (VA/NC)
Approved/Proposed
Proposed/Future
Future/Future
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
Forecasted
Capacity (Net MW)
Unit Name
Location
Primary Fuel
Unit Type
Summer
Winter
2015
Warren County, VA
Natural Gas
1,337
1,437
2015
VA
Solar
Intermittent
8
8
2016
VA
Solar
Intermittent
5
5
2016
Brunsw ick, VA
Natural Gas
1,375
1,509
COD1
Note: 1) Commercial Operation Date.
Figure 7.2.3 - Generation under Development1
Forecasted
COD
Unit
Location Primary Fuel
Unit Type
Nameplate Capacity
(MW)
Capacity (Net MW)
Summer
Winter
2017
Solar
VA
Renewable
Intermittent
40
15
2017
Solar Tag
VA
Renewable
Intermittent
4
2
15
2
2018
Solar
VA
Renewable
Intermittent
40
15
15
2018
VA
Wind
Intermittent
12
2
2
2019
Combined Cycle
VA
Natural Gas
1,566
1,566
1,614
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.
118
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
Year
Unit Name
Type
MW
Possum Point 5
SNCR
-
2018
Yorktown 3
SNCR
-
2018
Effective
GENERATION RETIREMENTS:
The Company plans to retire the units listed in Figure 7.2.5.
Figure 7.2.5 – Generation Retirements1
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
2016
Yorktown 2
164
Lowmoor CT
48
2016
Mt. Storm CT
11
2016
Northern Neck CT
47
2017
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.
119
Figure 7.2.6 - Planned Transmission Additions
Line Voltage Line Capacity
Line Terminal
Target Date Location
(kV)
(MVA)
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
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
775 (#2131)
840(#2126)
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
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.
120
•
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
Resource Name
Year
Type
Nameplate
Capacity (MW)
Firm Capacity
(MW)
Plan
Solar NUG
2015
Solar
50
19
A, B
2015
Distributed Solar
7.4
2.1
A, B
Solar NUG
2016
Solar
50
19
A, B
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
2018
Wind
12
2
B
Solar
2019
Solar
40
15
B
248.70
90.09
Total
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
121
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.
122
APPENDIX
AP - 1
Appendix 2A – Total Sales by Customer Class
(DOM LSE) (GWh)
Street
Year
Residential Commercial Industrial
Public
and
Authority
Traffic
Sales
for
Lighting
Total
Resale
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
Note: Historic (2004 – 2013), Projected (2014 – 2029).
AP - 2
Appendix 2B– North Carolina Sales by Customer Class
(DOM LSE) (GWh)
Street
Year
Public
and
Authority
Traffic
Sales
for
Total
Resale
Lighting
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 - 3
Appendix 2C – Virginia Sales by Customer Class
(DOM LSE) (GWh)
Street
Year
Public
and
Authority
Traffic
Sales
for
Lighting
Total
Resale
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 - 4
Appendix 2D – Total Customer Count
(DOM LSE)
Street
Year
Residential Commercial
Industrial
Public
and
Authority
Traffic
Lighting
Sales
for
Total
Resale
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 - 5
Appendix 2E – North Carolina Customer Count
(DOM LSE)
Street
Year
Industrial
Public
and
Authority
Traffic
Lighting
Sales
for
Total
Resale
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 - 6
Appendix 2F – Virginia Customer Count
(DOM LSE)
Street
Year
Industrial
Public
and
Authority
Traffic
Lighting
Sales
for
Total
Resale
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 - 7
Appendix 2G – Summer & Winter Peaks
Company Name:
Schedule 5
Virginia Ele ctric and Powe r Company
POWER SUPPLY DATA
(ACTUAL)
(PROJECTED)
2011
2012
2013
17,635
16,897
16,469
-114
-110
-103
17,521
16,787
4.4%
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
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
20,434
20,679
20,922
-379
-478
-735
-719
344
391
413
406
396
394
397
399
401
404
406
409
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
20,838
21,085
21,331
-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%
1.2%
1.3%
1.2%
1.2%
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
16,855
17,057
17,260
-114
-110
-103
-86
99
156
219
259
303
327
322
308
298
300
302
304
305
307
308
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
17,160
17,364
17,568
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%
1.1%
1.1%
1.2%
1.2%
II. Load (MW)
1. Summe r
(1)
a. Adjuste d Summe r Pe ak
b. Othe r Commitme nts
(2)
c. Total System Summer Peak
d. Pe rce nt Incre ase in Total
Summe r Pe ak
2. Winte r
(1)
a. Adjuste d Winte r Pe ak
b. Othe r Commitme nts
(2)
c. Total System Winter Peak
d. Pe rce nt Incre ase in Total
Winte r Pe ak
(1) Adjusted load from Appendix 2H.
(2) Includes firm Additional Forecast, Conservation Efficiency, and Peak Adjustments from Appendix 2H.
AP - 8
Appendix 2H – Projected Summer & Winter Peak Load & Energy Forecast
Company Name:
Schedule 1
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
2027
2028
2029
17,521
16,787
16,366
17,271
17,999
18,347
18,635
18,898
19,114
19,369
19,615
19,863
20,099
20,336
20,578
20,838
21,085
21,331
150
150
150
150
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-36
-40
-47
-65
-107
-172
-232
-289
-336
-358
-351
-341
-339
-342
-344
-346
-349
-351
-354
-51
-83
-83
-123
-136
-152
-171
-190
-210
-219
-219
-218
-218
-219
-221
-223
-225
-228
-230
-6
-7
-5
-5
-5
-5
-5
-5
-5
-5
-5
-5
-5
-5
-5
-5
-5
-5
-5
-
-
-
294
585
907
951
-55
-55
-55
-55
-55
-55
-55
-55
-55
-55
-55
-55
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
20,434
20,679
20,922
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%
1.3%
1.2%
1.2%
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
17,160
17,364
17,568
150
150
150
150
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-36
-40
-47
-64
-99
-156
-219
-259
-303
-327
-322
-308
-298
-300
-302
-304
-305
-307
-308
-10
-16
-15
-21
-17
-15
-17
-19
-21
-23
-24
-25
-26
-27
-28
-29
-30
-31
-32
-8
-6
-5
-5
-5
-5
-5
-5
-5
-5
-5
-5
-5
-5
-5
-5
-5
-5
-5
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
16,855
17,057
17,260
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%
1.1%
1.2%
1.2%
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
103,022
104,258
105,467
-
-
-
676
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-410
-410
-410
-410
-410
-410
-410
-410
-410
-410
-410
-410
-410
-410
-410
-410
-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
-3,048
-3,055
-3,063
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
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
99,564
100,794
101,994
-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%
1.2%
1.2%
1.2%
1. Utility Pe ak Load (MW)
A. Summe r
1a. Base Fore cast
17,670
1b. Additional Fore cast
NCEMC
2. Conse rvation, Efficie ncy(5)
3. De mand Re sponse
(2)(5)
4. De mand Re sponse -Existing
(2)(3)
5. Pe ak Adjustme nt
6. Adjuste d Load
7. % Incre ase in Adjuste d Load
(from pre vious year)
B. Winte r
1a. Base Fore cast
1b. Additional Fore cast
NCEMC
2. Conse rvation, Efficie ncy(5)
3. De mand Re sponse
(2)(4)
4. De mand Re sponse -Existing
(2)(3)
5. Adjuste d Load
6. % Incre ase in Adjuste d Load
2. Energy (GWh)
A. Base Fore cast
B. Additional Fore cast
NCEMC
Future BTM(6)
C. Conse rvation & De mand Re sponse (5)
D. De mand Re sponse -Existing
(2)(3)
E. Adjusted Ene rgy
F. % Increase in Adjuste d Ene rgy
(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.
AP - 9
Appendix 2I – Required Reserve Margin
Company Name:
Schedule 6
POWER SUPPLY DATA (continued)
(ACTUAL)
2011
2012
(PROJECTED)
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
(1)
I. Reserve Margin
(Including Cold Reserve Capability)
1. Summe r Re se rve Margin
a. MW
(1)
b. Pe rce nt of Load
(3)
c. Actual Re se rve Margin
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
2,260
2,289
2,316
2,617
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%
11.2%
11.2%
11.2%
12.5%
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%
9.1%
7.7%
6.4%
12.5%
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
6,883
6,702
6,501
7,936
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%
41.3%
39.8%
38.1%
46.0%
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
2. Winte r Re se rve Margin
a. MW
(1)
(3)
(1)(2)
I. Reserve Margin
(Excluding Cold Reserve Capability)
1. Summe r Re se rve Margin
a. MW
(1)
(3)
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
2,260
2,289
2,316
2,617
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%
11.2%
11.2%
11.2%
12.5%
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%
9.1%
7.7%
6.4%
12.5%
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
6,883
6,702
6,501
7,936
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%
41.3%
39.8%
38.1%
46.0%
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
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
2. Winte r Re se rve Margin
a. MW
(1)
(3)
(4)
III. Annual Loss-of-Load Hours
(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.
AP - 10
APPENDIX 2J – Economic Assumptions Used In the Sales and Hourly Budget Forecast Model
(Annual Growth Rate)
Year
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
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
9,276
9,344
9,412
Disposable Personal Income, (Mil., 2005$, SAAR)
323,048 336,260 350,735 360,280 367,706 374,761 382,260 390,426 398,616 405,763 412,697 419,783 427,296 435,292 443,636 451,881
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
46.9
47.5
48.0
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 35,828 34,566 34,203
Employment: Total Manufacturing, (Ths., SA)
230
231
234
234
233
231
229
227
224
222
220
217
215
213
212
210
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
720.0
720.4
721.2
Employment: Military personnel, (Ths., SA)
146
144
141
138
135
133
130
128
127
126
125
125
124
123
122
121
Employment: State and local government, (Ths., SA)
541
548
549
550
550
551
552
553
555
556
557
558
558
559
559
560
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 3,049.4 3,071.0 3,090.8
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 57,527 59,062 60,593
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
526.2
535.3
544.3
Gross Product: State & Local Government, (Mil. Chained 2005 $, SAAR) 27,893 27,839 27,526 27,301 27,140 27,033 27,011 27,044 27,057 27,021 26,949 26,828 26,659 26,474 26,294 26,108
CAGR
0.8%
2.3%
1.4%
-1.2%
-0.6%
0.1%
-1.2%
0.2%
1.0%
2.9%
2.0%
-0.44%
Source: Economy.com, March 2014 vintage
Year
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
Population: Total, (Ths.)
8,275
8,357
8,438
8,520
8,602
8,685
8,768
8,851
8,934
9,018
9,101
9,185
9,269
9,353
9,437
9,521
Disposable Personal Income, (Mil., 2005$, SAAR)
286,891 296,511 309,255 321,453 331,231 339,153 346,758 355,022 363,705 372,378 380,994 389,577 398,194 407,047 416,152 425,553
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
43.5
44.1
44.7
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 39,425 38,939 38,467
Employment: Total Manufacturing, (Ths., SA)
233
233
235
238
238
237
235
234
232
231
229
228
226
225
223
221
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
754.8
754.7
755.0
Employment: Military personnel, (Ths., SA)
139
138
137
136
136
135
134
133
132
131
130
130
129
128
127
126
Employment: State and local government, (Ths., SA)
543
551
563
570
574
577
579
581
582
583
584
584
585
585
585
586
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 3,150.2 3,177.1 3,204.5
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 50,682 51,604 52,588
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
546.2
557.6
569.5
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 28,759 28,613 28,479
Source: Economy.com, April 2013 vintage
AP - 11
CAGR
0.9%
2.7%
1.7%
0.0%
-0.3%
0.3%
-0.6%
0.5%
1.3%
2.3%
2.5%
0.25%
Appendix 3A – Existing Generation Units in Service
Company Name:
Schedule 14a
UNIT PERFORMANCE DATA
Existing Supply-Side Resources (MW)
Unit Name
Location
Unit Class
Primary Fuel Type
(1)
MW
MW
Summer
Winter
Altavista
Altavista, VA
Base
Fe b-1992
51
51
Bath County Units 1-6
Warm Springs, VA
Inte rme diate Hydro-Pumpe d Storage
De c-1985
1,802
1,802
Be ar Garde n
Buckingham County, Va
Inte rme diate Natural Gas-CC
May-2011
590
612
Be lle me ade
Richmond, VA
Mar-1991
267
267
Bre mo 3
Bre mo Bluff, VA
Pe ak
Natural Gas
Jun-1950
71
71
Bre mo 4
Bre mo Bluff, VA
Pe ak
Natural Gas
Aug-1958
156
156
Che sape ake 1
Che sape ake , VA
Base
Coal
Jun-1953
111
111
Che sape ake 2
Che sape ake , VA
Base
Coal
De c-1954
111
111
Che sape ake 3
Che sape ake , VA
Base
Coal
Jun-1959
149
149
Che sape ake 4
Che sape ake , VA
Base
Coal
May-1962
207
207
Che sape ake CT 1, 2, 4, 6
Che sape ake , VA
Pe ak
Light Fue l Oil
De c-1967
51
69
Che ste rfie ld 3
Che ste r, VA
Base
Coal
De c-1952
98
99
Che ste rfie ld 4
Che ste r, VA
Base
Coal
Jun-1960
163
163
Che ste rfie ld 5
Che ste r, VA
Base
Coal
Aug-1964
336
340
Che ste rfie ld 6
Che ste r, VA
Base
Coal
De c-1969
670
680
Che ste rfie ld 7
Che ste r, VA
Jun-1990
197
221
Che ste rfie ld 8
Che ste r, VA
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
Inte rme diate Hydro-Conve ntional
Jan-1930
2
3
Darbytown 1
Richmond, VA
Pe ak
Natural Gas-Turbine
May-1990
84
91
Darbytown 2
Richmond, VA
Pe ak
Natural Gas-Turbine
May-1990
84
91
Darbytown 3
Richmond, VA
Pe ak
Natural Gas-Turbine
Apr-1990
84
91
Darbytown 4
Richmond, VA
Pe ak
Natural Gas-Turbine
Apr-1990
84
91
Elizabe th Rive r 1
Che sape ake , VA
Pe ak
Natural Gas-Turbine
Jun-1992
116
116
Elizabe th Rive r 2
Che sape ake , VA
Pe ak
Natural Gas-Turbine
Jun-1992
116
116
Elizabe th Rive r 3
Che sape ake , VA
Pe ak
Natural Gas-Turbine
Jun-1992
116
116
Gaston Hydro
Roanoake Rapids, NC
Inte rme diate Hydro-Conve ntional
Fe b-1963
220
220
Gordonsville 1
Gordonsville , VA
Jun-1994
109
127
Gordonsville 2
Gordonsville , VA
Jun-1994
109
125
Grave l Ne ck 1-2
Surry, VA
Pe ak
Light Fue l Oil
Aug-1970
28
38
Grave l Ne ck 3
Surry, VA
Pe ak
Natural Gas-Turbine
Oct-1989
85
91
Grave l Ne ck 4
Surry, VA
Pe ak
Natural Gas-Turbine
Jul-1989
85
91
Grave l Ne ck 5
Surry, VA
Pe ak
Natural Gas-Turbine
Jul-1989
85
91
Grave l Ne ck 6
Surry, VA
Pe ak
Natural Gas-Turbine
Nov-1989
85
91
Hope we ll
Hope we ll, VA
Base
Re ne wable
Jul-1989
51
51
Ladysmith 1
Woodford, VA
Pe ak
Natural Gas-Turbine
May-2001
151
172
Ladysmith 2
Woodford, VA
Pe ak
Natural Gas-Turbine
May-2001
151
172
Ladysmith 3
Woodford, VA
Pe ak
Natural Gas-Turbine
Jun-2008
161
182
Ladysmith 4
Woodford, VA
Pe ak
Natural Gas-Turbine
Jun-2008
160
182
Ladysmith 5
Woodford, VA
Pe ak
Natural Gas-Turbine
Apr-2009
160
183
Lowmoor CT 1-4
Covington, VA
Pe ak
Light Fue l Oil
Jul-1971
48
64
(1) Commercial Operation Date.
