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INTEGRATED RESOURCE PLANNING REPORT
TO THE
KENTUCKY PUBLIC SERVICE COMMISSION
CASE NO. 2016-00413
VOLUME A PUBLIC VERSION
December 20, 2016
KPSC Case No. 2016-00413 2016 Integrated Resource Plan
Of Kentucky Power Company Volume A - Public Version
Page 1 of 1497
INTEGRATED RESOURCE PLANNING REPORT
TO THE
KENTUCKY PUBLIC SERVICE COMMISSION
CASE NO. 2016-00413
VOLUME A PUBLIC VERSION
PAGES 2-199 of 1497
December 20, 2016
KPSC Case No. 2016-00413 2016 Integrated Resource Plan
Of Kentucky Power Company Volume A - Public Version
Page 2 of 1497
Table of Contents
LIST OF FIGURES .................................................................................................................... VI
LIST OF TABLES ................................................................................................................... VIII
EXECUTIVE SUMMARY .......................................................................................................... 1
INTRODUCTION ................................................................................................................ 1 1.0
1.1 Overview .................................................................................................................................................. 1
1.2 Integrated Resource Plan (IRP) Process .................................................................................................... 1
1.3 Introduction to Kentucky Power .............................................................................................................. 2
1.4 Power Coordination Agreement (PCA) ..................................................................................................... 3
1.5 The Impact of Coal Mining on KPCo Service Territory ............................................................................... 4
1.6 Significant Changes from the 2013 IRP ..................................................................................................... 5
LOAD FORECAST AND FORECASTING METHODOLOGY .................................... 8 2.0
2.1 Summary of KPCo Load Forecast .............................................................................................................. 8
2.2 Forecast Assumptions .............................................................................................................................. 8 2.2.1 Economic Assumptions ................................................................................................................................ 8 2.2.2 Price Assumptions ....................................................................................................................................... 9 2.2.3 Specific Large Customer Assumptions ......................................................................................................... 9 2.2.4 Weather Assumptions ................................................................................................................................. 9 2.2.5 Demand Side Management (DSM) Assumptions ......................................................................................... 9
2.3 Overview of Forecast Methodology ....................................................................................................... 10
2.4 Detailed Explanation of Load Forecast ................................................................................................... 12 2.4.1 General ...................................................................................................................................................... 12 2.4.2 Customer Forecast Models ........................................................................................................................ 13 2.4.3 Short-term Forecasting Models ................................................................................................................. 13 2.4.4 Long-term Forecasting Models .................................................................................................................. 14 2.4.4.1 Supporting Models ................................................................................................................................. 15
2.4.4.1.1 Consumed Natural Gas Pricing Model ................................................................................................ 15 2.4.4.1.2 Regional Coal Production Model ........................................................................................................ 15
2.4.4.2 Residential Energy Sales ......................................................................................................................... 16
KPSC Case No. 2016-00413 2016 Integrated Resource Plan
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2.4.4.3 Commercial Energy Sales ....................................................................................................................... 18 2.4.4.4 Industrial Energy Sales ........................................................................................................................... 18
2.4.4.4.1 Manufacturing Energy Sales ............................................................................................................... 18 2.4.4.4.2 Mine Power Energy Sales ................................................................................................................... 18
2.4.4.5 All Other Energy Sales ............................................................................................................................ 19 2.4.5 Internal Energy Forecast ............................................................................................................................ 19 2.4.5.1 Blending Short and Long-Term Sales...................................................................................................... 19 2.4.5.2 Losses and Unaccounted-For Energy ..................................................................................................... 19
2.4.6 Forecast Methodology for Seasonal Peak Internal Demand ..................................................................... 20
2.5 Load Forecast Results and Issues ............................................................................................................ 20 2.5.1 Load Forecast ............................................................................................................................................. 21 2.5.2 Peak Demand and Load Factor .................................................................................................................. 21 2.5.3 Weather Normalization ............................................................................................................................. 21
2.6 Load Forecast Trends & Issues ............................................................................................................... 21 2.6.1 Changing Usage Patterns ........................................................................................................................... 21 2.6.2 Demand-Side Management (DSM) Impacts on the Load Forecast ............................................................ 24 2.6.3 Interruptible Load ...................................................................................................................................... 24 2.6.4 Blended Load Forecast............................................................................................................................... 25 2.6.5 Large Customer Changes ........................................................................................................................... 26 2.6.6 Wholesale Customer Contracts ................................................................................................................. 26
2.7 Load Forecast Scenarios ......................................................................................................................... 26
2.8 Energy-Price Relationships ..................................................................................................................... 27
2.9 Significant Changes from Previous Forecast ........................................................................................... 29 2.9.1 Energy Forecast ......................................................................................................................................... 29 2.9.2 Peak Internal Demand Forecast ................................................................................................................. 30 2.9.3 Forecasting Methodology .......................................................................................................................... 30
2.10 Additional Load Information .................................................................................................................. 30
2.11 Data-Base Sources.................................................................................................................................. 31
2.12 Other Topics ........................................................................................................................................... 31 2.12.1 Residential Energy Sales Forecast Performance ........................................................................................ 31 2.12.2 Peak Demand Forecast Performance ........................................................................................................ 32 2.12.3 Forecast Data and Model Results .............................................................................................................. 32 2.12.4 Forecast Updates ....................................................................................................................................... 32 2.12.5 KPSC Staff Recommendations Addressed .................................................................................................. 33
RESOURCE EVALUATION ............................................................................................ 34 3.0
3.1 Current Supply-Side Resources............................................................................................................... 34
3.2 Environmental Issues and Implications .................................................................................................. 37
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3.2.1 Mercury and Air Toxics Standards (MATS) ................................................................................................ 37 3.2.2 Cross-State Air Pollution Rule (CSAPR) ...................................................................................................... 39 3.2.3 National Ambient Air Quality Standards (NAAQS) ..................................................................................... 40 3.2.4 Coal Combustion Residuals (CCR) Rule ...................................................................................................... 40 3.2.5 Effluent Limitations Guidelines .................................................................................................................. 41 3.2.6 Clean Water Act 316(b) Rule ..................................................................................................................... 41 3.2.7 New Source Review Consent Decree ......................................................................................................... 42 3.2.8 Carbon Dioxide (CO2) Regulations, Including the Clean Power Plan (CPP) ................................................ 44
