CHAPTER 11. UTILITY IMPACT ANALYSIS

TABLE OF CONTENTS

11.1 INTRODUCTION ......................................................................................................... 11-1

11.2 METHODOLOGY ........................................................................................................ 11-2

11.3 UTILITY IMPACT RESULTS ..................................................................................... 11-4

11.3.1 Small Three-Phase Air-Cooled Air Conditioners and Heat Pumps <65,000 

Btu/h ....................................................................................................................... 11-4

11.3.1.1 Installed Capacity .................................................................................... 11-4

11.3.1.2 Electricity Generation .............................................................................. 11-7

11.3.1.1 Results Summary ................................................................................... 11-11

11.3.2 Water-Source Heat Pumps ................................................................................... 11-11

11.3.2.1 Installed Capacity .................................................................................. 11-11

11.3.2.2 Electricity Generation ............................................................................ 11-15

11.3.2.3 Results Summary ................................................................................... 11-17

LIST OF TABLES

Table 11.3.1 Small Commercial Air-Cooled Air Conditioners and Heat Pumps: 

Summary of Utility Impact Results ................................................................. 11-11

Table 11.3.2 Water-Source Heat Pumps: Summary of Utility Impact Results ..................... 11-18

LIST OF FIGURES

Figure 11.3.1 Small Commercial Air-Cooled Air Conditioners and Heat Pumps: Total 

Electric Capacity Reduction ........................................................................... 11-4

Figure 11.3.2 Small Commercial Air-Cooled Air Conditioners and Heat Pumps: Coal 

Capacity Reduction ......................................................................................... 11-5

Figure 11.3.3 Small Commercial Air-Cooled Air Conditioners and Heat Pumps: 

Nuclear Capacity Reduction ........................................................................... 11-5

Figure 11.3.4 Small Commercial Air-Cooled Air Conditioners and Heat Pumps: Gas 

Combined Cycle Capacity Reduction ............................................................. 11-6

Figure 11.3.5 Small Commercial Air-Cooled Air Conditioners and Heat Pumps: 

Peaking Capacity Reduction ........................................................................... 11-6

Figure 11.3.6 Small Commercial Air-Cooled Air Conditioners and Heat Pumps: 

Renewables Capacity Reduction..................................................................... 11-7

Figure 11.3.7 Small Commercial Air-Cooled Air Conditioners and Heat Pumps: Total 

Generation Reduction ..................................................................................... 11-8

Figure 11.3.8 Small Commercial Air-Cooled Air Conditioners and Heat Pumps: Coal 

Generation Reduction ..................................................................................... 11-8

Figure 11.3.9 Small Commercial Air-Cooled Air Conditioners and Heat Pumps: 

Nuclear Generation Reduction ........................................................................ 11-9

Figure 11.3.10 Small Commercial Air-Cooled Air Conditioners and Heat Pumps: Gas 

Combined Cycle Generation Reduction ......................................................... 11-9

11-i 
Figure 11.3.11 Small Commercial Air-Cooled Air Conditioners and Heat Pumps: Oil 

Generation Reduction ................................................................................... 11-10

Figure 11.3.12 Small Commercial Air-Cooled Air Conditioners and Heat Pumps 

Renewables Generation Reduction ............................................................... 11-10

Figure 11.3.13 Water-Source Heat Pumps: Total Electric Capacity Reduction ................... 11-12

Figure 11.3.14 Water-Source Heat Pumps: Coal Capacity Reduction .................................. 11-12

Figure 11.3.15 Water-Source Heat Pumps: Nuclear Capacity Reduction ............................ 11-13

Figure 11.3.16 Water-Source Heat Pumps: Gas Combined Cycle Capacity Reduction ....... 11-13

Figure 11.3.17 Water-Source Heat Pumps: Peaking Capacity Reduction ............................ 11-14

Figure 11.3.18 Water-Source Heat Pumps: Renewables Capacity Reduction ...................... 11-14

Figure 11.3.19 Water-Source Heat Pumps: Total Generation Reduction ............................. 11-15

Figure 11.3.20 Water-Source Heat Pumps: Coal Generation Reduction .............................. 11-15

Figure 11.3.21 Water-Source Heat Pumps: Nuclear Generation Reduction ......................... 11-16

Figure 11.3.22 Water-Source Heat Pumps: Gas Combined Cycle Generation Reduction ... 11-16

Figure 11.3.23 Water-Source Heat Pumps: Oil Generation Reduction ................................ 11-17

Figure 11.3.24 Water-Source Heat Pumps: Renewables Generation Reduction .................. 11-17

11-ii
CHAPTER 11. UTILITY IMPACT ANALYSIS

11.1 INTRODUCTION

In the utility impact analysis, the U.S. Department of Energy (DOE) analyzes the changes 

in electric installed capacity and power generation that result for each trial standard level (TSL). 