AP - 12
Re ne wable
C.O.D.
Appendix 3A Cont. – Existing Generation Units in Service
Company Name:
Schedule 14a
Existing Supply-Side Resources (MW)
Unit Name
Location
Unit Class
Primary Fuel Type
C.O.D.
(1)
MW
MW
Summer
Winter
Me cklenburg 1
Clarksville , VA
Base
Coal
Nov-1992
69
Me cklenburg 2
Clarksville , VA
Base
Coal
Nov-1992
69
69
69
Mount Storm 1
Mt. Storm, WV
Base
Coal
Se p-1965
554
554
Mount Storm 2
Mt. Storm, WV
Base
Coal
Jul-1966
555
555
Mount Storm 3
Mt. Storm, WV
Base
Coal
De c-1973
520
520
Mount Storm CT
Mt. Storm, WV
Pe ak
Light Fue l Oil
Oct-1967
11
12
North Anna 1
Mineral, VA
Base
Nucle ar
Jun-1978
838
868
North Anna 2
Mineral, VA
Base
Nucle ar
De c-1980
834
863
North Anna Hydro
Mineral, VA
Interme diate
Hydro-Conve ntional
De c-1987
1
1
Northern Ne ck CT 1-4
Warsaw, VA
Pe ak
Light Fue l Oil
Jul-1971
47
63
Pittsylvania
Hurt, VA
Base
Rene wable
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
Heavy Fuel Oil
Jun-1975
786
786
Possum Point 6
Dumfrie s, VA
Interme diate
Natural Gas-CC
612
Possum Point CT 1-6
Dumfrie s, VA
Pe ak
Light Fue l Oil
Remington 1
Re mington, VA
Pe ak
Remington 2
Re mington, VA
Remington 3
Re mington, VA
Remington 4
Jul-2003
559
May-1968
72
96
Natural Gas-Turbine
Jul-2000
153
174
Pe ak
Natural Gas-Turbine
Jul-2000
151
172
Pe ak
Natural Gas-Turbine
Jul-2000
152
172
Re mington, VA
Pe ak
Natural Gas-Turbine
Jul-2000
152
172
Roanoke Rapids Hydro
Roanoake Rapids, NC
Interme diate
Hydro-Conve ntional
Se p-1955
98
98
Rose mary
Roanoke Rapids, NC
Interme diate
Natural Gas-CC
De c-1990
165
183
Solar Partne rship Program
Distributed
Intermitte nt
Rene wable
Jan-2012
0
0
Southampton
Franklin, VA
Base
Rene wable
Mar-1992
51
51
Surry 1
Surry, VA
Base
Nucle ar
De c-1972
838
875
Surry 2
Surry, VA
Base
Nucle ar
May-1973
838
875
Virginia City Hybrid Ene rgy Ce nter
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
Heavy Fuel Oil
De c-1974
790
801
Subtotal - Base
8,567
8,725
Subtotal - Intermediate
4,319
4,502
Subtotal - Peak
4,791
5,129
Subtotal - Intermittent
Total
AP - 13
0
0
17,677
18,356
Appendix 3B – Other Generation Units
Company Name:
Schedule 14b
Virginia Ele ctric and Power Company
Existing Supply-Side Resources (kW)
Unit Name
Location
Unit Class
Primary
kW
Capacity
Contract
Contract
Fuel Type
Summer
Resource
Start
Expiration
Non-Utility Generation (NUG) Units
S pruanc e Genc o, Fac ility 1 (Ric hmo nd 1)
Ric hmond, VA
Base
Coal
115,500
Yes
8/1/1992
7/31/2017
S pruanc e Genc o, Fac ility 2 (Ric hmo nd 2)
Ric hmond, VA
Base
Coal
85,000
Yes
8/1/1992
7/31/2017
Edgec ombe Genco (Ro c ky Mo unt)
Battlebo ro, NC
Base
Coal
115,500
Yes
10/15/1990
10/14/2015
Doswell Co mplex
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
5/31/2015
Covanta Fairfax
Lorton, VA
Base
MS W
63,000
Yes
5/5/1990
Ro ano ke Valley II
Weldon, NC
Base
Coal
44,000
Yes
6/1/1995
3/31/2019
Ro ano ke Valley Projec t
Weldon, NC
Base
Coal
165,000
Yes
5/29/1994
3/31/2019
S EI Birc hwoo d
King Geo rge, VA
Base
Coal
217,800
Yes
11/15/1996
11/14/2021
21,000
No
1/29/1988
1/28/2023
2,900
No
8/27/1993
8/26/2013
(2)
Behind-The-Meter Generation (BTMG) Units
BTM Alexandria/Arlington - Covanta
VA
NUG
MS W
BTM Ric hmo nd Elec tric
VA
Must Take
Methane
BTM Brasfield Dam
VA
Must Take
Hydro
2,485
No
10/12/1993
10/11/2013
BTM S uffo lk 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 c ho olfield Dam
VA
Must Take
Hydro
2,500
No
12/1/1990
11/30/2015
BTM Lakeview (S wift Creek) Dam
VA
Must Take
Hydro
Auto renew
BTM MeadWestvac o (formerly Westvac o)
VA
NUG
Coal/Bio mass
BTM Banister Dam
VA
Must Take
Hydro
400
No
11/26/2008
125,000
No
11/3/1982
Auto renew
1,785
No
9/28/2008
Auto renew
BTM 119 Goo se Castle Terrac e
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 Beac h
NC
Must Take
Wind
2
No
8/22/2006
Auto renew
BTM Joc key's 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 S murfit-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 o uth 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 S olar
NC
Must Take
S olar
2,400
No
Pending
N/A
(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.
AP - 14
Appendix 3B Cont. – Other Generation Units
Company Name:
Schedule 14b
Unit Name
Location
Unit Class
Primary
Fuel Type
kW
Capacity
Contract
Contract
Summer
Resource
Start
Expiration
(5)
Customer Owned
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
Mo yoc k
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
Roc ky Mount
S tandby
Diesel
700
No
N/A
N/A
Roanoke Rapids
S tandby
Coal
Manteo
S tandby
Diesel
25000
No
N/A
N/A
300
No
N/A
N/A
Conway
S tandby
Lewisto n
S tandby
Diesel
800
No
N/A
N/A
Diesel
4000
No
N/A
Roanoke Rapids
N/A
S tandby
Diesel
1200
No
N/A
Weldon
N/A
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 V A
S tandby
Diesel
50
No
N/A
N/A
Northern V A
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 V A
S tandby
Diesel
14000
No
N/A
N/A
Northern V A
S tandby
Diesel
10000
No
N/A
N/A
Norfolk
S tandby
Diesel
4000
No
N/A
N/A
Ric hmond
S tandby
Diesel
4470
No
N/A
N/A
Arlington
S tandby
Diesel
5650
No
N/A
N/A
Ric hmond
S tandby
Diesel
22950
No
N/A
N/A
Northern V A
S tandby
Diesel
50
No
N/A
N/A
Hampton Roads
S tandby
Diesel
3000
No
N/A
N/A
Northern V A
S tandby
Diesel
900
No
N/A
N/A
Ric hmond
S tandby
Diesel
20110
No
N/A
N/A
Ric hmond
S tandby
Diesel
3500
No
N/A
N/A
Ric hmond
S tandby
Natural Gas
10
No
N/A
N/A
Ric hmond
S tandby
LP
120
No
N/A
N/A
V A Beac h
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 - 15
Company Name:
Schedule 14b
Unit Name
Location
Primary
Unit Class
Fuel Type
kW
Capacity
Contract
Contract
Summer
Resource
Start
Expiration
N/A
(5)
Customer Owned
Frederic ksburg
S tandby
Diesel
700
No
N/A
Hopewell
S tandby
Diesel
75
No
N/A
N/A
Newpo rt News
S tandby
Unknown
1000
No
N/A
N/A
Newpo rt 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 Beac h
S tandby
Diesel
3500
No
N/A
N/A
VA Beac h
S tandby
Diesel
2000
No
N/A
N/A
Chesterfield
S tandby
Diesel
2000
No
N/A
N/A
Central VA
Merc hant
Coal
92000
No
N/A
N/A
Central VA
Merc hant
Coal
115000
No
N/A
N/A
Williamsburg
S tandby
Diesel
2800
No
N/A
N/A
Ric hmond
S tandby
Diesel
30000
No
N/A
N/A
Charlottesville
S tandby
Diesel
40000
No
N/A
N/A
Arlington
S tandby
Diesel
13042
No
N/A
N/A
Arlington
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
Henric o
S tandby
Natural Gas
1341
No
N/A
N/A
Henric o
S tandby
LP
126
No
N/A
N/A
Henric o
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
Newpo rt News
S tandby
Diesel
1750
No
N/A
N/A
Northern VA
S tandby
Diesel
37000
No
N/A
N/A
Chesapeake
S tandby
Northern VA
Merc hant
Unknown
750
No
N/A
N/A
Natural Gas
50000
No
N/A
N/A
Northern VA
Ric hmond
S tandby
Diesel
138000
No
N/A
N/A
S tandby
S team
20000
No
N/A
Herndon
N/A
S tandby
Diesel
415
No
N/A
N/A
N/A
Herndon
S tandby
Diesel
50
No
N/A
VA
Merc hant
Hydro
2700
No
N/A
N/A
Northern VA
S tandby
Diesel
37000
No
N/A
N/A
Fairfax Co unty
S tandby
Diesel
20205
No
N/A
N/A
Fairfax Co unty
S tandby
Natural Gas
2139
No
N/A
N/A
Fairfax Co unty
S tandby
LP
292
No
N/A
N/A
S pringfield
S tandby
Diesel
6500
No
N/A
N/A
Warrento n
S tandby
Diesel
2 - 750
No
N/A
N/A
Northern VA
S tandby
Diesel
5350
No
N/A
N/A
Ric hmond
S tandby
Diesel
16400
No
N/A
N/A
Norfolk
S tandby
Diesel
350
No
N/A
N/A
Charlottesville
S tandby
Diesel
400
No
N/A
N/A
AP - 16
Company Name:
Schedule 14b
Unit Name
Location
Primary
Unit Class
Fuel Type
kW
Capacity
Contract
Contract
Summer
Resource
Start
Expiration
N/A
(5)
Customer Owned
Farmville
S tandby
Diesel
350
No
N/A
Mec hanic sville
S tandby
Diesel
350
No
N/A
N/A
King Geo rge
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 Beac h
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
Ric hmond
S tandby
Diesel
350
No
N/A
N/A
Ric hmond
S tandby
Diesel
350
No
N/A
N/A
Chesapeake
S tandby
Diesel
400
No
N/A
N/A
Newpo rt News
S tandby
Diesel
350
No
N/A
N/A
Dinwiddie
S tandby
Diesel
300
No
N/A
N/A
Gooc hland
S tandby
Diesel
350
No
N/A
N/A
Portsmouth
S tandby
Diesel
350
No
N/A
N/A
Frederic ksburg
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
N/A
Herndon
S tandby
Diesel
500
No
N/A
Henric o
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
Mo unt 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 Churc h
S tandby
Diesel
200
No
N/A
N/A
Falls Churc h
S tandby
Diesel
250
No
N/A
N/A
Northern VA
S tandby
Diesel
500
No
N/A
N/A
Frederic ksburg
S tandby
Diesel
4200
No
N/A
N/A
Norfolk
S tandby
NG
1050
No
N/A
N/A
Ric hmond
S tandby
Diesel
6400
No
N/A
N/A
Henric o
S tandby
Diesel
500
No
N/A
N/A
Elkton
S tandby
Natural 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
AP - 17
Company Name:
Schedule 14b
Unit Name
Location
Unit Class
Primary
Fuel Type
kW
Capacity
Contract
Contract
Summer
Resource
Start
Expiration
(5)
Customer Owned
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
Ric hmond
S tandby
Diesel
4470
No
N/A
N/A
Arlington
S tandby
Diesel
5650
No
N/A
N/A
Ashburn
S tandby
Diesel
22000
No
N/A
N/A
Ric hmond
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
Ric hmond
S tandby
Diesel
20110
No
N/A
N/A
Ric hmond
S tandby
Diesel
3500
No
N/A
N/A
Ric hmond
S tandby
NG
10
No
N/A
N/A
Ric hmond
S tandby
LP
120
No
N/A
N/A
Va Beac h
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
Frederic ksburg
S tandby
Diesel
700
No
N/A
N/A
Hopewell
S tandby
Diesel
75
No
N/A
N/A
Newpo rt News
S tandby
Unknown
1000
No
N/A
N/A
Newpo rt 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 Beac h
S tandby
Diesel
3500
No
N/A
N/A
Va Beac h
S tandby
Diesel
2000
No
N/A
N/A
Chesterfield
S tandby
Diesel
2000
No
N/A
N/A
Central VA
Merc hant
Coal
92000
No
N/A
N/A
Central VA
Merc hant
Coal
115000
No
N/A
N/A
Williamsburg
S tandby
Diesel
2800
No
N/A
N/A
Ric hmond
S tandby
Diesel
30000
No
N/A
N/A
Charlottesville
S tandby
Diesel
40000
No
N/A
N/A
Arlington
S tandby
Diesel
13042
No
N/A
N/A
Arlington
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
Henric o
S tandby
NG
1341
No
N/A
N/A
Henric o
S tandby
LP
126
No
N/A
N/A
Henric o
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
Newpo rt News
S tandby
Diesel
1750
No
N/A
N/A
Northern VA
S tandby
Diesel
37000
No
N/A
N/A
AP - 18
Company Name:
Schedule 14b
Unit Name
Location
Primary
Unit Class
Fuel Type
kW
Capacity
Contract
Contract
Summer
Resource
Start
Expiration
(5)
Customer Owned
Chesapeake
S tandby
Northern V A
Merchant
Northern V A
Richmond
Herndon
Unkno wn
750
No
N/A
N/A
NG
50000
No
N/A
N/A
S tandby
Diesel
138000
No
N/A
N/A
S tandby
S team
20000
No
N/A
N/A
S tandby
Diesel
415
No
N/A
N/A
N/A
Herndon
S tandby
Diesel
50
No
N/A
VA
Merchant
Hydro
2700
No
N/A
N/A
Northern V A
S tandby
Diesel
37000
No
N/A
N/A
Fairfax Co unty
S tandby
Diesel
20205
No
N/A
N/A
Fairfax Co unty
S tandby
NG
2139
No
N/A
N/A
Fairfax Co unty
S tandby
LP
292
No
N/A
N/A
S pringfield
S tandby
Diesel
6500
No
N/A
N/A
Warrenton
S tandby
Diesel
2 - 750
No
N/A
N/A
Northern V A
S tandby
Diesel
5350
No
N/A
N/A
Richmond
S tandby
Diesel
16400
No
N/A
N/A
Norfo lk
S tandby
Diesel
350
No
N/A
N/A
Charlottesville
S tandby
Diesel
400
No
N/A
N/A
Farmville
S tandby
Diesel
350
No
N/A
N/A
Mechanic sville
S tandby
Diesel
350
No
N/A
N/A
King Geo rge
S tandby
Diesel
350
No
N/A
N/A
Chatham
S tandby
Diesel
350
No
N/A
N/A
Hampto n
S tandby
Diesel
350
No
N/A
N/A
V irginia Beach
S tandby
Diesel
350
No
N/A
N/A
Po rtsmouth
S tandby
Diesel
400
No
N/A
N/A
Po whatan
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
Gooc hland
S tandby
Diesel
350
No
N/A
N/A
Po rtsmouth
S tandby
Diesel
350
No
N/A
N/A
Fredericksburg
S tandby
Diesel
350
No
N/A
N/A
Northern V A
S tandby
Diesel
22690
No
N/A
N/A
Northern V A
S tandby
Diesel
5000
No
N/A
N/A
Hampto n 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
Henric o
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
Lo udoun
S tandby
Diesel
2100
No
N/A
N/A
Lo udoun
S tandby
Diesel
710
No
N/A
N/A
Mount V erno n
S tandby
Diesel
1500
No
N/A
N/A
Northern V A
S tandby
Diesel
50
No
N/A
N/A
Eastern VA
S tandby
Black liquor/Natural Gas
112500
No
N/A
N/A
AP - 19
Company Name:
Schedule 14b
Unit Name
Location
Unit Class
Primary
Fuel Type
kW
Capacity
Contract
Contract
Summer
Resource
Start
Expiration
(5)
Customer Owned
Central V A
S tandby
Diesel
1700
No
N/A
N/A
Ho pewell
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
No rthern VA
S tandby
Diesel
500
No
N/A
N/A
Fredericksburg
S tandby
Diesel
4200
No
N/A
N/A
No rfo lk
S tandby
NG
1050
No
N/A
N/A
Ric hmond
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 o uthside V A
S tandby
Diesel
30000
No
N/A
N/A
No rthern VA
S tandby
Diesel
5000
No
N/A
N/A
No rthern VA
S tandby
#2 FO
5000
No
N/A
N/A
No rthern VA
S tandby
Diesel
50
No
N/A
N/A
Vienna
S tandby
Diesel
5000
No
N/A
N/A
No rthern VA
S tandby
Diesel
200
No
N/A
N/A
No rfo lk
S tandby
Diesel
1000
No
N/A
N/A
No rthern VA
S tandby
Diesel
1000
No
N/A
N/A
No rfo lk
S tandby
Diesel
1500
No
N/A
N/A
No rthern VA
S tandby
Diesel
3000
No
N/A
N/A
Newport News
S tandby
Diesel
750
No
N/A
N/A
Chesterfield
S tandby
Co al
500
No
N/A
N/A
Ric hmond
S tandby
Diesel
1500
No
N/A
N/A
Ric hmond
S tandby
Diesel
1000
No
N/A
N/A
Ric hmond
S tandby
Diesel
1000
No
N/A
N/A
No rthern VA
S tandby
Diesel
3000
No
N/A
N/A
Ric hmond Metro
S tandby
NG
25000
No
N/A
N/A
S uffolk
S tandby
Diesel
2000
No
N/A
N/A
No rthern VA
S tandby
Diesel
8000
No
N/A
N/A
No rthern VA
S tandby
Diesel
21000
No
N/A
N/A
Ric hmond
S tandby
Diesel
500
No
N/A
N/A
Hampton Ro ads
S tandby
Diesel
4000
No
N/A
N/A
No rthern VA
S tandby
Diesel
10000
No
N/A
N/A
No rthern VA
S tandby
Diesel
5000
No
N/A
N/A
Hampton Ro ads