3.3 Current Demand-Side Programs ............................................................................................................. 47 3.3.1 Impacts of Existing and Future Codes and Standards ................................................................................ 47 3.3.2 Demand Response (DR) ............................................................................................................................. 49 3.3.2.1 Existing Levels of Active Demand Response (DR) ................................................................................... 51
3.3.3 Energy Efficiency (EE) ................................................................................................................................. 51 3.3.3.1 Existing Levels of Energy Efficiency (EE) ................................................................................................. 53
3.3.4 Distributed Generation (DG) ...................................................................................................................... 53 3.3.4.1 Existing Levels of Distributed Generation (DG) ...................................................................................... 57 3.3.4.2 Cogeneration / Combined Heat and Power (CHP) ................................................................................. 57
3.3.5 Volt VAR Optimization (VVO) ..................................................................................................................... 58 3.3.6 KPSC Staff DSM Recommendations Addressed ......................................................................................... 59
3.4 AEP-PJM & Kentucky Power Transmission ............................................................................................. 63 3.4.1 General Description ................................................................................................................................... 63 3.4.2 Transmission Planning Process .................................................................................................................. 65 3.4.3 System-Wide Reliability Measure .............................................................................................................. 66 3.4.4 Evaluation of Adequacy for Load Growth .................................................................................................. 66 3.4.5 Evaluation of Other Factors ....................................................................................................................... 67 3.4.6 Transmission Expansion Plans ................................................................................................................... 67 3.4.7 FERC Form 715 Information ....................................................................................................................... 67 3.4.8 Kentucky Transmission Projects ................................................................................................................ 69
3.5 Distribution ............................................................................................................................................ 70
MODELING PARAMETERS .......................................................................................... 72 4.0
4.1 Modeling and Planning Process An Overview ...................................................................................... 72
4.2 Methodology ......................................................................................................................................... 73
4.3 Fundamental Modeling Input Parameters .............................................................................................. 73 4.3.1 Commodity Pricing Scenarios .................................................................................................................... 75 4.3.1.1 Emission Reduction Credit (ERC) Pricing ................................................................................................ 75 4.3.1.2 Mid Scenario .......................................................................................................................................... 76 4.3.1.3 Low Band Scenario ................................................................................................................................. 76 4.3.1.4 High Band Scenario ................................................................................................................................ 77 4.3.1.5 No Carbon Scenario ................................................................................................................................ 77 4.3.1.6 Forecasted Fundamental Parameters .................................................................................................... 77
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4.4 PJM Capacity Performance Rule Impacts ............................................................................................... 81
4.5 Demand-Side Management (DSM) Program Screening & Evaluation Process ........................................ 82 4.5.1 Overview .................................................................................................................................................... 82 4.5.2 Levels of Energy Efficiency (EE) Potential .................................................................................................. 82 4.5.3 Evaluating Incremental Demand-Side Resources ...................................................................................... 83 4.5.3.1 Incremental Energy Efficiency (EE) Modeled ......................................................................................... 83 4.5.3.2 Volt VAR Optimization (VVO) Modeled .................................................................................................. 86 4.5.3.3 Demand Response (DR) Modeled .......................................................................................................... 87 4.5.3.4 Distributed Generation (DG) .................................................................................................................. 88 4.5.3.5 Combined Heat and Power (CHP) .......................................................................................................... 89
4.6 Identify and Screen Supply-side Resource Options ................................................................................. 89 4.6.1 Capacity Resource Options ........................................................................................................................ 89 4.6.2 New Supply-side Capacity Options ............................................................................................................ 90 4.6.3 Base/Intermediate Options ....................................................................................................................... 91 4.6.3.1 Natural Gas Combined Cycle (NGCC) ..................................................................................................... 92
4.6.4 Peaking Options ......................................................................................................................................... 92 4.6.4.1 Simple Cycle Combustion Turbines (NGCT)............................................................................................ 93 4.6.4.2 Aeroderivatives (AD) .............................................................................................................................. 93 4.6.4.3 Reciprocating Engines (RE) ..................................................................................................................... 94 4.6.4.4 Battery Storage ...................................................................................................................................... 95
4.6.5 Renewable Options .................................................................................................................................... 96 4.6.5.1 Solar ....................................................................................................................................................... 96
4.6.5.1.1 Large-Scale Solar ................................................................................................................................. 96 4.6.5.1.2 Trends in Solar Energy Pricing ............................................................................................................ 98
4.6.5.2 Wind ....................................................................................................................................................... 99 4.6.5.3 Hydro .................................................................................................................................................... 102 4.6.5.4 Biomass ................................................................................................................................................ 102
4.7 Integration of Supply-Side and Demand-Side Options within Plexos Modeling ................................... 102 4.7.1 Optimization of Other Demand-Side Resources ...................................................................................... 103
RESOURCE PORTFOLIO MODELING ..................................................................... 104 5.0
5.1 The Plexos Model - An Overview ......................................................................................................... 104 5.1.1 Key Input Parameters .............................................................................................................................. 105
5.2 Plexos Optimization ............................................................................................................................ 106 5.2.1 Modeling Options and Constraints .......................................................................................................... 106 5.2.2 Optimization Scenarios ............................................................................................................................ 108 5.2.2.1 Optimized Portfolios of Commodity Pricing Scenarios ........................................................................ 109 5.2.2.2 Optimized Portfolios of Load Scenarios ............................................................................................... 110
5.3 Preferred Plan ...................................................................................................................................... 111 5.3.1 Demand-Side Program Levels .................................................................................................................. 112 5.3.2 Comparing the Cost of the Preferred Plan ............................................................................................... 113 5.3.3 Rate Impacts of the Preferred Plan ......................................................................................................... 115
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5.3.4 Comparing Costs of Clean Power Plan Compliance ................................................................................. 117 5.3.5 Risk Analysis ............................................................................................................................................. 118 5.3.5.1 Stochastic Modeling Process and Results ............................................................................................ 119
SUMMARY AND CONCLUSIONS ............................................................................... 122 6.0
6.1 Conclusion ........................................................................................................................................... 128
KPSC Case No. 2016-00413 2016 Integrated Resource Plan
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List of Figures
Figure 1. Kentucky Power Service Territory ...................................................................................3