S tandby
Diesel
12000
No
N/A
N/A
West Point
S tandby
Unknown
50000
No
N/A
N/A
No rthern 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 taffo rd
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
Ric hmond
S tandby
Diesel
5150
No
N/A
N/A
Culpepper
S tandby
Diesel
7000
No
N/A
N/A
Ric hmond
S tandby
Diesel
8000
No
N/A
N/A
No rthern VA
S tandby
Diesel
2000
No
N/A
N/A
No rthern VA
S tandby
Diesel
6000
No
N/A
N/A
No rthern VA
S tandby
Diesel
500
No
N/A
N/A
No rthern VA
S tandby
NG
50000
No
N/A
N/A
AP - 20
Company Name:
Schedule 14b
Virginia Ele ctric a nd Powe r Company
Unit Name
Location
Unit Class
Primary
Fuel Type
kW
Capacity
Contract
Contract
Summer
Resource
Start
Expiration
(5)
Customer Owned
Hampton Ro ads
S tandby
Unknown
4000
No
N/A
N/A
Northern V A
S tandby
Diesel
10000
No
N/A
N/A
Northern V A
S tandby
Diesel
13000
No
N/A
N/A
S outhside V A
S tandby
Water
227000
No
N/A
N/A
Northern V A
S tandby
Diesel
300
No
N/A
N/A
Northern V A
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
Various
S tandby
Diesel
3000
No
N/A
N/A
Various
S tandby
Diesel
30000
No
N/A
N/A
Northern V A
S tandby
Diesel
5000
No
N/A
N/A
Northern V A
S tandby
Diesel
2000
No
N/A
N/A
Ashburn
S tandby
Diesel
16000
No
N/A
N/A
Northern V A
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 V A
Diesel
150
No
N/A
N/A
S tandby
Henrico
S tandby
Diesel
500
No
N/A
N/A
Virginia Beach
S tandby
Diesel
1500
No
N/A
N/A
Aho skie
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
Coro lla
S tandby
Diesel
700
No
N/A
N/A
Kill Devil Hills
S tandby
Diesel
700
No
N/A
N/A
Roc ky Mount
S tandby
Diesel
700
No
N/A
N/A
Roanoke Rapids
S tandby
Co al
Manteo
S tandby
Diesel
30000
No
N/A
N/A
300
No
N/A
N/A
Conway
S tandby
Lewiston
S tandby
Diesel
800
No
N/A
N/A
Diesel
4000
No
N/A
Roanoke Rapids
N/A
S tandby
Diesel
1200
No
N/A
Weldon
N/A
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 - 21
Appendix 3C – Equivalent Availability Factor (%)
Company Name:
Schedule 8
Virginia Electric and Power Company
Equivalent Availability Factor (%)
(ACTUAL)
Unit Name
Altavista
Bear Garden
Bellemeade
Bremo 3
Bremo 4
Brunswick
Chesapeake 1
Chesapeake 2
Chesapeake 3
Chesapeake 4
Chesapeake CT 1, 2, 4, 6
Chesterfield 3
Chesterfield 4
Chesterfield 5
Chesterfield 6
Chesterfield 7
Chesterfield 8
Clover 1
Clover 2
Covanta Fairfax
Cushaw Hydro
Darbytown 1
Darbytown 2
Darbytown 3
Darbytown 4
Doswell Complex
Edgecombe Genco (Rocky Mountain)
Elizabeth River 1
Elizabeth River 2
Elizabeth River 3
Existing Solar NC NUGs with PPAs
Future Solar NC Nugs
Gaston Hydro
Generic CC 2019
Generic CC 2029
Generic CT 2022
Generic CT 2023
Gordonsville 1
Gordonsville 2
Gravel Neck 1-2
Gravel Neck 3
Gravel Neck 4
Gravel Neck 5
Gravel Neck 6
Hopewell
Hopewell Cogen
Ladysmith 1
Ladysmith 2
Ladysmith 3
Ladysmith 4
Ladysmith 5
Lowmoor CT 1-4
2011
2012
(PROJECTED)
2013
2014
2015
80
2016
81
90
90
84
90
90
81
90
90
81
90
90
81
90
90
87
86
89
84
87
86
90
90
89
90
84
90
90
90
90
90
90
98
85
62
60
93
90
90
90
90
90
90
90
90
90
90
90
90
90
90
84
83
56
59
92
88
88
88
88
88
88
88
88
88
88
88
88
88
88
-
-
-
-
-
90
90
90
85
90
90
84
90
90
84
90
90
90
90
85
90
96
94
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
86
91
93
94
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
83
85
86
91
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
88
91
86
92
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
80
75
96
88
88
88
88
88
88
-
-
-
-
-
-
-
-
-
-
68
41
83
81
91
85
85
91
87
87
87
87
87
87
87
87
87
87
87
66
90
68
84
84
84
84
74
85
85
85
85
85
85
85
85
85
85
85
53
85
71
83
88
83
88
90
83
94
83
94
83
94
83
94
83
94
83
94
74
87
77
87
89
79
91
87
87
87
87
87
87
87
87
87
87
87
92
87
91
83
96
91
96
89
96
89
85
88
89
96
91
89
91
89
96
91
73
94
86
89
96
88
96
85
96
91
96
83
89
96
85
89
89
89
96
76
98
96
78
94
94
86
96
96
86
96
96
86
96
96
86
96
96
89
94
94
83
94
94
83
94
96
96
94
96
86
96
96
96
96
96
86
92
92
86
72
95
-
-
-
-
-
-
-
-
-
-
-
-
-
-
31
39
62
83
83
83
83
83
83
83
83
83
83
83
83
83
83
83
83
98
94
96
94
94
94
94
83
92
92
92
92
92
92
92
92
92
92
92
92
97
98
94
94
94
94
87
90
92
92
92
92
92
92
92
92
92
92
99
97
99
94
94
94
90
87
92
92
92
92
92
92
92
92
92
92
92
99
96
97
94
94
94
94
83
92
92
92
92
92
92
92
92
92
92
92
84
86
87
74
84
84
95
-
-
-
-
-
-
-
-
-
-
-
-
96
96
94
89
96
-
-
-
-
-
-
-
-
-
-
-
-
-
-
98
96
93
93
90
90
90
90
90
90
90
90
90
90
90
90
90
90
90
97
98
93
93
67
90
90
90
90
90
90
90
90
90
90
90
90
90
90
98
98
94
93
67
90
90
90
90
90
90
90
90
90
90
90
90
90
90
-
-
-
21
21
21
21
21
21
21
21
21
21
21
21
21
21
21
-
-
-
-
-
21
22
21
21
21
22
21
21
21
22
21
21
21
22
21
78
86
86
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-
-
-
-
-
-
-
-
88
88
88
88
88
88
88
88
88
88
88
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
88
-
-
-
-
-
-
-
-
-
-
-
88
88
88
88
88
88
88
88
N/A
93
2029
85
N/A
92
2028
91
N/A
93
2027
84
N/A
92
2026
87
N/A
93
2025
82
N/A
92
2024
88
N/A
93
2023
84
N/A
92
2022
86
N/A
93
2021
84
N/A
92
2020
55
N/A
93
2019
-
N/A
92
2018
-
N/A
93
2017
N/A
92
N/A
93
N/A
-
-
-
-
-
-
-
-
-
-
-
-
88
88
88
88
88
88
88
93
92
94
84
84
88
85
96
91
96
89
91
96
85
96
90
91
91
96
93
87
94
90
96
91
88
85
91
96
91
85
94
91
84
94
91
96
94
94
93
96
88
88
88
88
88
88
-
-
-
-
-
-
-
-
-
-
93
97
72
94
94
94
94
94
94
94
94
89
94
94
94
94
94
94
94
73
97
98
92
94
94
94
94
94
89
94
94
94
94
94
94
94
94
94
97
92
98
92
94
94
94
94
94
89
94
94
94
94
94
94
94
94
94
92
72
98
94
94
94
94
94
94
94
94
89
94
94
94
94
94
94
94
95
87
39
90
88
92
93
93
92
92
92
92
92
92
92
92
92
92
92
85
88
83
86
94
-
-
-
-
-
-
-
-
-
-
-
-
-
-
88
95
81
90
90
90
90
90
90
90
90
90
81
90
90
90
92
90
89
95
94
80
90
90
90
90
90
90
90
90
81
90
90
90
90
90
90
89
91
94
94
89
90
90
90
90
90
90
90
90
90
90
90
90
90
90
89
92
95
94
89
90
90
90
87
90
90
90
90
90
90
90
90
90
90
89
92
96
95
90
90
90
90
90
87
90
90
90
90
90
90
90
90
90
89
100
98
100
88
88
88
-
-
-
-
-
-
-
-
-
-
-
-
-
AP - 22
Appendix 3C Cont. – Equivalent Availability Factor (%)
Company Name:
Schedule 8
Equivalent Availability Factor (%)
(ACTUAL)
Unit Name
Mecklenburg 1
Mecklenburg 2
Mount Storm 1
Mount Storm 2
Mount Storm 3
Mount Storm CT
North Anna 1
North Anna 2
North Anna Hydro
Northern 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 Valley II
Roanoke Valley Project
Rosemary
SEI Birchwood
Southampton
Spruance Genco, Facility 1 (Richmond 1)
Surry 1
Surry 2
Warren
Yorktown 1
Yorktown 2
Yorktown 3
2011
2012
(PROJECTED)
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
98
94
97
95
90
95
92
95
91
92
95
92
95
91
95
91
95
91
95
96
94
98
90
95
95
92
95
91
95
91
95
92
95
91
95
91
95
91
92
87
74
90
84
83
89
90
83
89
89
81
89
89
81
89
89
81
89
76
80
83
73
84
81
83
91
89
89
81
89
89
81
89
89
81
89
89
93
59
79
91
84
66
91
91
91
81
91
91
81
91
91
81
91
91
81
87
98
92
88
88
88
-
-
-
-
-
-
-
-
-
-
-
-
-
77
85
90
98
92
89
98
90
91
98
91
91
98
91
91
98
91
91
98
74
96
86
89
98
91
90
98
91
91
98
91
91
98
91
91
98
91
91
-
-
-
30
30
29
30
30
30
29
30
30
30
29
30
30
30
29
99
99
98
88
88
88
88
-
-
-
-
-
-
-
-
-
-
-
-
81
76
78
91
95
93
93
93
92
93
93
93
93
93
93
93
93
93
93
70
67
89
83
91
87
87
91
91
82
91
91
91
87
91
91
91
82
91
87
63
92
80
91
85
87
91
91
87
91
91
91
85
91
91
91
87
91
75
77
70
39
77
69
77
77
85
78
85
69
85
78
85
78
85
69
85
78
90
89
88
81
88
88
81
89
89
82
89
89
82
89
89
89
89
89
99
98
100
88
88
-
-
-
-
-
-
-
-
-
-
-
-
-
-
92
86
90
86
90
90
90
90
90
90
90
90
90
90
90
90
90
90
89
97
88
87
90
87
90
90
90
90
90
90
90
90
90
90
90
90
90
89
97
87
90
90
90
90
87
90
90
90
90
90
90
90
90
90
90
90
89
94
86
91
86
90
90
90
90
90
90
90
90
90
90
90
90
90
90
89
94
93
94
34
34
34
34
34
34
34
34
34
34
34
34
34
34
34
34
85
89
87
89
86
89
89
87
89
97
-
-
-
-
-
-
-
-
-
89
80
85
88
87
87
87
87
95
-
-
-
-
-
-
-
-
-
-
89
86
85
85
89
96
89
96
96
96
96
96
91
96
96
91
96
96
91
78
91
87
87
87
82
87
87
87
87
82
-
-
-
-
-
-
-
-
-
-
-
18
13
14
14
14
14
14
14
14
14
14
14
14
14
14
14
90
85
46
86
93
93
93
93
93
93
93
93
93
88
93
93
93
93
93
94
95
95
88
90
90
96
-
-
-
-
-
-
-
-
-
-
-
91
94
91
93
89
89
95
-
-
-
-
-
-
-
-
-
-
-
-
98
90
91
98
90
92
98
91
91
98
91
91
98
91
91
98
91
91
98
76
90
100
89
90
98
92
91
98
91
91
98
91
91
98
91
91
98
90
-
57
78
84
84
84
84
84
81
92
88
84
92
88
84
92
88
84
92
-
-
-
97
87
88
88
84
90
97
88
90
90
85
90
90
85
90
90
73
71
78
84
89
89
-
-
-
-
-
-
-
-
-
-
-
-
-
73
76
81
87
93
93
-
-
-
-
-
-
-
-
-
-
-
-
-
54
57
58
39
73
61
73
77
85
78
85
78
85
78
85
78
85
78
85
AP - 23
30
-
Appendix 3D – Net Capacity Factor
Company Name:
Schedule 9
Virginia Electric and Powe r Company
Net Capacity Factor (%)
(ACTUAL)
Unit Name
Altavista
Bear Garden
Bellemeade
Bremo 3
Bremo 4
Brunswick
Chesapeake 1
Chesapeake 2
Chesapeake 3
Chesapeake 4
Chesterfield 3
Chesterfield 4
Chesterfield 5
Chesterfield 6
Chesterfield 7
Chesterfield 8
Clover 1
Clover 2
Covanta Fairfax
Cushaw Hydro
Darbytown 1
Darbytown 2
Darbytown 3
Darbytown 4
Doswell Complex
Elizabeth River 1
Elizabeth River 2
Elizabeth River 3
Gaston Hydro
Generic CC 2019
Generic CC 2029
Generic CT 2022
Generic CT 2023
Gordonsville 1
Gordonsville 2
Gravel Neck 1-2
Gravel Neck 3
Gravel Neck 4
Gravel Neck 5
Gravel Neck 6
Hopewell
Hopewell Cogen
Ladysmith 1
Ladysmith 2
Ladysmith 3
Ladysmith 4
Ladysmith 5
Lowmoor CT 1-4
2011
2012
-
-
(PROJECTED)
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
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
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
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
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
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
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
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
-
-
-
-
-
36.0
14.3
18.1
14.8
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
39.5
20.4
18.2
16.3
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
60.0
56.5
60.0
67.1
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
68.1
17.6
23.4
22.4
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
0.2
0.1
0.1
0.9
0.8
0.7
0.5
0.4
-
-
-
-
-
-
-
-
-
-
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
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
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
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
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
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
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
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
114.5
104.9
100.1
63.6
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
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
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
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
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
48.8
56.8
54.2
50.8
43.3
34.0
-
-
-
-
-
-
-
-
-
-
-
-
-
42.1
12.0
9.1
75.8
58.5
-
-
-
-
-
-
-
-
-
-
-
-
-
-
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
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
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
-
-
-
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
-
-
-
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
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
74.4
74.4
73.9
72.4
70.4
70.6
70.2
70.1
69.2
69.6
10.4
8.9
15.6
15.2
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
63.6
69.0
-
-
-
-
-
-
-
-
-
-
-
5.5
4.5
4.6
4.6
4.6
4.9
4.8
4.4
-
-
-
-
-
-
-
-
-
-
-
-
6.0
6.2
6.2
6.2
6.6
6.3
5.7
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
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
0.1
0.1
0.0
1.0
0.8
0.7
0.5
0.5
-
-
-
-
-
-
-
-
-
-
-
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
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
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
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
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
31.9
40.0
26.0
41.8
20.5
-
-
-
-
-
-
-
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
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
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
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
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
0.0
0.1
0.1
1.0
0.8
-
-
-
AP - 24
-
-
-
-
-
-
-
-
-
-
-
-
-
8.9
8.1
10.8
9.8
9.0
11.7
10.7
9.7
10.1
10.5
9.6
8.8
9.7
9.5
9.9
9.0
8.3
-
-
-
-
-
Appendix 3D Cont. – Net Capacity Factor
Company Name:
Schedule 9
Net Capacity Factor (%)
(ACTUAL)
Unit Name
2011
Mecklenburg 1
19.4
Mecklenburg 2
16.5
Mount Storm 1
70.9
Mount Storm 2
54.8
Mount Storm 3
64.4
Mount Storm CT
0.1
North Anna 1
77.2
North Anna 2
75.8
North Anna Hydro
0.1
Pittsylvania
54.0
Possum Point 3
3.1
Possum Point 4
5.6
Possum Point 5
1.0
Possum Point 6
57.5
Possum Point CT 1-6
0.0
Remington 1
5.5
Remington 2
4.6
Remington 3
5.0
Remington 4
5.9
22.6
Roanoke Valley II
81.8
88.5
Rosemary
10.6
SEI Birchwood
24.1
Southampton
17.0
Spruance Genco, Facility 1 (Richmond 1) 55.0
Spruance Genco, Facility 2 (Richmond 2) 44.9
Surry 1
99.5
Surry 2
76.7
Warren
Yorktown 1
41.3
Yorktown 2
45.1
Yorktown 3
2.5
2012
(PROJECTED)
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
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
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
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
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
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
0.1
0.2
0.9
0.7
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