Figure 2. Economic Impact of Lost Mining Load on KPCo Regional Economy ............................4
Figure 3. KPCo Internal Energy Requirements and Peak Demand Forecasting Method ..............11
Figure 4. Eastern Kentucky Coal Production (Millions of Tons) 2000-2015................................16
Figure 5. KPCo Normalized Use per Customer (kWh) .................................................................22
Figure 6. Projected Changes in Cooling Efficiencies, 2010-2030 .................................................23
Figure 7. Projected Changes in Lighting and Clothes Washer Efficiencies, 2010-2030 ...............23
Figure 8. Load Forecast Blending Illustration ...............................................................................25
Figure 9. KPCo "Going-In" Capacity Position throughout Planning Period (2017-2031) ............36
Figure 10. Total Energy Efficiency (GWh) Compared with Total Residential and
Commercial Load (GWh) ............................................................................................49
Figure 11. Residential and Commercial Forecasted Solar Installed Costs (Nominal $/WAC)
for Kentucky ................................................................................................................54
Figure 12. Breakeven Cost vs. Forecasted Installation Costs for Residential Rooftop Solar
System; Discount Rate = 10%; Capacity Factor = 19.7% ...........................................55
Figure 13. Breakeven Cost vs. Forecasted Installation Costs for Residential Rooftop Solar
System; Discount Rate = 10%; Capacity Factor = 16% ..............................................56
Figure 14. Range of Residential Distributed Solar Breakeven Values Based on Discount
Rate; Capacity Factor = 19.7% ....................................................................................57
Figure 15. Volt VAR Optimization Schematic ..............................................................................58
Figure 16. Long-term Power Price Forecast Process Flow ............................................................74
Figure 17. Dominion South Natural Gas Prices (Nominal $/mmBTU) .........................................78
KPSC Case No. 2016-00413 2016 Integrated Resource Plan
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Figure 18. Dominion South Natural Gas Prices (2015 Real $/mmBTU) ......................................78
Figure 19. NAPP High Sulfur Coal Prices (Nominal $/ton, FOB origin) .....................................79
Figure 20. CO2 Prices (Nominal $/short ton).................................................................................79
Figure 21. PJM On-Peak Energy Prices (Nominal $/MWh) .........................................................80
Figure 22. PJM Off-Peak Energy Prices (Nominal $/MWh) .........................................................80
Figure 23. PJM Capacity Prices (Nominal $/MW-Day) ................................................................81
Figure 24. Energy Efficiency Bundle Levelized Cost vs. Potential Energy Savings for 2019......86
Figure 25. KPCo Forecasted Rooftop Solar Installations ..............................................................88
Figure 26. Large-Scale Solar Pricing Tiers with Investment Tax Credits .....................................98
Figure 27. U.S. Average Solar Photovoltaic (PV) Installation Cost (Nominal $/WAC) Trends,
excluding Investment Tax Credit Benefits ..................................................................99
Figure 28. Levelized Cost of Electricity (LCOE) of Wind Resources (Nominal $/MWh) .........101
Figure 29. KPCo Energy Efficiency Savings According to Preferred Plan ................................113
Figure 30. Bill Impacts ($/Month) of Preferred Plan Compared to Do Nothing Plan .................115
Figure 31. Range of Variable Inputs for Stochastic Analysis ......................................................119
Figure 32. Revenue Requirement at Risk (RRaR) ($000) for Preferred Plan and Do Nothing
Plan ............................................................................................................................120
Figure 33. 2017 KPCo Nameplate Capacity Mix ........................................................................123
Figure 34. 2031 KPCo Nameplate Capacity Mix ........................................................................123
Figure 35. 2017 KPCo Energy Mix .............................................................................................124
Figure 36. 2031 KPCo Energy Mix .............................................................................................124
Figure 37. KPCo Annual PJM Capacity Position (MW) According to Preferred Plan ...............126
Figure 38. KPCo Annual Energy Position (GWh) According to Preferred Plan.........................126
KPSC Case No. 2016-00413 2016 Integrated Resource Plan
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List of Tables
Table 1. PJM Energy and Capacity Prices in 2013 IRP and 2016 IRP, in 2011 $ ..........................6
Table 2. Natural Gas and Coal Prices in 2013 IRP and 2016 IRP, in 2011 $ ..................................6
Table 3. KPCo Existing Supply-Side Resources ...........................................................................35
Table 4. Consent Decree Annual NOx Cap for AEP-East.............................................................43
Table 5. Modified Consent Decree Annual SO2 Cap for AEP-East .............................................44
Table 6. Modified Consent Decree Annual SO2 Cap for Rockport Plant .....................................44
Table 7. KPCo State Mass-Based Clean Power Plan Goals ..........................................................46
Table 8. KPCo State Rate-Based Clean Power Plan Goals ...........................................................46
Table 9. Forecasted View of Relevant Residential Energy Efficiency Code Improvements ........48
Table 10. Forecasted View of Relevant Non-Residential Energy Efficiency Code
Improvements ..............................................................................................................48
Table 11. Energy Efficiency Market Barriers ................................................................................52
Table 12. Efficiency Potential for Industrial Sector, as Provided by AEG in the 2015 KPCO
Market Potential Study ................................................................................................62
Table 13. Incremental Residential Energy Efficiency (EE) Bundle Summary .............................84
Table 14. Incremental Commercial Energy Efficiency (EE) Bundle Summary ............................85
Table 15. Volt VAR Optimization (VVO) Tranche Profiles .........................................................87
Table 16. Incremental Demand Response (DR) Resource Blocks ................................................87
Table 17. New Generation Technology Options with Key Assumptions ......................................91
Table 18. Optimization Scenarios ................................................................................................109
Table 19. Cumulative PJM Capacity Additions (MW) and Energy Positions (GWh) for Mid,
Low Band, High Band, and No Carbon Scenarios ....................................................110
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Table 20. Cumulative PJM Capacity Additions (MW) and Energy Positions (GWh) for Low
and High Load Scenarios ...........................................................................................111
Table 21. Cumulative PJM Capacity Additions (MW) and Energy Positions (GWh) for
Preferred Plan.............................................................................................................112
Table 22. Approximate Rate Impacts of Preferred Plan ..............................................................116
Table 23. Estimated Costs of Mass-Based and Rate-Based Compliance with Clean Power
Plan (CPP) ..................................................................................................................118
Table 24. Risk Analysis Factors and Relationships .....................................................................119
Table 25. Preferred Plan Capacity Additions throughout Planning Period (2017-2031) ............127
KPSC Case No. 2016-00413 2016 Integrated Resource Plan
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Executive Summary
This Integrated Resource Plan (IRP, Plan, or Report) is submitted by Kentucky Power
Company (KPCo or Company) based upon the best information available at the time of its
preparation. However, changes that impact this Plan can occur without notice. Therefore, as with
any planning document, this Plan is not a commitment by the Company to specific resource
additions or other courses of action, since the future is highly uncertain, particularly in light of
current economic and political conditions, the movement towards increasing use of renewable
generation and end-use efficiency, as well as current and future environmental regulations,
including the U.S. Environmental Protection Agencys (EPA) Final Clean Power Plan (CPP).
An IRP explains how a utility company plans to meet the projected capacity (i.e., peak
demand) and energy requirements of its customers. KPCo is required to provide an IRP that
encompasses a 15-year forecast period (in this filing, 2017-2031). KPCo plans to aggressively
pursue economic development throughout its service territory, however, this IRP does not
include any assumptions for economic development opportunities, but rather, has been
developed using the Companys current long-term assumptions for:
customer load requirements peak demand and energy;
commodity prices coal, natural gas, on-peak and off-peak power prices, capacity
and emission prices;
supply-side alternative costs including fossil fuel and renewable resources; and
demand-side program costs and impacts.
In addition, KPCo considered the effect of environmental rules and guidelines, such as
the CPP, which could add significant costs and present significant challenges to operations. The
CPP is still being reviewed by the courts, and individual state plans to implement it may not be
finalizedlet alone approvedfor a number of years. In preparing this Report, KPCo has analyzed
multiple scenarios, with differing commodity pricing conditions, as well as multiple internal load
conditions. KPCo has also conducted analyses which specifically address certain aspects of
compliance with the CPP.
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Summary of KPCo Resource Plan
KPCos customers consist of both retail and wholesale customers located in the Eastern
portion of the Commonwealth of Kentucky. Currently, KPCo serves approximately 168,000
retail customers. The peak load requirement of KPCos total retail and wholesale customers is
seasonal in nature, with distinctive peaks occurring in the summer and winter seasons. KPCos
all-time highest recorded peak demand was 1,685 MW, which occurred in January 2005; and the
highest recorded summer peak was 1,358 MW, which occurred in July 2005.
Over the next 15 year period (2017-2031)1, KPCos service territory is expected to see
population and non-farm employment decline 0.1% per year. KPCo is projected to see its
customer count decline at a similar rate of 0.2% per year. Over the same forecast period, KPCos
retail sales are projected to decline at 0.2% per year with growth expected from the industrial
class (+0.1% per year) while the residential class experiences a decline (0.5% per year) over the
forecast period. Finally, KPCos internal energy and peak demand are expected to decline at an
average rate of 0.2% and 0.3% per year, respectively, through 2031.
KPCos IRP provides adequate supply and demand resources to meet its peak load and
energy obligations for the next fifteen years. The key intial assumptions in developing this plan
are for Kentucky Power to:
continue operation of the Mitchell Plant (KPCo share 780 MW);
continue operation through 2030 of Big Sandy Unit 1 (285 MW) which was
converted to burn natural gas instead of coal;
continue to receive power under the Unit Power Agreement (UPA) from the
Rockport Units (393 MW);
add cost-effective wind and large-scale solar as needed to continue to
diversify its mix of supply-side resources;
incorporate demand-side resources, including but not limited to additional
1 15 year forecast periods begin with the first full forecast year, 2017.
KPSC Case No. 2016-00413 2016 Integrated Resource Plan
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Energy Efficiency (EE) programs and Volt VAR Optimization (VVO)
installations; and
Residential and commercial customers will add distributed resources,
primarily in the form of residential and commercial rooftop solar.
Additionally, KPCo evaluated other supply- and demand-side measures and, as a result,
expects that there will be opportunities for utility-scale storage (i.e. batteries) and Combined
Heat and Power (CHP) resources in the KPCo service territiory within the next 10 years. KPCo
also expects that customer-owned solar generation will continue to expand, further reducing the
requirements for new utility-owned generation.
The Rockport Plant UPA for 393 MW expires at the end of 2022. While KPCo is
assuming, for purposes of this IRP, that the UPA will be renewed and continue through the
planning period, the actual decision to extend the UPA will be made in the future. KPCo is
currently committed to this purchase through 2022, and there remains much uncertainty with
regard to load growth, carbon regulations, commodity pricing, and the future UPA cost.
KPCo can meet its customers requirements with existing resources and modest
investments in renewable resources and energy efficiency. Figure ES-1 below present KPCos
Going-In capacity position. The Going-In position represents how KPCos existing and
planned capacity resources would compare with the capacity requirements absent any
incremental changes in capacity.
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Figure ES-1. KPCo "Going-In" PJM Capacity Position (MW)
To determine the appropriate level and mix of incremental supply-side and demand-side
resources to include in its portfolio, KPCo utilized the Plexos Linear Program optimization
model to develop least cost resource portfolios under a variety of pricing and load scenarios.
Although the IRP planning period is limited to 15 years (through 2031), the Plexos modeling
was performed through the year 2035, so as to properly consider various cost-based end-
effects for the resource alternatives being considered.
KPCo used the results of the modeling to develop a Preferred Plan. To arrive at the
Preferred Plan composition, KPCo developed six Plexos-derived, optimum portfolios under
four long-term commodity price forecasts, and two load sensitivity forecasts. The Preferred
Plan is presented as an option that attempts to balance cost and other factors while meeting
KPCos peak load obligations. In addition, this IRP considers existing and future environmental
requirements, including those that may result from the CPP, and the practical limitations of
customer self-generation.
In summary, the Preferred Plan:
KPSC Case No. 2016-00413 2016 Integrated Resource Plan
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invests $6 million/year in demand-side management through 2024;
adds 75 MW (nameplate capacity)/year of wind resources beginning in 2018 for
a total of 300 MW through 2021;
adds utility scale solar, beginning with 10 MW in 2019, for a total of 130 MW
by 2031.
implements customer and grid EE programs, including VVO, reducing energy
requirements by over 90 GWh and 70 MW of capacity by 2031;
assumes KPCos customers add Distributed Generation (DG) (i.e. rooftop solar)
capacity totaling 1.1 MW (nameplate) by 20312;
adds 10MW (nameplate) of battery storage resources in 2025;
assumes a host facility is identified such that a CHP project can be implemented
by 2022;
continues operation of KPCos existing generation facilities including Big
Sandy 1 through 2030, and the KPCo share of the Mitchell Units (West
Virginia), and
continues the UPA for a 15% share of the energy and capacity from the
Rockport Plant (Indiana)..
Specific KPCo capacity changes over the 15-year planning period associated with the
Preferred Plan are shown in Figure ES-2 and Figure ES-3, and their relative impacts on KPCos
annual energy position are shown in Figure ES-4 and Figure ES-5 .
2 KPCo does not have control over the amount, location or timing of these additions
KPSC Case No. 2016-00413 2016 Integrated Resource Plan
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Figure ES-2. 2017 KPCo Nameplate Capacity Mix
Figure ES-3. 2031 KPCo Nameplate Capacity Mix
KPSC Case No. 2016-00413 2016 Integrated Resource Plan
Of Kentucky Power Company Volume A - Public Version
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Figure ES-4. 2017 KPCo Energy Mix
Figure ES-5. 2031 KPCo Energy Mix
Figure ES-2 through Figure ES-5 indicate that this Preferred Plan would reduce KPCos
reliance on coal-based generation and increase reliance on demand-side (EE, CHP, VVO) and
renewable resources, further diversifying the portfolio. Specifically, over the 15-year planning
KPSC Case No. 2016-00413 2016 Integrated Resource Plan
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horizon the Companys nameplate capacity mix attributable to coal-fired assets would decline
from 80% to 71.3%. Natural Gas capacity would be 0% by 2031. Wind and solar assets climb
from 0% to 26%, and demand-side resources (including EE, VVO, DG, Demand Response [DR],
and CHP) increase from 0.5% to 2.5% over the planning period.
KPCos energy output attributable to coal-fired generation shows a decrease from 94.9%
to 82% over the period. The Preferred Plan shows a significant increase in renewable energy
(wind and solar), from 0% to 14.9%. Energy from these renewable resources, combined with EE
and VVO energy savings reduce KPCos exposure to energy, fuel and potential carbon prices.
Figure ES-6 and Figure ES - 7 show annual changes in capacity and energy mix,
respectively, that result from the Preferred Plan. The capacity contribution from renewable
resources is fairly modest due to their intermittent performance, as well as the implications of
PJMs Capacity Performance rule; however, those resources (particularly wind) provide a
significant volume of energy. KPCos model selected those wind resources because they were
lower cost than alternative resources. When comparing the capacity values in Figure ES-6 with
those in Figure ES-2 and Figure ES-3, it is important to note that Figure ES-6 provides an
analysis of PJM-recognized capacity, while Figure ES-2 and Figure ES-3 depict nameplate
capacity.
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Figure ES-6. KPCo Annual PJM Capacity Position (MW) According to Preferred Plan
Figure ES - 7. KPCo Annual Energy Position (GWh) According to Preferred Plan
KPSC Case No. 2016-00413 2016 Integrated Resource Plan
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Table ES-1 below provides a summary of the Preferred Plan.
Table ES-1. Preferred Plan Capacity Additions throughout Planning Period (2017-2031)
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
(10)
(11)
(12)
(13)
(14)
=(1)
to(1
3) e
xcl(5
)(1
5)(1
6)(1
7)(1
8)(1
9)(2
0)
(Cum
ulat
ive)
(Cum
ulat
ive)
Exis
ting
Flee
tEx
istin
g Fl
eet
(Cum
ul.)
VVO
DRW
ind
(D)
Batt
ery(
F)N
ETW
ind(
D)Ba
tter
y(F)
IRP
Perio
d
PJM
Pl
anni
ng
Year
(A)
Unit
Upra
tes &
De
rate
s
PJM
Cap
acity
Pe
rfor
man
ce
Impa
ct (U
CAP
Redu
ctio
n)N
G CH
PN
G C
C
Embe
dded
Fe
dera
l EE
Regu
latio
ns
(Non
-DSM
EE)
(B
)
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ms(C
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(A) P
JM P
lann
ing
Year
is e
ffect
ive
6/1/
XXXX
.