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
-
-
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
0.1
0.1
1.1
0.8
0.7
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
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
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
1.0
0.5
1.5
1.3
1.1
0.9
-
-
-
-
-
-
-
-
-
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
-
-
-
-
80.1
77.5
77.7
7.5
7.9
7.2
6.7
9.6
10.2
9.5
8.5
33.6
34.1
34.2
28.1
0.1
0.1
1.0
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
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
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
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
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
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
86.5
87.5
86.5
86.1
90.2
89.6
88.3
88.9
-
-
-
-
-
-
-
-
-
78.1
84.2
86.5
85.4
86.3
86.7
86.9
-
-
-
-
-
-
-
-
-
-
-
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
19.3
28.5
61.3
50.8
45.6
42.6
43.9
41.5
45.2
41.5
-
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
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
11.7
11.8
79.9
75.7
69.2
45.7
-
-
-
-
-
-
-
-
-
-
-
11.4
13.1
74.6
62.3
64.1
38.7
-
-
-
-
-
-
-
-
-
-
-
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
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
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
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
-
-
-
-
-
-
42.9
26.5
41.5
37.9
-
-
-
-
-
-
-
-
-
-
-
-
-
17.6
32.1
48.0
50.2
-
-
-
-
-
-
-
-
-
-
-
-
-
-
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 - 25
-
Appendix 3E – Heat Rates
Company Name:
Schedule 10a
Virginia Ele ctric and Powe r Compa ny
Average Heat Rate - (mmBtu/MWh) (At Maximum)
(ACTUAL)
Unit Name
Altavista
Bear Garden
Bellemeade
Bremo 3
Bremo 4
Brunswick
Chesapeake 1
Chesapeake 2
Chesapeake 3
Chesapeake 4
Chesterfield 3
Chesterfield 4
Chesterfield 5
Chesterfield 6
Chesterfield 7
Chesterfield 8
Clover 1
Clover 2
Covanta Fairfax
Cushaw Hydro
Darbytown 1
Darbytown 2
Darbytown 3
Darbytown 4
Doswell Complex
Elizabeth River 1
Elizabeth River 2
Elizabeth River 3
Gaston Hydro
Generic CC 2019
Generic CC 2029
Generic CT 2022
Generic CT 2023
Gordonsville 1
Gordonsville 2
Gravel Neck 1-2
Gravel Neck 3
Gravel Neck 4
Gravel Neck 5
Gravel Neck 6
Hopewell
Hopewell Cogen
Ladysmith 1
Ladysmith 2
Ladysmith 3
Ladysmith 4
Ladysmith 5
Lowmoor CT 1-4
2011
2012
-
-
N/A
N/A
(PROJECTED)
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
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
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
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
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
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
10.52
10.72
10.76
10.73
10.73
-
-
-
10.97
10.91
10.66
10.73
10.88
10.51
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
-
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
10.66
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
10.80
10.57
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
10.61
10.51
10.13
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
10.58
10.56
10.86
10.26
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
17.04
17.97
20.42
18.54
18.54
18.54
18.54
18.54
18.54
-
-
-
-
-
-
-
-
-
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
-
-
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
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
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
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
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
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
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
10.00
10.00
10.00
10.00
10.00
-
-
-
-
-
-
-
-
-
-
-
-
-
-
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
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
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
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
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
10.00
10.00
10.00
8.55
8.55
8.55
8.55
-
-
-
-
-
-
-
-
-
-
-
10.00
10.00
10.00
10.00
10.00
-
-
-
-
-
-
-
-
-
-
-
-
-
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
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
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
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
-
-
-
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
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
-
-
-
-
-
-
-
-
6.76
6.76
6.76
6.76
6.76
6.76
6.76
6.76
6.76
6.76
6.76
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
6.76
-
-
-
-
-
-
-
-
-
-
-
9.04
9.04
9.04
9.04
9.04
9.04
9.04
9.04
-
-
-
-
-
-
-
-
-
-
-
-
9.04
9.04
9.04
9.04
9.04
9.04
9.04
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
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
17.71
18.45
17.17
17.40
17.40
17.40
17.40
17.40
17.40
-
-
-
-
-
-
-
-
-
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
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
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
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
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
10.00
10.00
10.00
8.47
8.47
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
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
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
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
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
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
17.65
16.98
17.19
16.76
16.76
16.76
-
AP - 26
-
-
-
-
-
-
-
-
-
-
-
-
Appendix 3E Cont. – Heat Rates
Company Name:
Schedule 10a
Virginia Ele ctric and Powe r Compa ny
Average Heat Rate - (mmBtu/MWh) (At Maximum)
(ACTUAL)
Unit Name
Mecklenburg 1
Mecklenburg 2
Mount Storm 1
Mount Storm 2
Mount Storm 3
Mount Storm CT
North Anna 1
North Anna 2
North Anna Hydro
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 Valley II
Rosemary
SEI Birchwood
Southampton
Surry 1
Surry 2
Warren
Yorktown 1
Yorktown 2
Yorktown 3
2011
2012
(PROJECTED)
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
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
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
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
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
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
23.59
21.80
15.97
20.36
20.36
20.36
-
-
-
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
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
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
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
16.27
17.29
17.17
16.83
16.83
16.83
16.83
-
-
-
-
-
-
-
-
-
-
-
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
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
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
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
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
17.27
16.69
16.64
16.76
16.76
-
-
-
-
-
-
-
-
-
-
-
-
-
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
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
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
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
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
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
10.00
10.00
10.00
-
-
-
-
-
-
-
-
8.76
-
-
-
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
10.00
10.00
10.00
9.61
9.61
9.61
9.61
9.61
9.61
9.61
9.61
-
-
-
-
-
-
-
-
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
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
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
-
-
-
-
-
-
-
-
-
-
-
-
-
-
10.54
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
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
-
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
-
-
-
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
10.46
10.48
10.72
10.58
10.58
10.58
-
-
-
-
-
-
-
-
-
-
-
-
-
9.87
9.79
10.16
10.23
10.23
10.23
-
-
-
-
-
-
-
-
-
-
-
-
-
11.73
10.77
10.48
10.64
10.64
10.64
10.64
10.64
AP - 27
10.64
10.64
10.64
10.64
10.64
10.64
10.64
10.64
10.64
10.64
10.64
Company Name:
Average Heat Rate - (mmBtu/MWh) (At Minimum)
Schedule 10b
(ACTUAL)
(PROJECTED)
Unit Name
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
Altavista
Bear Garden
Bellemeade
Bremo 3
Bremo 4
Brunswick
Chesapeake 1
Chesapeake 2
Chesapeake 3
Chesapeake 4
Chesterfield 3
Chesterfield 4
Chesterfield 5
Chesterfield 6
Chesterfield 7
Chesterfield 8
Clover 1
Clover 2
Covanta Fairfax
Cushaw Hydro
Darbytown 1
Darbytown 2
Darbytown 3
Darbytown 4
Doswell Complex
Elizabeth River 1
Elizabeth River 2
Elizabeth River 3
Gaston Hydro
Generic CC 2019
Generic CC 2029
Generic CT 2022
Generic CT 2023
Gordonsville 1
Gordonsville 2
Gravel Neck 1-2
Gravel Neck 3
Gravel Neck 4
Gravel Neck 5
Gravel Neck 6
Hopewell
Hopewell Cogen
Ladysmith 1
Ladysmith 2
Ladysmith 3
Ladysmith 4
Ladysmith 5
Lowmoor CT 1-4
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
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
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
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
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
N/A
N/A
N/A
11.87
11.87
N/A
N/A
N/A
N/A
N/A
N/A
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
-
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
10.93
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
N/A
10.85
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
N/A
N/A
10.41
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
N/A
N/A
N/A
10.33
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
N/A
N/A
N/A
18.54
18.54
18.54
18.54
18.54
18.54
-
-
-
-
-
-
-
-
-
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
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
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
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
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
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
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
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
N/A
N/A
N/A
10.00
10.00
-
-
-
-
-
-
-
-
-
-
-
-
-
-
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
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
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
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
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
N/A
N/A
N/A
8.55
8.55
8.55
8.55
-
-
-
-
-
-
-
-
-
-
-
N/A
N/A
N/A
10.00
10.00
-
-
-
-
-
-
-
-
-
-
-
-
-
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
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
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
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
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
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
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
N/A
N/A
N/A
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
N/A
N/A
N/A
-
-
-
-
-
-
-
-
N/A
N/A
N/A
-
-
-
-
-
-
-
-
N/A
N/A
N/A
8.52
8.52
8.52
8.52
8.52
8.52
8.52
8.52
N/A
N/A
N/A
8.63
8.63
8.63
8.63
8.63
8.63
8.63
8.63
N/A
N/A
N/A
17.40
17.40
17.40
17.40
17.40
17.40
-
-
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
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
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
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
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
N/A
N/A
N/A
8.47
8.47
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
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
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
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
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
N/A
N/A
N/A
16.76
16.76
16.76
-
-
-
-
-
-
AP - 28
-
-
-
-
-
-
11.92
-
-
7.65
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
8.52
8.52
8.52
8.52
8.52
8.52
8.52
8.52
8.63
8.63
8.63
8.63
8.63
8.63
8.63
8.63
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Company Name:
Average Heat Rate - (mmBtu/MWh) (At Minimum)
Schedule 10b
(ACTUAL)
Unit Name
(PROJECTED)
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
N/A
Mecklenburg 1
N/A
Mecklenburg 2
N/A
Mount Storm 1
Mount Storm 2
N/A
N/A
Mount Storm 3
N/A
Mount Storm CT
N/A
North Anna 1
North Anna 2
N/A
North Anna Hydro
N/A
N/A
N/A
Pittsylvania
Possum Point 3
N/A
Possum Point 4
N/A
N/A
Possum Point 5
N/A
Possum Point 6
Possum Point CT 1-6
N/A
Remington 1
N/A
N/A
Remington 2
N/A
Remington 3
N/A
Remington 4
N/A
N/A
Roanoke Valley II
N/A
N/A
Rosemary
SEI Birchwood
N/A
N/A
N/A
Southampton
Spruance Genco, Facility 1 (Richmond 1) N/A
Spruance Genco, Facility 2 (Richmond 2) N/A
Surry 1
N/A
N/A
Surry 2
N/A
N/A
Warren
Yorktown 1
N/A
N/A
Yorktown 2
N/A
Yorktown 3
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
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
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
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
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
N/A
N/A
20.36
20.36
20.36
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
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
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
N/A
16.83
16.83
16.83
16.83
-
-
-
-
-
-
-
-
-
-
-
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
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
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
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
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
N/A
N/A
16.76
16.76
-
-
-
-
-
-
-
-
-
-
-
-
-
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
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
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
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
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
N/A
10.00
10.00
10.00
10.00
10.00
10.00
10.00
-
-
-
-
-
-
-
-
-
N/A
N/A
10.00
10.00
10.00
10.00
10.00
10.00
-
-
-
-
-
-
-
-
-
-
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
N/A
N/A
11.73
11.73
11.73
11.73
11.73
11.73
11.73
11.73
-
-
-
-
-
-
-
-
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
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
N/A
N/A
10.00
10.00
10.00
10.00
-
-
-
-
-
-
-
-
-
-
-
N/A
N/A
10.00
10.00
10.00
10.00
-
-
-
-
-
-
-
-
-
-
-
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
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
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
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
N/A
N/A
12.25
12.25
12.25
-
-
-
-
-
-
-
-
-
-
-
-
-
N/A
N/A
11.12
11.12
11.12
-
-
-
-
-
-
-
-
-
-
-
-
N/A
N/A
11.49
11.49
11.49
-
11.49
-
11.40
AP - 29
-
11.40
-
11.40
-
11.40
-
11.40
-
11.40
-
11.40
-
11.40
-
11.40
-
11.40
-
11.40
-
-
-
-
11.40
Appendix 3F – Existing Capacity
Company Name:
Schedule 7
CAPACITY DATA
(ACTUAL)
2011
2012
(PROJECTED)
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
(1)
I. Installed Capacity (MW)
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
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
4,020
4,020
4,020
4,020
c. He avy Fue l 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
1,576
1,576
1,576
1,576
d. Light Fue l 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
543
543
543
543
f. Natural Gas-Combine d 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
6,474
6,474
6,474
8,040
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
3,329
3,329
3,329
3,329
h. Hydro-Conve ntional
317
317
317
321
321
321
321
321
321
321
321
321
321
321
321
321
321
321
321
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
1,802
1,802
1,802
1,802
i. Pumped Storage
j. Re ne wable
k. Total Company Installed
l.
Othe r (NUG)
83
83
83
254
263
273
279
285
292
298
301
301
301
301
301
301
301
301
301
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
21,714
21,714
21,714
23,280
1,787
1,787
1,787
1,785
1,741
1,308
702
502
336
292
291
73
73
73
72
72
71
71
36
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
21,786
21,785
23,316
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%
15.4%
15.4%
15.4%
14.4%
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%
18.5%
18.5%
18.5%
17.2%
c. He avy Fue l 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%
7.2%
7.2%
7.2%
6.8%
d. Light Fue l 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%
2.5%
2.5%
2.5%
2.3%
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%
29.7%
29.7%
29.7%
34.5%
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%
15.3%
15.3%
15.3%
14.3%
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%
1.5%
1.5%
1.5%
1.4%
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%
8.3%
8.3%
8.3%
7.7%
j. Re ne wable
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%
1.4%
1.4%
1.4%
1.3%
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%
99.7%
99.7%
99.7%
99.8%
n. Total
II. Installed Capacity Mix (%)
(2)
k. Total Company Installed
l.
Othe r (NUG)
n. Total
-
-
-
-
-
-
-
-
-
-
-
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%
0.3%
0.3%
0.3%
0.2%
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%
100.0%
100.0%
100.0%
100.0%
(1) Net dependable installed capability during peak season.
(2) Each item in Section I as a percent of line n (Total).
AP - 30
Appendix 3G – Energy Generation by Type (GWh)
Company Name:
Schedule 2
GENERATION
(ACTUAL)
(PROJECTED)
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
a. Nuclear
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
28,207
27,618
27,696
28,207
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
22,214
22,533
21,388
21,215
250
164
119
300
245
179
150
174
205
222
224
195
175
183
184
190
204
200
215
85
74
45
22
14
9
4
3
1
-
-
-
-
-
-
-
-
-
-
135
180
146
656
588
408
334
418
362
379
393
410
415
410
420
416
440
411
369
I. System Output (GWh)
c. He avy Fuel Oil
d. Light Fuel Oil
e . Natural Gas-Boiler
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
29,932
29,466
29,843
35,721
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
1,700
1,766
1,652
1,530
661
580
1,025
601
601
601
601
601
601
601
601
601
601
601
601
601
601
601
601
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
1,739
1,924
1,921
1,465
i. Hydro-Pumpe d Storage
j. Re ne wable
(1)
k. Total Generation
l. Purchase d Power
m. Total Payback Ene rgy
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
2,306
2,279
2,238
2,284
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
87,307
86,832
85,952
91,608
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
15,433
16,846
18,766
15,974
-
-
12
11
10
17
19
21
22
20
21
21
21
22
22
22
22
22
-3,151
-3,097
-2,489
-1,559
-2,225
-2,005
-2,421
-1,395
-1,409
-1,800
-1,876
-1,928
-2,063
-2,128
-2,185
-2,418
-2,414
-1,841
(2)
n. Less Pumping Ene rgy
o. Less Other Sale s
393
60,050
(3)
p. Total System Firm Energy Req.
-3,015
-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
-2,197
-1,703
-1,517
-3,753
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
98,358
99,557
100,787
101,987
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
II. Energy Supplied by Competitive
Service Provide rs
(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.
AP - 31
N/A
N/A
Appendix 3H – Actual Energy Generation by Type (%)
Company Name:
Schedule 3
GENERATION
(ACTUAL)
2011
2012
(PROJECTED)
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
III. System Output Mix (%)
a. Nuclear
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%
28.7%
27.7%
27.5%
27.7%
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%
22.6%
22.6%
21.2%
20.8%
c. Heavy 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%
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%
0.0%
0.0%
0.0%
0.0%
e . Natural Gas-Boiler
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%
0.4%
0.4%
0.4%
0.4%
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%
30.4%
29.6%
29.6%
35.0%
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%
1.7%
1.8%
1.6%
1.5%
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%
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%
1.8%
1.9%
1.9%
1.4%
j. Rene wable 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%
2.3%
2.3%
2.2%
2.2%
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%
88.8%
87.2%
85.3%
89.8%
l. Purchased Power
15.7%
f. Natural Gas-Combined Cycle
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%
15.7%
16.9%
18.6%
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%
0.0%
0.0%
0.0%
0.0%
n. Le ss Pumping Energy
-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%
-2.2%
-2.4%
-2.4%
-1.8%
o. Le ss Othe r Sale s
(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%
-2.2%
-1.7%
-1.5%
-3.7%
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%
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%
55.7%
55.6%
55.6%
55.5%
(1) Economy energy.
AP - 32
Appendix 3I – Planned Changes to Existing Generation Units
Company Name:
Schedule 13a
(1)
Unit Size (MW) Uprate and Derate
(ACTUAL)
Unit Name
2011
2012
(PROJECTED)
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
Altavista
-
-
-12
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Bear Garde n
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Belle me ade
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Bre mo 3
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Bre mo 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 Comple x
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Edge combe Genco (Rocky Mountain)
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Elizabe th Rive r 1
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Elizabe th Rive r 2
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Elizabe th Rive r 3
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Gaston Hydro
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Ge ne ric CC 2019
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Ge ne ric CC 2029
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Ge ne ric CT 2022
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Ge ne ric CT 2023
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Gordonsville 1
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Gordonsville 2
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Gravel Neck 1-2
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Gravel Neck 3
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Gravel Neck 4
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Gravel Neck 5
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Gravel Neck 6
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Hope well
-
-
-12
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Hope well Cogen
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Incre mental Ne t Me te r
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Ladysmith 1
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Ladysmith 2
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Ladysmith 3
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Ladysmith 4
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Ladysmith 5
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Lowmoor CT 1-4
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
(1) Peak net dependable capability as of this filing. Incremental uprates shown as positive (+) and decremental derates shown as negative (-)
AP - 33
Appendix 3I Cont. – Planned Changes to Existing Generation Units
Unit Name
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
Me ckle nburg 1
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Me ckle nburg 2
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Mount Storm 1
-
Mount Storm 2
31
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Mount Storm 3
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Mount Storm CT
-
North Anna 1
-
-
23
30
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
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
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Re mington 1
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Re mington 2
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Re mington 3
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Re mington 4
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Roanoke Valley II
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Rose mary
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
SEI Birchwood
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Southampton
-
-
-12
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Surry 1
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Surry 2
40
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Virginia City Hybrid Ene rgy Ce nter
-
Warren
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Yorktown 1
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Yorktown 2
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Yorktown 3
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
(1) Peak net dependable capability as of this filing. Incremental uprates shown as positive (+) and decremental derates shown as negative (-)
AP - 34
Appendix 3I Cont. – Planned Changes to Existing Generation Units
Company Name:
S chedule 13b
(1)
Planned Changes to Existing Generation Units
S tation / Unit Name
Uprate/Derate Description
Expected
Removal
Date
Expected
Return
Date
Base
Rating
Revised
Rating
MW
Bremo 3
Fuel Switch
N/A
M ay-14
71
71
-
Bremo 4
Fuel Switch
N/A
Jun-14
156
156
-
(1) Peak net dependable capability as of this filing.
AP - 35
Appendix 3J – Potential Unit Retirements
Company Name:
Schedule 19
(1)
Planned Unit Retirements
Unit Name
Possum Point CT
Location
Dumfries, VA
Unit
P rimary
Type
Fuel Type
CombustionTurbine
Light Fuel Oil
P rojected
Retirement
Year
2015
MW
MW
Summer
Winter
72
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
Chesapeake 1
111
Chesapeake 2
111
Chesapeake 3
149
Chesapeake 4
207
96
578
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
Mt. S torm GT1
Northern Neck CT
11
Warsaw, VA
CombustionTurbine
Light Fuel Oil
2017
47
Northern Nec k GT1
12
Northern Nec k GT2
11
Northern Nec k GT3
12
Northern Nec k GT4
12
Chesapeake CT 1
Chesapeake, VA
CombustionTurbine
Light Fuel Oil
2019
Chesapeake GT1
Chesapeake CT 2
15
63
20
15
Chesapeake, VA
CombustionTurbine
Light Fuel Oil
2019
36
Chesapeake GT2
12
Chesapeake GT4
12
Chesapeake GT6
12
Gravel Neck 1
12
11
Surry, VA
CombustionTurbine
Light Fuel Oil
2019
28
Gravel Nec k GT1
12
Gravel Nec k GT2
16
(1) Reflects retirement assumptions used for planning purposes, not firm Company commitments.
AP - 36
49
38
Appendix 3K – Generation under Construction
Company Name:
Schedule 15a
Planned Supply-Side Resources (MW)
Unit Name
Location
Unit Type
Primary Fuel
Type
C.O.D.