(C) R
epre
sent
s est
imat
ed co
ntrib
utio
n fr
om cu
rren
t/kn
own
KPCo
DSM
-EE
and
Dem
and
Resp
onse
(Int
erru
ptib
le, D
LC/E
LM) p
rogr
am a
ctiv
ity th
roug
h 20
18; v
alue
s are
bas
elin
ed fr
om 2
016
(D) D
ue to
the
inte
rmitt
ency
of w
ind
reso
urce
s, K
PCo
assu
mes
5%
of n
amep
late
' MW
ratin
g ar
e in
clude
d fo
r cap
acity
reso
urce
det
erm
inat
ion
purp
oses
bey
ond
2020
.(E
) Due
to th
e in
term
itten
cy o
f sol
ar re
sour
ces,
Util
ity a
nd D
istrib
uted
Sol
ar re
ceiv
e 38
% o
f nam
epla
te M
W ra
ting
for c
apac
ity re
sour
ce d
eter
min
atio
n pu
rpos
es.
(F) D
ue to
the
inte
rmitt
ency
of b
atte
ry/s
tora
ge re
sour
ces,
KPC
o as
sum
es 5
0% o
f nam
epla
te M
W ra
ting
for c
apac
ity re
sour
ce d
eter
min
atio
n pu
rpos
es.
Chan
ges t
o ex
istin
g re
sour
ces P
ost-J
une
1, 2
017:
(G) R
ockp
ort 1
turb
ine
upgr
ade.
(H) R
ockp
ort 2
turb
ine
upgr
ade.
(I) R
ockp
ort 1
FGD
par
asiti
c loa
d in
crea
se.
(J) R
ockp
ort 2
FGD
par
asiti
c loa
d in
crea
se.
(K)
Inclu
des c
hang
es in
exis
ting
reso
urce
s plu
s pla
n ad
ditio
ns, e
xclu
ding
colu
mn
5 "e
mbe
dded
" EE
and
exist
ing
DR p
rogr
ams.
(L)
PJM
min
imum
crite
rion
@16
.5%
as a
func
tion
of p
eak
dem
and
effe
ctiv
e w
ith th
e 20
19/2
0 PY
(pre
viou
sly @
15.
7%).
(M) B
ig S
andy
1 G
as C
onve
rsio
n un
it re
tirem
ent
Kent
ucky
Pow
er C
ompa
ny
131
(Cum
ulat
ive)
'N
AMEP
LATE
' ADD
ITIO
NS
New
-Bui
ldEn
ergy
Eff
icie
ncy
(EE)
Sola
r(E)
Abov
eSo
lar(E
)
Pref
erre
d Pl
an
2016
Inte
grat
ed R
esou
rce
Plan
Cum
ulat
ive
Reso
urce
Cha
nges
- (M
W)
(Cum
ulat
ive)
Firm
Cap
acity
Res
ourc
e AD
DITI
ON
SRe
sulti
ngKP
Co R
eser
ves
(B) R
epre
sent
s est
imat
ed (p
ost-2
005)
ene
rgy
effic
ienc
y le
vels
alre
ady
'em
bedd
ed' in
to K
PCo'
s lon
g-te
rm lo
ad &
pea
k de
man
d fo
reca
st b
ased
on
emer
genc
e of
prio
r-es
tabl
ished
Fed
eral
effi
cienc
y st
anda
reds
(EPA
ct
2005
; 200
7 EI
SA, 2
009
ARRA
).
Tota
l Sol
ar
89To
tal I
ncre
m. E
nerg
y Ef
ficie
ncy
KPSC Case No. 2016-00413 2016 Integrated Resource Plan
Of Kentucky Power Company Volume A - Public Version
Page 21 of 1497
The Clean Power Plan (CPP) and KPCos Preliminary Modeling Assessment
On October 23, 2015, EPA published a final rule the CPP - in the Federal Register
establishing carbon dioxide (CO2) emission guidelines for existing fossil fueled electric
generating units under Section 111(d) of the Clean Air Act. The CPP established interim and
final uniform national emission standards for two subcategories of generating units: (1) fossil-
fueled electric steam generating units; and (2) natural gas-fired combined-cycle units. EPA also
determined equivalent state-specific CO2 emission rate-based goals and mass-based goals. The
interim goals decline over the period from 2022-2029, with final goals effective in 2030 and
beyond.
Twenty-seven states, many utilities, coal producers, unions, national business
associations and other interested parties challenged the final rule, and sought to stay its
implementation pending judicial review. Although the D.C. Circuit denied these motions for
stay, on February 9, 2016, the U.S. Supreme Court granted the applications, staying
implementation of the CPP during review by the D.C. Circuit and any subsequent petitions for
review by the Supreme Court.
To account for potential incremental costs associated with the CPP or any future CO2
regulations, KPCos commodity price forecast assumes costs associated with CO2 emissions will
begin in 2024, escalating through 2030.
Conclusion
This IRP, based upon various assumptions, identifies adequate capacity resources at
reasonable cost, through a combination of supply-side resources (including renewable supply-
side resources) and demand-side programs throughout the forecast period.
Moreover, this IRP also identifies a means to enhance KPCos energy position. The
Preferred Plan offers incremental resources that will providein addition to PJM installed
capacity to achieve mandatory PJM (summer) peak demand requirementsadditional energy to
reduce the long-term exposure of the Companys customers to PJM energy markets.
The portfolios discussed in this Report attribute limited capacity value for solar and wind
KPSC Case No. 2016-00413 2016 Integrated Resource Plan
Of Kentucky Power Company Volume A - Public Version
Page 22 of 1497
resources, in part due to PJMs Capacity Performance rule. It is possible that intermittent
resources can be combined, or coupled, and offered into the PJM market as Capacity
Performance resources. Now that the final PJM Capacity Performance tariffs have been
accepted, the Company will investigate methods to maximize the utilization of future
intermittent resources within that construct. An example could be the additional coupling of wind
and solar resources in a manner that would mitigate potentially costly non-performance risk.
This IRP also addresses the Commission Staffs 2013 IRP recommendations. A table
showing the location of KPCos responses to the staffs recommendations is included at the end
of this executive summary, as well as in Exhibit A of the appendix to this report.
The IRP process is a continuous activity; assumptions and plans are reviewed as new
information becomes available and modified as appropriate. Indeed, the capacity and energy
resource portfolios reported herein reflect, to a large extent, assumptions that are subject to
change; an IRP is simply a snapshot of the future at a given time. As noted previously, this IRP
is not a commitment to specific resource additions or other courses of action, as the future is
highly uncertain. The resource planning process is becoming increasingly complex when
considering pending regulatory restrictions, technology advancement, changing energy supply
pricing fundamentals, uncertainty of demand and end-use efficiency improvements. These
complexities exacerbate the need for flexibility and adaptability in any ongoing planning activity
and resource planning process.
To that end, KPCo intends to pursue the following three-year action plan:
1. Pursue economic development opportunities to increase and diversify our industrial and commercial load. This includes looking at green power tariff alternatives for the growing number of customers who seek green power in the upcoming years.
2. Continue the planning and regulatory actions necessary to implement cost-effective Demand-Side Management (DSM)/EE programs.
3. Monitor renewable resource costs, particularly wind and solar, and based on consumer demand for green energy or other economic/strategic factors,
KPSC Case No. 2016-00413 2016 Integrated Resource Plan
Of Kentucky Power Company Volume A - Public Version
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determine the appropriate schedule to pursue cost-effective solicitations that would include self-build or acquisition options.
4. Monitor the status of, and if necessary, participate in formulating plans for Kentucky (as well as West Virginia and Indiana) pertaining to the CPP. Once plans are established, perform specific assessments as to the implications of the CPP on KPCos resource profile. And
5. Monitor this action plan and future IRPs to address changing circumstances.
KPSC Case No. 2016-00413 2016 Integrated Resource Plan
Of Kentucky Power Company Volume A - Public Version
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Cross Reference Table of Staff Comments from 2013 Final IRP Report
Topic Staff Comment Section Load Forecast
Provide a comparison of forecasted winter and summer peak demands with actual results for the period following the 2013 IRP, along with a discussion of the reasons for the differences between forecasted and actual peak demands (update of one of the recommendations in the previous IRP Staff Report)
2.12.5, 2.12.2
Provide a comparison of the annual forecast of residential energy sales, using the current econometric models, with actual results for the period following the 2013 IRP. Include a discussion of the reasons for the differences between forecasted and actual results
2.12.5, 2.12.1
Depending on the timing of its next IRP filing, Kentucky Power should, as needed, update the information relied upon in developing its forecast in order to reflect a greater amount of actual data for the year in the forecast is prepared
2.12.5
DSM/EE Include all environmental costs, as they become known, in future benefit/cost analyses
3.3.6
Research and report on best practices for DSM/EE program promotion, educational programs, and innovative marketing opportunities;
3.3.6
Research and report on possible partnering with adjoining AEP operating companies in order to enhance marketing and reduce advertising costs by using common program titles and offerings
3.3.6
Report on work undertaken to enhance evaluation, measurement, and verification procedures to ensure DSM/EE programs are achieving expected goals
3.3.6
Report on the results of the market potential study and, specifically, on industrial sector potential for implementing DSM/EE measures
3.3.6
Monitor the PJM capacity markets for economic opportunities related to demand response and DSM/EE and include an update on the potential for bidding peak savings from demand response and DSM/EE in the PJM capacity markets
3.3.6
General Include a discussion of and any changes or modifications that are under consideration for the PCA, and potential impacts to Kentucky Power
1.3
Provide current specific discussions of pending renewable generation sought by Kentucky Power in its system, or by coordination with other utilities
3.1
Discuss the status of cogeneration and CHP opportunities in its 3.3.4.2
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service territory and the consideration given to cogeneration and CHP in the resource plan Identify and describe currently installed net metering systems 3.3.4.1 Provide a detailed discussion of the ways in which net metering systems are encouraged and considered in the IRP, along with customer specific statistics
3.3.4.1
Provide detailed discussions of the consideration, suitability, and evaluation given to distributed generation
3.3.4
Provide additional specific discussions of the improvements and more efficient utilization of generation, transmission and distribution facilities as required by 807 KAR 5:058, Section 8(2a). The discussion should cover all modifications since the filing of the 2013 IRP and should address Kentucky Power's plans for the three years immediately following the filing of its next IRP.
3.1, 3.4.8, 3.5
Discuss system reliability and the criteria used to determine appropriate summer and winter reserve margins. Identify the capacity margin required by PJM and how it correlates to the reserve margin the Company used prior to its RTO membership.
3.1
In addition to describing how Kentucky Power is addressing current and pending environmental regulations and anticipated new regulations and legislation, the next IRP should address the expected impact and changes on the costs and operations
3.2, 5.3.3, 5.3.4
Discuss how Kentucky Power has addressed uncertainty in modeling future load and the resources to meet that load.
5.2.2
KPSC Case No. 2016-00413 2016 Integrated Resource Plan
Of Kentucky Power Company Volume A - Public Version
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Introduction 1.0
1.1 Overview
This Report presents the 2016 Integrated Resource Plan (IRP, Plan, or Report) for Kentucky
Power Company (KPCo or Company) including descriptions of assumptions, study parameters,
and methodologies. The results integrate supply- and demand-side resources.
The goal of the IRP process is to identify the amount, timing and type of resources required to
ensure a reliable supply of power and energy to customers at the least reasonable cost.
In addition to developing a long-term plan for achieving reliability/reserve margin
requirements as set forth by PJM, resource planning is critical to KPCo due to its impact on:
Capital budgeting; rate case planning; and environmental compliance and other planning processes.
1.2 Integrated Resource Plan (IRP) Process
This Report covers the processes and assumptions used to develop the IRP for the
Company. The IRP process for KPCo includes the following components/steps:
Description of the Company, the resource planning process in general, and the
implications of current issues as they relate to resource planning;
provide projected growth in demand and energy which serves as the
underpinning of the Plan;
identify and evaluate demand-side options such as Energy Efficiency (EE)
measures, Demand Response (DR) and Distributed Generation (DG);
identify current supply-side resources, including projected changes to those
resources (e.g., de-rates or retirements), and transmission system integration
issues;
identify and evaluate supply-side resource options; and
perform resource modeling and use the results to develop various portfolios.
KPSC Case No. 2016-00413 2016 Integrated Resource Plan
Of Kentucky Power Company Volume A - Public Version
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Figure 1. Kentucky Power Service Territory
1.4 Power Coordination Agreement (PCA)
Prior to 2014, the AEP-East utilities operated as part of the AEP integrated public utility
holding company system under the now-repealed Public Utility Holding Company Act of 1935.
As part of that arrangement, those companies coordinated the planning and operations of their
respective generating resources pursuant to the AEP Interconnection Agreement (Pool or Pool
Agreement). The Pool Agreement was terminated on January 1, 2014.
As of January 1, 2014 KPCo has been responsible for maintaining an adequate level of
power supply resources to meet its own load requirements for capacity, including any required
reserve margin. KPCo is also a party to the Power Coordination Agreement (PCA)3. The most
recent change to the PCA was the addition of Wheeling Power Company (WPCo) effective June
1, 2015. This addition was the result of WPCo acquiring a 50% undivided interest in the Mitchell
3 The Power Coordination Agreement currently provides Appalachian Power Company (APCo), Indiana Michigan Power (I&M), KPCo and Wheeling Power Company (WPCo) the opportunity to participate collectively (a) under a common Fixed Resource Requirement (FRR) capacity plan in PJM, and (b) in specified collective off-system sales and purchase activities. Under the Power Coordination Agreement, generation is not planned on a single-system basis as it was under the previous Pool Agreement. Rather, APCo, I&M, KPCo and WPCo individually are required to own or contract for sufficient generation to meet their respective load and reserve obligations. Additional information regarding the PCA as it pertains to Kentucky Power can be found in FERC Docket No. ER13-234.
KPSC Case No. 2016-00413 2016 Integrated Resource Plan
Of Kentucky Power Company Volume A - Public Version
Page 29 of 1497
Plant. This change had no impact on KPCos obligations under the PCA. No further changes to
the PCA are under consideration at this time.
1.5 The Impact of Coal Mining on KPCo Service Territory
For decades, coal mining has been a significant portion of KPCos industrial load.
Approximately 85% of KPCos customers live in counties that are part of the Appalachian coal
basin. As market conditions and environmental regulations have evolved and gas prices have
declined over the past decade, the demand for Appalachian coal produced in KPCos service
territory has declined.