(1)
MW
MW
Summer(3)
Nameplate
Under Construction
Brunswick County Powe r Station
Distributed
Intermitte nt
Solar
2016(2)
4
13
Warre n County, VA
Inte rmediate / Baseload
Natural Gas
Dec-2014
1,337
1,337
Brunswick County, VA
Inte rmediate / Baseload
Natural Gas
May-2016
1,375
1,375
(2) Phase 1 to be completed by 2015; Phase 2 to be completed by 2016.
(3) Firm capacity.
AP - 37
Appendix 3L – Wholesale Power Sales Contracts
Company Name:
Schedule 20
WHOLESALE POWER SALES CONTRACTS
(Actual)
Entity
Contract Length
Contract Type
2011
2012
(Projecte d)
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
North Carolina
Ele ctric
Me mbe rship
Coop
Non-Firm
12/31/2014
Partial Re quire me nts
150
150
150
150
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
6
6
7
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
9
9
9
11
11
11
11
11
11
11
11
12
12
12
12
12
12
12
13
358
344
338
338
339
341
345
350
355
359
365
369
374
378
381
385
389
393
397
12-Month
Craig-Bote tourt
Te rmination
Full
Ele ctric Coop
Notice
Re quire me nts
(1)
12-Month
Town of Windsor, Te rmination
Full
North Carolina
Notice
Re quire me nts
Ele ctric
5/31/2031
Full
Association
with annual re ne wal Re quire me nts
(1)
Virginia
Municipal
(1)
(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.
AP - 38
Appendix 3M – Description of Approved DSM Programs
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
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.
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
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 - 39
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.
Branded Name:
Distributed Generation
State:
Virginia
Target Class:
Commercial and Industrial
VA Program Type:
Demand-Side Management
VA Duration:
2012 – 2038
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 - 40
Target Class:
Non-residential
NC Program Type:
Energy Efficiency
VA Program Type:
Energy Efficiency
NC Duration:
2014 – 2038
VA Duration:
2012 – 2038
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
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 - 41
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.
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:
including but not limited to: direct mail, bill inserts, web content, social media and outreach events.
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
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
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 - 42
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
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:
including but not limited to: direct mail, bill inserts, web content, social media, and outreach events.
Target Class:
Non-Residential
VA Program Type:
Energy Efficiency
VA Duration:
2014 – 2038
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, LEDbased bulbs, and lighting control systems.
Program Marketing:
AP - 43
Target Class:
Non-Residential
VA Program Type:
Energy Efficiency
VA Duration:
2014 – 2038
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:
AP - 44
Appendix 3N – Approved Programs Non-Coincidental Peak Savings
(kW) (System-Level)
Programs
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
104,928
122,243
139,558
156,873
174,188
191,503
198,896
201,519
201,204
196,939
192,365
193,407
194,431
195,453
196,475
3,737
3,910
3,910
3,910
3,910
3,910
3,910
3,910
3,910
3,910
3,871
3,335
2,044
1,237
589
197,484
-
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
-
-
-
-
-
-
-
673
673
673
673
673
673
673
673
673
673
673
591
446
174
5,447
11,175
17,482
19,785
20,125
21,323
21,937
23,059
23,235
23,410
23,586
23,761
23,933
24,103
5,750
10,280
15,390
17,720
17,995
21,125
20,509
15,844
17,956
20,069
22,181
23,237
24,294
25,350
26,406
27,462
28,519
29,575
30,631
31,687
32,744
21,740
41,104
61,675
87,433
94,350
104,723
117,144
118,302
119,424
120,615
121,610
122,679
123,732
124,775
125,813
126,838
624
1,053
1,507
1,709
1,736
1,764
18,471
1,784
18,604
1,798
18,733
1,812
18,858
1,917
18,981
1,840
19,102
1,854
19,221
1,868
19,339
24,442
18,274
24,273
1,881
19,457
1,894
19,575
1,908
1,141
2,994
5,059
6,018
6,130
6,243
6,327
6,387
6,446
6,505
6,564
6,622
6,679
6,735
6,791
6,847
9,035
15,908
23,145
32,611
35,373
41,480
49,871
50,327
50,771
51,210
51,649
52,088
52,519
52,940
53,356
53,771
10,941
21,149
31,964
47,094
51,112
55,237
59,163
59,790
60,394
60,983
61,556
62,115
62,667
63,219
63,771
64,313
395
2,766
7,244
12,954
19,173
20,983
21,073
21,226
21,422
21,615
21,804
21,991
22,178
22,365
22,550
22,733
1,299
5,780
11,701
18,394
25,190
28,823
29,179
29,458
29,733
30,003
30,268
30,530
30,790
31,051
31,310
31,566
2,567
8,546
14,649
20,841
28,038
28,235
28,468
28,752
29,026
29,294
29,557
29,816
30,072
30,327
30,582
30,835
Note: Residential Bundle Program includes Residential Home Energy Check-Up Program, Residential Duct & Sealing Program, Residential Heat Pump Tune Up Program, and Residential Heat
Pump Upgrade Program.
AP - 45
Appendix 3O – Approved Programs Coincidental Peak Savings
(kW) (System-Level)
Programs
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
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
195,282
196,305
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
476
154
197,317
-
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
-
-
-
-
-
-
-
673
673
673
673
673
673
673
673
673
673
673
586
342
88
-
-
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
23,915
24,083
24,250
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
19,339
19,457
19,575
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
30,191
31,247
32,304
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
68,944
69,522
70,090
504
966
1,476
1,709
1,736
1,764
1,784
1,798
1,812
1,826
1,840
1,854
1,868
1,881
1,894
1,908
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
6,735
6,791
6,847
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
13,340
13,444
13,548
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
46,987
47,392
47,788
142
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
29,146
29,389
29,629
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
30,305
30,561
30,814
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
418,243
421,445
424,874
Total
2,091
5,903
11,010
16,679
19,266
19,393
19,506
19,687
19,865
20,040
20,212
20,384
20,556
20,727
20,896
AP - 46
Appendix 3P – Approved Programs Energy Savings
(MWh) (System-Level)
Programs
2014
2015
2016
-
-
9,166
9,964
2017
-
9,964
2018
2019
-
-
9,964
9,964
2020
-
9,964
2021
2022
-
-
9,964
9,964
2023
2024
9,964
2025
-
-
9,964
9,355
7,031
4,310
2,447
-
276,824
276,824
276,824
276,824
240,142
177,744
112,436
36,496
121,206
121,513
121,206
121,206
121,206
110,634
65,709
16,403
-
-
-
-
-
-
-
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
539
-
-
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
116,107
116,923
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
71,297
71,895
98
1
1
7
13
3
7
15
15
11
18
28
42
175
333
20
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
268,878
271,121
273,330
1,861
3,627
5,584
6,576
6,680
6,786
6,865
6,921
6,975
7,029
7,083
7,137
-
-
798
276,824
-
2029
-
121,206
-
2028
-
-
2027
-
Commercial Lighting
-
2026
-
7,189
7,241
-
7,292
-
117,737
72,168
7,343
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
9,616
9,696
9,775
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
78,952
79,570
80,186
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
173,069
174,563
176,027
Total
8,112
23,255
43,714
66,503
77,532
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
36,500
36,804
37,105
3,027
673
20,591
42,047
63,877
87,783
99,716
100,457
78,076
101,468
78,510
102,439
79,240
103,389
79,956
104,321
80,661
105,238
81,355
106,142
82,047
107,043
82,740
107,944
83,428
108,840
84,107
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
685,727
689,246
693,306
AP - 47
Appendix 3Q – Approved Programs Penetrations
(System-Level)
Programs
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
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
186,495
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
2,000
-
-
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
-
-
-
-
-
-
127
127
127
127
127
127
127
127
127
127
127
99
40
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
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
187,470
188,427
-
-
-
-
-
5,754
5,794
5,834
2,295
2,309
2,323
20
13
15
17
19
21
22
23
24
25
26
27
28
29
30
31
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
409,593
412,849
416,080
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
11,644
11,726
11,807
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
21,834
22,013
22,193
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
281,083
283,269
285,449
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
95,032
95,841
96,632
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
5,508,856
5,554,282
5,598,992
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
3,923
3,955
Total
3,987
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
8,102
8,170
8,237
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
6,127,048
6,174,860
6,223,912
AP - 48
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
2027
2028
2029
-
427
1,274
2,121
2,972
4,084
5,136
5,193
5,247
5,300
5,352
5,403
5,452
5,502
5,552
5,601
-
876
2,253
3,631
5,121
6,672
7,279
7,357
7,433
7,507
7,579
7,649
7,720
7,790
7,860
7,928
-
5,739
15,569
28,284
43,296
60,100
67,800
68,448
69,081
69,704
70,315
70,919
71,520
72,122
72,720
73,310
AP - 49
Appendix 3S – Proposed Programs Coincidental Peak Savings
(kW) (System-Level)
Programs
2014
2015
-
2016
100
2017
756
1,450
2018
2,147
2019
2,845
2020
3,156
2021
3,189
2022
3,222
2023
3,254
2024
3,286
2025
3,316
2026
3,347
2027
3,377
2028
3,407
2029
3,437
-
283
1,902
3,462
5,022
6,582
7,279
7,357
7,433
7,507
7,579
7,649
7,720
7,790
7,860
7,928
-
2,381
15,215
28,284
43,296
60,100
67,800
68,448
69,081
69,704
70,315
70,919
71,520
72,122
72,720
73,310
Total
-
2,765
17,872
33,196
50,465
69,527
78,234
78,994
79,736
80,465
81,180
81,885
82,587
83,290
83,987
84,675
AP - 50
Appendix 3T– Proposed Programs Energy Savings
Programs
2014
2015
-
2016
508
3,100
2017
6,130
2018
9,168
2019
12,213
2020
13,759
2021
13,907
2022
14,051
2023
14,191
2024
14,327
2025
14,461
2026
14,594
2027
14,727
2028
14,859
2029
14,988
-
1,790
9,941
18,342
26,742
35,143
39,178
39,600
40,009
40,407
40,795
41,175
41,553
41,932
42,307
42,674
-
3,925
21,522
40,409
62,139
86,473
98,515
99,457
100,379
101,284
102,174
103,052
103,926
104,801
105,670
106,528
Total
-
6,223
34,563
64,881
98,050
133,829
151,451
152,964
154,438
155,882
157,296
158,688
160,073
161,460
162,836
164,190
AP - 51
Appendix 3U – Proposed Programs Penetrations
(System-Level)
Programs
2014
2015
-
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2,110
6,290
10,470
14,670
18,870
19,079
19,280
19,476
19,666
19,852
20,035
20,219
20,402
20,582
20,758
52,663
-
6,564
16,891
27,218
37,545
47,872
48,402
48,912
49,408
49,892
50,363
50,828
51,293
51,759
52,216
-
976
2,357
3,994
5,838
7,894
7,971
8,046
8,120
8,192
8,263
8,333
8,404
8,474
8,544
8,613
Total
-
9,650
25,538
41,682
58,053
74,636
75,452
76,238
77,003
77,751
78,479
79,197
79,916
80,636
81,343
82,034
AP - 52
Appendix 3V– Generation Interconnection Projects under Construction
Line Voltage
Line Capacity
Interconnection Cost
(kV)
(MVA)
(Million $)
V2-030
500
3,424
7.8
Dec-14
VA
X2-076
500
3,424
89.1
May-15
VA
Line Terminal
PJM Queue
Warren
Carson - Wake
AP - 53
Target Date Location
Appendix 3W – List of Transmission Lines under Construction
Line
Line Terminal
Line
Voltage Capacity Target Date Location
(kV)
(MVA)
115
261
Sep-14
NC
115
180
Oct-14
VA
500
4,334
Dec-14
VA
115
261
Apr-15
VA
230
751
May-15
NC
230
1,047
May-15
VA
230
1,047
Jun-15
NC
230
Jun-15
NC
115
262
Jun-15
VA/NC
230
1,047
Jun-15
VA
115
239
Jun-15
VA
115
231
Jul-15
VA
115
230
Jul-15
VA
115
233
Dec-15
VA
500
4,000
Jun-16
VA
230
1,047
Jun-16
VA
115
353
Jun-16
VA
AP - 54
775 (#2131)
840(#2126)
Appendix 4A –
ICF Commodity Price
Forecasts for Dominion
Virginia Power
June 2014 Forecast
AP - 55
NOTICE PROVISIONS FOR AUTHORIZED THIRD PARTY USERS. All third parties authorized to use the Deliverables must agree to comply with the
following terms:
IMPORTANT NOTICE:
REVIEW OR USE OF THIS REPORT BY ANY PARTY OTHER THAN THE CLIENT CONSTITUTES ACCEPTANCE OF THE FOLLOWING TERMS. Read these terms
carefully. They constitute a binding agreement between you and ICF Resources, LLC (“ICF”). By your review or use of the report, you hereby agree to
the following terms.
Any use of this report other than as a whole and in conjunction with this disclaimer is forbidden.
This report may not be copied in whole or in part or distributed to anyone.
This report and information and statements herein are based in whole or in part on information obtained from various sources. ICF makes no
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NO WARRANTY, WHETHER EXPRESS OR IMPLIED, INCLUDING THE IMPLIED WARRANTIES OF MERCHANTABILITY AND FITNESS FOR A PARTICULAR
PURPOSE IS GIVEN OR MADE BY ICF IN CONNECTION WITH THIS REPORT.
You use this report at your own risk. ICF is not liable for any damages of any kind attributable to your use of this report.
AP - 56
COPYRIGHT © 2014 ICF Resources, LLC. All rights reserved.
Basecase Price Forecast (2013 Real $)
Note: The 2015 - 2017 prices are a blend of futures/forwards and forecast prices for all commodities except emission and capacity prices. 2018 and beyond are forecast prices.
Capacity prices reflect PJM RPM auction clearing prices through delivery year 2017/18, forecast thereafter. Emission prices are forecasted for all years.
AP - 57
Basecase and Scenario Price Forecast; Natural Gas
Note: The 2015-2017 prices are a blend of futures/forwards and forecast prices. 2018 and beyond are forecast prices.
AP - 58
Basecase and Scenario Price Forecast; Natural Gas
Note: The 2015 - 2017 prices are a blend of futures/forwards and forecast prices. 2018 and beyond are forecast
prices.
AP - 59
Basecase and Scenario Price Forecast; Coal: FOB
prices.
AP - 60
Basecase and Scenario Price Forecast; Oil
prices.
AP - 61
Basecase and Scenario Price Forecast; Oil
prices.
AP - 62
Basecase and Scenario Price Forecast; On-Peak Power Price
prices.
AP - 63
Basecase and Scenario Price Forecast; Off-Peak Power Price
prices.
AP - 64
Basecase and Scenario Price Forecast; PJM Tier 1 Renewable Energy Certificates
prices.
AP - 65
Basecase and Scenario Price Forecast; PJM RTO Capacity
Note: PJM RPM auction clearing prices through delivery year 2017/18, forecast thereafter.
AP - 66
Basecase and Scenario Price Forecast; SO2 Emission Allowances
AP - 67
Basecase and Scenario Price Forecast; NOx Emission Allowances
AP - 68
Basecase and Scenario Price Forecast; NOx Emission Allowances
AP - 69
Basecase and Scenario Price Forecast; CO2
AP - 70
Appendix 4B – Delivered Fuel Data
Company Name:
Schedule 18
FUEL DATA
(ACTUAL)
(PROJECTED)
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
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
0.77
0.78
0.79
0.80
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
3.41
3.48
3.55
3.63
c. He avy Fue l 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
17.10
17.78
18.48
19.20
d. Light Fuel Oil
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
25.24
26.23
27.25
28.30
e . Natural 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
6.95
7.26
7.51
7.92
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
3.78
3.85
3.93
4.02
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
0.83
0.84
0.85
0.86
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
4.20
4.28
4.37
4.47
c. He avy Fue l 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
22.70
20.75
23.56
23.09
d. Light Fuel Oil
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
N/A
N/A
N/A
N/A
e . Natural 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
5.19
5.43
5.60
5.93
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
5.76
5.87
6.00
6.12
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
N/A
N/A
N/A
N/A
(1)
I. Delivered Fuel Price ($/mmBtu)
(2)
f. Re ne wable
(3)
(4)
II. Primary Fuel Expenses (cents/kWh)
(2)
f. Re ne wable
(3)
(5)
g. NUG
i. Economy Ene rgy Purchase s
(6)
j. Capacity Purchase s ($/kW-Year)
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
4.78
5.05
5.30
5.39
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
94.80
94.85
95.01
95.16
(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 Oil and Natural Gas
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, Pittsylvania, respectively.
(5) Average of NUGs Fuel Expenses.
(6) Average cost of Market Energy Purchases.
AP - 71
Appendix 5A - Tabular Results of Busbar
Capacity Factor (%)
$/kW-Year
CT
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
$67
$161
$255
$348
$442
$536
$630
$724
$818
$912
$1,005
CC 3x1
$139
$204
$268
$333
$397
$462
$527
$591
$656
$720
$785
Nuclear
$1,136
$1,146
$1,157
$1,168
$1,179
$1,190
$1,200
$1,211
$1,222
$1,233
$1,244
Fuel Cell
$1,040
$1,101
$1,161
$1,222
$1,282
$1,343
$1,404
$1,464
$1,525
$1,585
$1,646
Biomass
$909
$957
$1,005
$1,054
$1,102
$1,151
$1,199
$1,248
$1,296
$1,345
$1,393
Solar - Fixed Tilt
$329
$320
$312
$303
N/A
N/A
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
N/A
N/A
Solar - Tag
$275
$266
$257
$248
N/A
N/A
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
N/A
N/A
Offshore Wind
$1,324
$1,314
$1,304
$1,295
$1,285
N/A
N/A
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
$2,423
$2,538
SCPC with CCS
$754
$878
$1,001
$1,125
$1,248
$1,371
$1,495
$1,618
$1,741
$1,865
$1,988
IGCC without CCS
$881
$939
$997
$1,055
$1,113
$1,171
$1,228
$1,286
$1,344
$1,402
$1,460
SCPC without CCS
$465
$531
$598
$664
$731
$797
$864
$930
$997
$1,063
$1,130
AP - 72
Appendix 5B - Busbar Assumptions
Nominal $
Heat Rate
MMBtu/MWh
Variable
(1)
Fixed Cost
$/MWh
$/kW-Year
Cost
Book
2014
Life
Real $
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
(1) Variable cost for Biomass, Solar - Fixed Tilt, Solar - Tracking, Solar Tag, Onshore Wind or Offshore Wind include value for RECs.
AP - 73
Appendix 5C – Planned Generation under Development
Company Name:
Schedule 15c
Planned Supply-Side Resources (MW)
Unit Name
Under Development
Location
Unit Type
Primary Fuel
Type
C.O.D.
(2)
MW
MW
Summer
Nameplate
(1)
Offshore Wind De monstration Proje ct
VA
Ge ne ric CC 2019
N/A
Inte rmitte nt
Inte rme diate / Ba se load
Wind
Natural Gas-CC
11
(3)
2018
2
2019
1,566
1,566
1,453
North Anna 3
Mine ra l, VA
Base load
Nucle ar
2028
1,453
Solar Tag 2017
N/A
Inte rmitte nt
Solar
2017
2
4
Solar Tag 2020
N/A
Inte rmitte nt
Solar
2020
13
35
Solar 2017
N/A
Inte rmitte nt
Solar
2017
15
40
Solar 2018
N/A
Inte rmitte nt
Solar
2018
15
40
Solar 2019
N/A
Inte rmitte nt
Solar
2019
15
40
Solar 2020
N/A
Inte rmitte nt
Solar
2020
15
40
Solar 2021
N/A
Inte rmitte nt
Solar
2021
15
40
Solar 2022
N/A
Inte rmitte nt
Solar
2022
15
40
Solar 2023
N/A
Inte rmitte nt
Solar
2023
15
40
Solar 2024
N/A
Inte rmitte nt
Solar
2024
15
40
Solar 2025
N/A
Inte rmitte nt
Solar
2025
15
40
Solar 2026
N/A
Inte rmitte nt
Solar
2026
15
40
Solar 2027
N/A
Inte rmitte nt
Solar
2027
15
40
Solar 2028
N/A
Inte rmitte nt
Solar
2028
15
40
Solar 2029
N/A
Inte rmitte nt
Solar
2029
15
40
Wind 1: 2022
N/A
Inte rmitte nt
Wind
2022
16
120
Wind 2: 2023
N/A
Inte rmitte nt
Wind
2023
10
81
Wind 3: 2024
N/A
Inte rmitte nt
Wind
2024
6
46
(2) Estimated Commercial Operation Date.
(3) Accounts for line losses.
AP - 74
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 - 75
Appendix 5E – DSM Programs Energy Savings
(MWh)
(System-Level)
Company Name:
Virginia Electric & Power Company
Schedule 12
Energy Efficiency/Energy Efficiency- Demand Response/Peak Shaving/Demand Side Management (MWh)
ACTUAL - MWh
Program Type
(1)
Peak Shaving
Sub-total
Energy Efficiency Demand Response
Program Name
Date
Life/
(2)
Duration
2010
2029
Size (kW)
(4)
2011
197,317
197,317
2012
(PROJECTED - MWh)
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
2010
2029
32,304
609
1
1
7
13
3
7
15
15
11
18
28
42
175
333
20
1987
2029
5
32,309
308
917
355
355
227
227
227
325
227
228
227
228
227
234
227
240
227
230
227
234
227
242
227
242
227
238
227
245
227
255
227
269
227
402
227
560
227
247
Residential Lighting Program
Commercial Lighting Program
2010
2010
2010
2028
2022
2022
-
2,831
228,892
51,149
4,053
228,892
72,620
5,300
228,892
72,620
9,166
276,824
121,206
9,964
276,824
121,206
9,964
276,824
121,513
9,964
276,824
121,206
9,964
276,824
121,206
9,964
240,142
121,206
9,964
177,744
110,634
9,964
112,436
65,709
9,964
36,496
9,964
-
Commercial HVAC Program
2010
2010
2012
2027
2029
2029
-
5,113
24,250
19,575
-
5,936
29
70
5,936
3,613
1,659
3,656
20,249
20,221
3,656
49,652
37,337
3,660
80,068
56,261
3,656
95,092
65,309
3,656
96,733
66,323
3,656
101,951
67,351
3,660
104,661
68,246
3,656
111,075
68,586
3,656
111,924
69,060
3,656
112,770
69,522
3,660
113,616
70,134
3,227
114,457
70,422
2010
2012
2029
2029
70,090
1,908
-
526
20
11,359
945
37,655
1,861
94,523
3,627
157,717
5,584
198,020
6,576
215,382
6,680
237,979
6,786
252,399
6,865
254,896
6,921
257,322
6,975
259,701
7,029
262,040
7,083
2012
2012
2029
2029
6,847
13,548
-
8
328
105
4,474
1,384
10,694
4,094
24,458
7,089
39,791
8,589
49,906
8,748
55,927
8,910
66,880
9,032
74,413
9,118
75,084
9,203
75,740
9,287
76,393
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
Standby Generation & Curtailable Service (Pricing Tariffs)
(5)
Sub-total
Energy Efficiency
(3)
(6)
-
-
98
1
16,403
9,355
7,031
4,310
2,447
798
-
-
-
-
-
-
-
-
-
-
-
-
-
-
1,947
115,287
70,861
539
116,107
71,297
-
-
-
116,923
71,895
117,737
72,168
264,340
7,137
266,615
7,189
268,878
7,241
271,121
7,292
273,330
7,343
9,371
77,046
9,455
77,694
9,536
78,329
9,616
78,952
9,696
79,570
9,775
80,186
168,539
170,055
171,561
173,069
174,563
176,027
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
81,355
82,047
82,740
83,428
84,107
Non-Residential Heating & Cooling Efficiency Program
2014
2014
2029
2029
30,814
29,629
-
-
-
3,027
-
-
-
884
20,591
6,762
42,047
14,393
63,877
22,268
87,783
30,259
99,716
33,899
100,457
34,303
101,468
34,631
102,439
34,952
103,389
35,269
104,321
35,580
105,238
35,888
106,142
36,194
107,043
36,500
107,944
36,804
108,840
37,105
Non-Residential Custom Incentive Program
Residential Appliance Recycling
Non Residential Small Business Audit
2014
2014
2014
2014
2014
2029
2029
2029
2029
2029
87,824
73,387
18,342
40,409
6,130
1,126,020
342,777
136,539
26,742
62,139
9,168
1,551,997
660,151
200,562
35,143
86,473
12,213
1,987,937
977,526
264,585
39,178
98,515
13,759
2,333,705
1,294,900
271,115
39,600
99,457
13,907
2,559,911
1,612,275
273,425
40,009
100,379
14,051
2,761,594
1,919,246
275,736
40,407
101,284
14,191
3,025,090
2,064,390
278,050
40,795
102,174
14,327
3,179,102
1,916,362
280,336
41,175
103,052
14,461
3,037,344
1,916,362
282,586
41,553
103,926
14,594
3,042,424
1,916,362
284,821
41,932
104,801
14,727
3,048,194
1,916,362
287,047
42,307
105,670
14,859
3,055,159
1,916,362
289,269
42,674
106,528
14,988
3,063,107
1,126,253
1,552,237
1,988,167
2,333,939
2,560,153
2,761,836
3,025,328
3,179,347
3,037,600
3,042,693
3,048,596
3,055,718
3,063,354
-
5,923
25,195
21,862
35,104
40,757
-
-
-
-
1,790
-
-
-
Sub-total
73,589
7,928
73,310
3,437
353,518
293,908
337,321
351,241
528,665
0
508
675,607
40,757
23,845
9,941
21,522
3,100
884,868
Total Demand Side Management
583,144
294,825
337,676
351,468
528,989
0
675,835
885,095
-
3,925
(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-Up Program, and Residential
Heat Pump Upgrade Program.
AP - 76
Appendix 5F – Description of Future DSM Programs
Voltage Conservation
Target Class:
NC Program Type:
VA Program Type:
NC Duration:
VA Duration:
All Classes
Energy Efficiency
Energy Efficiency
2016 – 2038
2009 – 2038
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
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
This Program provides income and age-qualifying residential customers with energy assessments
and direct install measures at no cost to the customer.
AP - 77
Appendix 5F Cont. – Description of Future DSM Programs
Target Class:
Residential
NC Program Type:
Energy Efficiency
VA Program Type:
Energy Efficiency
NC Duration:
2016 – 2038
VA Duration:
2015 – 2038
This program provides incentives to residential customers to recycle specific types of qualifying
appliances. Appliance pick-up and proper recycling services are included.
Target Class:
Non-Residential
NC Program Type:
Energy Efficiency
VA Program Type:
Energy Efficiency
NC Duration:
2016 – 2038
VA Duration:
2015 – 2038
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 - 78
Appendix 5G – Future Programs Non-Coincidental Peak Savings
(kW) (System-Level)
Programs
Non-Residential Custom Incentive
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
6,860
7,965
7,690
17,162
66,984
129,004
184,437
253,044
315,064
375,051
389,504
374,488
374,488
374,488
361,574
374,488
-
-
7,593
23,369
43,479
63,867
84,254
86,334
87,069
87,805
88,542
89,270
89,987
90,698
91,407
92,115
AP - 79
Appendix 5H – Future Programs Coincidental Peak Savings
(kW) (System-Level)
Programs
2014
2015
2016
-
-
2017
-
2018
-
2019
-
2020
-
2021
-
2022
-
2023
-
2024
-
2025
-
2026
-
2027
-
2028
-
2029
-
-
-
-
6,066
18,669
34,735
51,022
67,310
68,971
69,559
70,147
70,735
71,317
71,889
72,458
73,024
73,589
Total
-
-
6,066
18,669
34,735
51,022
67,310
68,971
69,559
70,147
70,735
71,317
71,889
72,458
73,024
73,589
AP - 80
Appendix 5I – Future Programs Energy Savings
Programs
Total
2014
2015
35,104
2016
40,757
40,757
2017
87,824
2018
2019
342,777
660,151
2020
977,526
2021
1,294,900
2022
1,612,275
2023
1,919,246
2024
2,064,390
2025
1,916,362
2026
1,916,362
2027
1,916,362
2028
1,916,362
2029
1,916,362
-
-
23,845
73,387
136,539
200,562
264,585
271,115
273,425
275,736
278,050
280,336
282,586
284,821
287,047
289,269
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
2,201,183
2,203,409
2,205,631
AP - 81
Appendix 5J – Future Programs Penetrations
(System-Level)
Programs
Total
2014
2015
77,273
2016
77,273
-
-
77,273
77,273
2017
77,273
2018
195,045
666,131
2019
2020
1,137,217
1,608,304
2021
2,079,390
2022
2,550,476
2023
2,903,791
2024
2,946,240
2025
2,946,240
2026
2,946,240
2027
2,946,240
2028
2,946,240
2029
2,946,240
219
674
1,254
1,842
2,430
2,490
2,511
2,532
2,554
2,575
2,595
2,616
2,636
2,657
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
2,948,855
2,948,876
2,948,896
AP - 82
Appendix 5K – Planned Generation Interconnection Projects
Line Terminal
PJM Queue
* North Anna – Ladysmith
Q-65
Line Voltage
Line
Interconnection Cost
Target
(kV)
Capacity
(Million $)
Date
500
4,300
48
Apr-24
*Subject to change based on receipt of applicable regulatory approval(s).