While the direct impact of the lost mining loads within KPCos service territory has been
severe, an indirect impact on other industries located within the area has also been felt. Since the
2008 recession, mining employment within KPCos coal counties is down 68% (approximately
7,900 jobs), while total employment is down 13%. KPCos residential customer counts have
also dropped by 6% (approximately 8,000 customers) since the 2008 recession. The population
within the coal counties has also declined by over 15,000 people since the recession. Figure 2
below illustrates the overall impact the lost mining loads have had on the regional economy
within KPCos service territory.
Figure 2. Economic Impact of Lost Mining Load on KPCo Regional Economy
KPSC Case No. 2016-00413 2016 Integrated Resource Plan
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1.6 Significant Changes from the 2013 IRP
KPCo generally updates its load forecast and commodity price forecasts on an annual
basis. KPCo also monitors the cost of supply and demand side resources and incorporates the
latest forecasts and trends into its analysis when preparing its IRP. The changes to the load
forecast since the 2013 IRP filing are described in Section 2.9, Exhibit C-11 and Exhibit C-12 of
this report. Pricing trends for renewable resources are generally discussed in Section 4.6.5,
although the most significant change is related to wind and solar pricing, which now include the
benefits of the production tax credit and investment tax credit, respectively, in their pricing
assumptions. In the 2013 IRP, the Production Tax Credit (PTC) for wind was assumed to expire
for projects not in service before 2017. In the 2016 IRP the PTC is now available on a
diminishing scale for projects that begin construction prior to the end of 2019. For solar projects,
in addition to extending the Investment Tax Credit (ITC) benefit, a lower priced tier of solar
projects were also made available for modeling purposes.
Changes to the fundamental pricing forecast reflect the impact lower natural gas prices
have had on the energy market and demand for coal. Table 1 and Table 2 below show, in
constant 2011 dollars, the difference in the base commodity price forecast for energy, capacity
and fuels. Note that the current forecasts for all these commodities, with the exception of Powder
River Basin coal, are now lower than previously forecasted.
KPSC Case No. 2016-00413 2016 Integrated Resource Plan
Of Kentucky Power Company Volume A - Public Version
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Table 1. PJM Energy and Capacity Prices in 2013 IRP and 2016 IRP, in 2011 $
Table 2. Natural Gas and Coal Prices in 2013 IRP and 2016 IRP, in 2011 $
Finally, the assumptions regarding Carbon Dioxide (CO2) pricing have also been revised.
In the 2013 IRP, a $15/ton cost, in nominal dollars, associated with emitting CO2 would take
effect in 2022, and this cost would remain flat through the forecast period. The 2016 forecast
2013 IRP 2016 IRP 2013 IRP 2016 IRP 2013 IRP 2016 IRP2017 $50.35 $24.12 $32.26 $19.16 $113.52 $114.592018 $49.80 $30.87 $32.38 $22.26 $167.62 $123.402019 $49.24 $33.18 $32.37 $24.54 $176.81 $96.042020 $49.59 $33.87 $32.87 $25.70 $185.83 $41.552021 $50.52 $34.17 $33.33 $25.87 $194.93 $17.952022 $56.10 $34.53 $41.56 $26.11 $204.01 $17.562023 $56.09 $34.88 $41.40 $26.05 $213.09 $17.182024 $56.01 $36.87 $41.49 $28.37 $222.27 $16.822025 $55.99 $38.56 $41.35 $30.30 $231.22 $16.472026 $55.75 $40.15 $41.11 $32.06 $240.15 $16.132027 $55.75 $41.88 $40.84 $33.92 $249.07 $22.912028 $55.54 $43.46 $40.78 $35.59 $258.10 $31.072029 $55.50 $45.46 $40.77 $37.48 $260.33 $40.402030 $54.86 $48.26 $40.74 $39.33 $260.33 $50.902031 $54.76 $50.43 $40.86 $41.72 $260.33 $62.57
On-Peak Energy Prices Off-Peak Energy Prices Capacity Prices
2013 IRP 2016 IRP 2013 IRP 2016 IRP 2013 IRP 2016 IRP2017 $5.48 $2.74 $46.57 $32.92 $11.60 $11.542018 $5.45 $4.04 $48.02 $33.80 $11.54 $10.802019 $5.39 $4.18 $50.02 $35.43 $11.89 $14.702020 $5.47 $4.18 $51.13 $36.99 $12.49 $16.282021 $5.61 $4.18 $50.15 $36.10 $12.18 $17.022022 $5.82 $4.22 $50.13 $35.25 $12.62 $17.122023 $5.78 $4.23 $51.19 $34.43 $12.80 $15.412024 $5.82 $4.31 $50.24 $36.62 $12.35 $15.712025 $5.87 $4.38 $49.32 $37.25 $12.05 $16.482026 $5.82 $4.45 $48.33 $35.97 $11.93 $18.082027 $5.82 $4.55 $47.36 $36.45 $11.85 $16.952028 $5.83 $4.64 $46.11 $35.33 $11.77 $17.122029 $5.83 $4.73 $45.50 $34.01 $11.87 $19.532030 $5.79 $4.85 $45.21 $34.81 $13.06 $18.592031 $5.81 $4.94 $44.41 $35.45 $14.31 $20.52
(A) TCO = Columbia Gas Transmission Corporation(B) Powder River Basin (PRB) Coal, 8,800 Btu/lb.
Nat. Gas TCO(A)-Delivered Illinois Basin Coal PRB - 8800 Coal(B)
KPSC Case No. 2016-00413 2016 Integrated Resource Plan
Of Kentucky Power Company Volume A - Public Version
Page 32 of 1497
assumes costs associated with CO2 would not begin until 2024, and those costs would start at
$3/ton, but escalate to $20/ton by 2030.
Changes in the load forecast, commodity price forecast, and resource pricing assumptions
have resulted in a resource plan recommendation that is different than the one proposed in 2013.
The 2016 Preferred Plan includes 300 MW of wind, compared to the 2013 plan which added 100
MW. The utility scale solar profile is very similar with the 2016 plan adding 130 MW of utility
scale solar by 2031 compared to the 2013 plan adding 90 MW by 2028. The 2013 plan included
an aggressive 41 MW of DG by 2028, while the 2016 plan has only 1 MW, based on current
trends. The 2016 plan replaced the 59 MW biomass project with a 15 MW Combined Heat and
Power (CHP) installation, and adds a 10 MW battery. Demand side programs, including Volt
VAR Optimization (VVO) have more than doubled in the 2016 plan compared to the 2013 plan,
from 44 MW to 89 MW.
KPSC Case No. 2016-00413 2016 Integrated Resource Plan
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Load Forecast and Forecasting Methodology 2.0
2.1 Summary of KPCo Load Forecast
The KPCo load forecast was developed by the American Electric Power Service
Corporation (AEPSC) Economic Forecasting organization and completed in June 2016.4 The
final load forecast is the culmination of a series of underlying forecasts that build upon each
other. In other words, the economic forecast provided by Moodys Analytics is used to develop
the customer forecast, which is then used to develop the sales forecast, which is ultimately used
to develop the peak load and internal energy requirements forecast.