AP - 83
Location
VA
Appendix 5L – List of Planned Transmission Lines
Line Voltage
Line Capacity
(kV)
(MVA)
115
261
Sep-14
NC
115
180
Oct-14
VA
Cannon Branch to Cloverhill - New 230kV Line
230
1,047
Dec-14
VA
500
4,334
Dec-14
VA
115
261
Apr-15
VA
Line Terminal
Target Date
Location
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
230
751
May-15
NC
230
1,047
May-15
VA
Yadkin - Chesapeake increase 115 kV Capacity
115
398
Jun-15
VA
Jun-15
NC
775 (#2131)
230
Line 32 Rebuild
115
240
Jun-15
VA
230
1,047
Jun-15
NC
115
262
Jun-15
NC/VA
115
239
Jun-15
VA
230
1,047
Jun-15
VA
115
231
Jul-15
VA
Line #222 Uprate from Northwest to Southwest
230
706
Jul-15
VA
115
230
Jul-15
VA
Line #201 Rebuild
230
1,200
Nov-15
VA
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
500
4,000
Jun-16
VA
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
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
840(#2126)
Note: Asterisk reflects planned transmission addition subject to change based on inclusion in future PJM RTEP and/or receipt of applicable
regulatory approval(s).
AP - 84
Appendix 6A – Renewable Resources
Company Name:
Schedule 11
RENEWABLE RESOURCE GENERATION (GWh)
(ACTUAL)
Resource Type
(1)
Unit Name
C.O.D.
(2)
Build/Purchase/
Convert
(3)
Life/
(PROJECTED)
Size
(4)
Duration
MW
(5)
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
Hydro
Cushaw Hy dro
Jan-30
Build
60
2
Gasto n Hydro
Feb-63
Build
60
220
No rth Anna Hydro
Dec -87
Build
60
1
2
3
1
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Roano ke Rapids Hydro
S ep-55
Build
60
98
185
159
300
292
292
292
292
292
292
292
292
292
292
292
292
292
292
292
292
321
391
345
616
601
601
601
601
601
601
601
601
601
601
601
601
601
601
601
601
16
Sub-total
5
9
14
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
199
175
301
292
292
292
292
292
292
292
292
292
292
292
292
292
292
292
292
Solar
S olar Partnership Prog ram
Existing S olar NC NUGs with PPAs
Future S olar NC Nugs
2013-2016
Build
20
13
-
-
-
1
9
16
16
16
16
16
16
16
16
16
16
16
16
16
2014
Purchase
15
100
-
-
-
188
187
187
185
184
183
183
181
181
180
179
178
177
176
176
-
2015-2016
Purchase
15
100
-
-
-
-
94
188
187
186
185
184
183
182
181
181
179
178
177
177
176
213
-
-
-
188
281
375
372
370
368
367
364
363
361
360
357
355
354
353
176
83
393
341
369
278
102
86
262
343
466
465
414
491
555
603
610
595
582
565
565
Sub-total
Biomass
Unit Name
Pittsylvania
Jun-94
Virg inia City Hybrid Energy Center (6 )
Apr-12
Build
60
61
-
-
11
130
214
267
321
370
401
476
446
429
463
439
415
460
444
420
461
Altavista
Feb-92
Co nvert
30
51
-
-
145
359
417
410
417
408
417
410
417
408
417
410
417
408
417
410
417
S outhampton
Mar-92
Co nvert
30
51
-
-
56
384
417
418
417
417
417
418
417
417
417
393
416
417
415
418
417
Jul-92
Co nvert
30
51
-
-
85
400
392
410
417
417
410
411
410
409
408
407
405
410
404
409
409
-
Purchase
-
Hopewell
Covanta Fairfax
Purchase
Sub-total
Total Renewables
60
63
600
580
553
351
197
-
-
-
-
-
-
-
-
-
-
-
-
-
-
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
2,253
2,263
2,290
2,263
2,222
2,268
1,713
1,493
1,835
2,621
2,566
2,806
2,926
3,079
3,148
3,068
3,118
3,221
3,214
3,221
3,247
3,218
3,177
3,046
894
2,692
(1) Per definition of § 56-576 of the Code of Virginia.
(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.
AP - 85
Appendix 6B – Potential Supply-Side Resources
Company Name:
Schedule 15b
Potential Supply-Side Resources (MW)
Unit Name
MW
MW
Summer
Nameplate
457
457
2023
457
457
2029
1,566
1,566
(1)
Location
Unit Type
Primary Fuel Type
C.O.D.
Gene ric CT 2022
N/A
Pe ak
Natural Gas-Turbine
2022
Gene ric CT 2023
N/A
Pe ak
Natural Gas-Turbine
Gene ric CC 2029
N/A
Interme diate / Base load Natural Gas-CC
(1) Estimated Commercial Operation Date.
AP - 86
***Confidential Information Redacted***
Appendix 6C – Summer Capacity Position
Company Name:
Schedule 16
Virginia Ele ctric a nd Powe r Compa ny
UT ILIT Y CAPACIT Y POSIT ION (MW)
(ACTUAL)
Exis ting Ca pa city
Conve ntiona l
Re ne wa ble
Tota l Exis ting Ca pa city
Ge ne ra tion Unde r Cons truction
Conve ntiona l
Re ne wa ble
Tota l Pla nne d Cons truction Ca pa city
Ge ne ra tion Unde r De ve lopme nt
Conve ntiona l
Re ne wa ble
Tota l Pla nne d De ve lopme nt Ca pa city
Pote ntia l (Expe cte d) Ne w Ca pa city
Conve ntiona l
Re ne wa ble
Tota l Pote ntia l Ne w Ca pa city
Othe r (NUG)
Unforce d Ava ila bility
Net Generation Capacity
2012
2013
16,531
17,140
17,265
2015
17,102
2016
16,445
2017
16,054
16,001
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
15,995
15,910
15,904
15,901
15,901
15,901
15,901
15,901
15,901
15,901
15,901
15,901
400
400
400
575
581
591
597
603
609
615
618
618
618
618
618
618
618
618
618
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
16,519
16,519
16,519
1,337
2,712
2,712
2,712
2,712
2,712
2,712
2,712
2,712
2,712
2,712
2,712
2,712
2,712
2,712
-
-
-
-
-
-
-
0.2
2
-
-
-
0.2
1,339
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
1,566
1,566
1,566
1,566
1,566
1,566
1,566
1,566
1,566
1,566
1,566
-
-
-
-
-
-
-
-
-
-
-
457
914
914
914
914
914
914
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
457
914
914
914
914
914
914
1,787
-
1,787
-
(1)
1,787
-
19,327
6
-
Tota l Exis ting DSM Re ductions
2014
16,931
18,718
Exis ting DSM Re ductions
De ma nd Re s pons e
Cons e rva tion/Efficie ncy
(PROJ ECTED)
2011
19,451
7
-
6
1,785
4
2,716
1,566
1,566
1,566
1,566
4
2,716
1,566
4
2,716
1,566
1,566
1,566
1,566
4
2,716
1,566
2,480
-
73
73
73
-
-
-
-
-
-
-
-
-
-
-
21,137
21,092
21,092
21,331
21,787
21,787
21,786
21,786
21,786
21,785
23,316
5
5
-
5
-
5
5
-
5
5
-
5
5
5
5
5
5
-
5
5
-
5
5
-
5
5
-
5
71
2,480
-
5
71
4
2,716
19,815
-
72
4
2,716
-
5
72
4
2,716
20,016
5
291
4
2,716
-
-
292
4
2,716
20,668
5
336
1,566
4
2,716
-
5
502
4
2,716
20,107
-
702
4
2,716
-
5
1,308
4
2,716
19,462
5
-
7
1,741
4
2,716
5
-
5
36
5
-
5
5
-
5
5
Approve d DSM Re ductions
(4)
(2)(4)
Tota l Approve d DSM Re ductions
51
83
123
136
152
171
190
210
219
219
218
218
219
221
223
225
228
230
36
40
47
83
65
104
148
180
204
215
212
203
192
188
190
191
192
193
194
195
87
123
130
188
240
300
351
395
425
431
422
410
406
409
412
415
418
421
425
Future DSM Re ductions
(4)
(2)
Tota l Future DSM Re ductions
(1)
T otal Demand-Side Reductions
Net Generation & Demand-side
Ca pa city Sa le
(3)
Ca pa city Purcha s e
(3)
Ca pa city Adjus tme nt
(3)
-
-
-
-
-
-
-
-
3
24
52
85
121
146
148
149
151
152
153
154
156
157
158
-
-
-
-
3
24
52
85
121
146
148
149
151
152
153
154
156
157
158
93
130
135
18,811
19,457
19,586
188
19,651
-
243
20,350
-
-
-
-
-
473
854
909
1,636
-
-
-
214
(89)
274
99
(1,814)
20,051
(727)
20,988
(1,501)
480
20,295
-
20,657
-
403
-
20,419
-
Net Utility Capacity Position
-
324
20,992
-
-
Capacity Requirement or
PJM Capacity Obligation
-
-
-
546
-
-
577
21,683
21,669
-
570
-
559
-
557
-
561
565
-
570
-
574
-
578
-
583
21,662
21,890
22,344
22,348
22,352
22,356
22,360
22,364
23,899
-
-
-
-
-
-
-
-
-
168
433
718
989
-
-
-
-
-
(900)
(600)
340
139
91
-
-
-
-
1
1
-
1
-
1
-
1
20,272
21,009
22,003
21,922
20,346
20,586
20,802
21,312
21,550
22,006
22,007
22,176
22,443
22,729
23,001
23,546
473
854
909
1,636
340
(761)
(509)
1
1
1
1
168
433
718
989
1
(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.
AP - 87
Appendix 6D – Construction Forecast
Company Name:
Schedule 17
CONSTRUCTION COST FORECAST (Thousand Dollars)
(PROJECTED)
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
725,130
317,990
773,681
637,753
294,394
71,517
205,321
207,602
40,596
4,446
76,976
727,252
646,245
352,585
112,902
4,188
5,079
4,238
3,913
5,899
131
569
466
3
13
152
1,523
3,864
5,567
177
(3)
I. New Traditional Generating Facilities
a. Construction Expe nditure (Not AFUDC)(2)
b. AFUDC
(1)
864,642
1,800
c. 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
650,109
358,151
113,079
866,442
d. 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
4,758,941
5,117,092
5,230,171
6,096,613
12,804
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
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
12,806
12,806
12,806
12,806
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
824,875
849,621
875,110
901,363
b. Distribution
624,470
600,343
571,157
583,641
612,037
623,050
623,050
623,050
641,741
660,994
680,823
701,248
722,286
743,954
766,273
789,261
12,347
15,199
178,724
178,845
154,463
14,441
14,875
15,321
15,781
16,254
16,742
17,244
17,761
18,294
18,843
19,408
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
27,210
31,914
32,104
25,060
33,086
42,325
41,405
33,840
34,855
35,901
36,978
38,087
39,230
40,407
41,619
42,867
f. 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
1,604,151
1,652,276
1,701,844
1,752,899
g. 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
19,368,946
21,021,222
22,723,066
24,475,966
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
2,254,260
2,010,427
1,814,923
2,619,342
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
24,140,693
26,151,120
27,966,043
30,585,385
II. New Renewable Generating Facilities
a. Construction Expe nditure (Not AFUDC)
b. AFUDC
(1)
III. Other Facilities
c. Ene rgy Conse rva tion & DR(3)
d. Othe r
e . AFUDC
IV. Total Construction Expenditures
V. % of Funds for Total Construction
Provided from External Financing
N/A
N/A
N/A
N/A
N/A
N/A
N/A
(1) Does not include Construction Work in Progress.
(2) The construction expenditure includes both modeled and budgeted expenditures.
AP - 88
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
***Confidential Information Redacted***
Appendix 6E – Capacity Position
Company Name:
Schedule 4
POWER SUPPLY DATA
(ACTUAL)
(PROJECTED)
2011
2012
2013
2014
2015
2016
2017
2018
2019
16,931
17,540
17,665
17,677
18,366
19,361
19,314
19,314
1,749
1,747
1,747
1,785
1,741
1,308
702
502
2020
2021
2022
2023
2024
2025
2026
20,801
20,801
20,801
21,257
21,714
21,714
21,714
336
292
291
73
73
73
2027
2028
2029
I. Capability (MW)
1. Summer
a. Installed Net Dependable
Capacity
(1)
21,714
21,714
21,714
23,280
b. Positive Interchange
Commitme nts
(2)
72
72
71
71
36
c. Capability in Cold Reserve/
Re serve Shutdown Status
(1)
d. Demand Re sponse - Existing
e. Demand Re sponse - Approved(5)
f. De mand Response - Future (5)
g. Capacity Sale
(3)
h. Capacity Purchase
(3)
i. Capacity Adjustment
(3)
j. Total Ne t Summer Capability
(4)
105
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
6
7
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
51
83
83
123
136
152
171
190
210
219
219
218
218
219
221
223
225
228
230
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-900
-600
-
-
-
-
-
-
-
-
-
-
-
-
473
854
909
1,636
340
139
91
1
1
1
1
168
433
718
989
1
-
-
-
214
274
99
-
-
-
-
-
-
-
-
-
-
-
-
18,731
19,370
19,495
20,267
21,004
(89)
21,998
21,917
20,341
20,581
20,797
21,307
21,545
22,001
22,002
22,171
22,438
22,724
22,996
23,541
-
-
-
18,361
19,133
19,189
20,306
20,243
22,702
22,595
22,595
23,058
23,521
23,521
23,521
23,521
23,521
23,521
25,160
-
-
-
1,943
1,945
1,367
1,367
441
441
273
228
6
6
6
6
6
6
6
3
2. Winter
a. Installed Net De pendable
Capacity
(1)
b. Positive Inte rchange
Commitments
(2)
c. Capability in Cold Rese rve/
Rese rve Shutdown Status
d. Demand Response
(1)
(5)
e. Demand Response-Existing(6)
f. Total Ne t Winter Capability
(4)
77
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
10
16
15
21
17
15
17
19
21
23
24
25
26
27
28
29
30
31
32
8
6
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
-
-
-
20,325
21,094
20,571
21,690
20,702
23,164
22,891
22,847
23,089
23,553
23,554
23,555
23,556
23,557
23,558
25,195
(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.
(6) Included in the winter capacity forecast.
AP - 89

integrated resource plan

Transcription

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