Over the next 15-year period (2017-2031)5, KPCos service territory is expected to see
population and non-farm employment decline of 0.1% per year. KPCo is projected to see
customer count decline at a similar rate of 0.2% per year. Over the same forecast period, KPCos
retail sales are projected to decline at 0.2% per year with growth expected from the industrial
class (+0.1% per year) while the residential class experiences a decline (0.5% per year) over the
forecast horizon. Finally, KPCos internal energy and peak demand are expected to decline at an
average rate of 0.2% and 0.3% per year, respectively, through 2031.
2.2 Forecast Assumptions
2.2.1 Economic Assumptions
The load forecasts for KPCo and the other operating companies in the AEP System
incorporate a forecast of U.S. and regional economic growth provided by Moodys Analytics.
The load forecasts utilized Moodys Analytics economic forecast issued in December 2015.
4 The load forecasts (as well as the historical loads) presented in this Report reflect the traditional concept of internal load, i.e., the load that is directly connected to the utilitys transmission and distribution system and that is provided with bundled generation and transmission service by the utility. Such load serves as the starting point for the load forecasts used for generation planning. Internal load is a subset of connected load, which also includes directly connected load for which the utility serves only as a transmission provider. Connected load serves as the starting point for the load forecasts used for transmission planning. 5 Fifteen year forecast period begins with the first full forecast year of 2017.
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Moodys Analytics projects moderate growth in the U.S. economy during the 2017-2031 forecast
period, characterized by a 2.0% annual rise in real Gross Domestic Product (GDP), and moderate
inflation, with the implicit GDP price deflator expected to rise by 2.0% per year. Industrial
output, as measured by the Federal Reserve Board's (FRB) index of industrial production, is
expected to grow at 1.5% per year during the same period. Moodys projects employment growth
of -0.1% per year during the forecast period and real regional income per-capita annual growth
of 2.1% for the KPCo service area.
2.2.2 Price Assumptions
The Company utilizes an internally developed service area electricity price forecast. This
forecast incorporates information from the Companys financial plan for the near term and the
U.S. Department of Energy (DOE) Energy Information Administration (EIA) outlook for the
East North Central Census Region for the longer term. These price forecasts are incorporated
into the Companys energy sales models, where appropriate.
2.2.3 Specific Large Customer Assumptions
KPCos customer service engineers are in frequent touch with industrial and commercial
customers about their needs and activities. From these discussions, expected load additions or
deletions are relayed to the Company.
2.2.4 Weather Assumptions
Where appropriate, the Company includes weather as an explanatory variable in its
energy sales models. These models reflect historical weather for the model estimation period and
normal weather for the forecast period.
2.2.5 Demand Side Management (DSM) Assumptions
The Companys long term load forecast models account for trends in EE both in the
historical data as well as the forecasted trends in appliance saturations as the result of various
legislated appliance efficiency standards (Energy Policy Act of 2005 [EPAct], Energy
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Independence and Security Act [EISA] of 2007, etc.) modeled by the EIA. In addition to general
trends in appliance efficiencies, the Company also administers multiple Demand-Side
Management (DSM) programs that the Commission approved as part of its DSM portfolio. The
load forecast utilizes the most current Commission-approved programs at the time the load
forecast is created to adjust the forecast for the impact of these programs.
2.3 Overview of Forecast Methodology
KPCo's load forecasts are based mostly on econometric, statistically adjusted end-use and
analyses of time-series data. This is helpful when analyzing future scenarios and developing
confidence bands in addition to objective model verification by using standard statistical criteria.
KPCo utilizes two sets of econometric models: 1) a set of monthly short-term models
which extends for approximately 24 months and 2) a set of monthly long-term models which
extends for approximately 30 years. The forecast methodology leverages the relative analytical
strengths of both the short- and long-term methods to produce a reasonable and reliable forecast
that is used for various planning purposes.
For the first full year of the forecast, the forecast values are generally governed by the
short-term models. The short-term models are regression models with time series errors which
analyze the latest sales and weather data to better capture the monthly variation in energy sales
for short-term applications like capital budgeting and resource allocation. While these models
produce extremely accurate forecasts in the short run, without logical ties to economic factors,
they are less capable of capturing structural trends in electricity consumption that are more
important for longer-term resource planning applications.
The long-term models are econometric, and statistically adjusted end-use models which
are specifically equipped to account for structural changes in the economy as well as changes in
customer consumption due to increased energy efficiency. The long-term forecast models
incorporate regional economic forecast data for income, employment, households, output, and
population.
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The short-term and long-term forecasts are then blended to ensure a smooth transition
from the short-term to the long-term forecast horizon for each major revenue class. There are
some instances when the short-term and long-term forecasts diverge, especially when the long-
term models are incorporating a structural shift in the underlying economy that is expected to
occur within the first 24 months of the forecast horizon. In these instances, professional
judgment is used to ensure that the final forecast that will be used in the peak models is
reasonable. The class level sales are then summed and adjusted for losses to produce monthly net
internal energy sales for the system. The demand forecast model utilizes a series of algorithms to
allocate the monthly net internal energy to hourly demand. The inputs into forecasting hourly
demand are internal energy, weather, 24-hour load profiles and calendar information.
A flow chart depicting the sequence of models used in projecting KPCos electric load
requirements as well as the major inputs and assumptions that are used in the development of the
load forecast is shown in Figure 3, below.
Figure 3. KPCo Internal Energy Requirements and Peak Demand Forecasting Method
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2.4 Detailed Explanation of Load Forecast
2.4.1 General
This section provides a more detailed description of the short-term and long-term models
employed in producing the forecasts of KPCos energy consumption, by customer class.
Conceptually, the difference between short- and long-term energy consumption relates to
changes in the stock of electricity-using equipment and economic influences, rather than the
passage of time. In the short term, electric energy consumption is considered to be a function of
an essentially fixed stock of equipment. For residential and commercial customers, the most
significant factor influencing the short term is weather. For industrial customers, economic
forces that determine inventory levels and factory orders also influence short-term utilization
rates. The short-term models recognize these relationships and use weather and recent load
growth trends as the primary variables in forecasting monthly energy sales.
Over time, demographic and economic factors such as population, employment, income,
and technology influence the nature of the stock of electricity-using equipment, both in size and
composition. Long-term forecasting models recognize the importance of these variables and
include all or most of them in the formulation of long-term energy forecasts.
Relative energy prices also have an impact on electricity consumption. One important
difference between the short-term and long-term forecasting models is their treatment of energy
prices, which are only included in long-term forecasts. This approach makes sense because
although consumers may suffer sticker shock from energy price fluctuations, there is little they
can do to impact them in the short-term. They already own a refrigerator, furnace or industrial
equipment that may not be the most energy-efficient model available. In the long term, however,
these constraints are lessened as durable equipment is replaced and as price expectations come to
fully reflect price changes.
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2.4.2 Customer Forecast Models
The Company also utilizes both short-term and long-term models to develop the final
customer count forecast. The short-term customer forecast models are time series models with
intervention (when needed) using Autoregressive Integrated Moving Average (ARIMA) methods
of estimation. These models typically extend for 24 months into the forecast horizon.
The long-term residential customer forecasting models are also monthly but extend for 30
years. The explanatory jurisdictional economic and demographic variables include gross regional
product, employment, mortgage rate, population, real personal income and households are used
in various combinations. In addition to the economic explanatory variables, the long-term
customer models employ a lagged dependent variable to capture the adjustment of customer
growth to changes in the economy. There are also binary variables to capture monthly variations
in customers, unusual data points and special occurrences.
The short-term and long-term customer forecasts are blended as was de