The utility impact analysis is based on output of the DOE/Energy Information 

Administration (EIA)’s National Energy Modeling System (NEMS).a

 NEMS is a public domain, 

multi-sectored, partial equilibrium model of the U.S. energy sector. Each year, DOE/EIA uses 

NEMS to produce an energy forecast for the United States, the Annual Energy Outlook (AEO). 

The EIA publishes a reference case, which incorporates all existing energy-related policies at the 

time of publication, and a variety of side cases which analyze the impact of different policies, 

energy price and market trends. As of 2014, DOE is using a new methodology based on results 

published for the Annual Energy Outlook 2014 (AEO 2014) Reference case and a set of side 

cases that implement a variety of efficiency-related policies.

2

 

The new approach retains key aspects of DOE’s previous methodology, and provides 

some improvements: 

• The assumptions used in the AEO reference case and side cases are fully 

documented and receive detailed public scrutiny. 

• NEMS is updated each year, with each edition of the AEO, to reflect changes in 

energy prices, supply trends, regulations, etc. 

• The comprehensiveness of NEMS permits the modeling of interactions among 

the various energy supply and demand sectors. 

• Using EIA published side cases to estimate the utility impacts enhances the 

transparency of DOE’s analysis.

• The variability in impacts estimates from one edition of AEO to the next will be 

reduced under the new approach. 

On the average, however, over the full analysis period, the results from the new approach 

are comparable to results from the old approach. 

a For more information on NEMS, refer to the U.S. Department of Energy, Energy Information Administration 

documentation. A useful summary is National Energy Modeling System: An Overview.

1

11-1 

 
11.2 METHODOLOGY 

DOE estimates the marginal impacts of reduction in energy demand on the energy supply 

sector. In principle, marginal values should provide a better estimate of the actual impact of 

energy conservation standards. 

NEMS uses predicted growth in demand for each end use to build up a projection of the 

total electric system load growth. The system load shapes are converted internally to load 

duration curves, which are then used to estimate the most cost-effective additions to capacity. 

When electricity demand deviates from the AEO reference case, in general there are three interrelated effects: the annual generation (TWh) from the stock of electric generating capacity 

changes, the total generation capacity itself (GW) may change, and the mix of capacity by fuel 

type may change. Each of these effects can vary for different types of end use. The change in 

total generating capacity is sensitive to the degree to which the end-use is peak coincident, while

the capacity mix is sensitive to the hourly load shape associated with the end use. Changes in 

generation by fuel type lead in turn to changes in total power sector emissions of SO2, NOx, Hg 

and CO2. 

DOE’s new approach examines a series of AEO side cases to estimate the relationship 

between demand reductions and the marginal energy, emissions and capacity changes. The 

assumptions for each side case are documented in Appendix E of the AEO. The side cases, or 

scenarios, that incorporate significant changes to equipment efficiencies relative to the Reference 

case are: 

• 2013 Technology (leaves all technologies at 2013 efficiencies); 

• Best Available Technology (highest efficiency irrespective of cost); 

• High Technology (higher penetration rates for efficiency and demand management); 

• Extended Policies (includes efficiency standards that are not in the reference). 

Scenarios that incorporate policies that directly affect the power sector without changes 

in energy demand (for example, subsidies for renewables, or high fuel price assumptions) are not 

appropriate for this analysis. The methodology proceeds in seven steps:

1. Supply-side data on generation, capacity and emissions, and demand-side data on electricity 

use by sector and end-use, are extracted from each side case. The data are converted to 

differences relative to the AEO Reference case.

2. The changes in electricity use on the demand-side data are allocated to one of three 

categories: on-peak, shoulder, and off-peak. These categories are used in the utility sector to 

correlate end-use consumption with supply types. For each of the end-uses that are modeled 

explicitly in NEMS, load shape information is used to identify the fraction of annual 

electricity use assigned to each category. On-peak hours are defined as noon-5pm, June 

through September. Off-peak hours are nights and Sundays. All other hours are assigned to 

the shoulder period. 

11-2 
3. For each year and each side case, the demand-side reductions to on-peak, off-peak and 

shoulder-period electricity use are matched on the supply-side to reductions in generation by 

fuel type. The fuel types are petroleum fuels, natural gas, renewables, nuclear and coal. The 

allocation is based on the following rules: 

3.1. All petroleum-based generation is allocated to peak periods; 

3.2. Natural gas generation is allocated to any remaining peak reduction; this is consistent 

with the fact that oil and gas steam units are used in NEMS to meet peak demand; 

3.3. Base-load generation (nuclear and coal) is allocated proportionally to all periods; 

3.4. The remaining generation of all types is allocated to the remaining off-peak and shoulder 

reductions proportionally. 

4. The output of step 3 defines fuel-share weights giving the fraction of energy demand in each 

load category that is met by each fuel type as a function of time. These are combined with the 

weights that define the load category shares by end-use to produce coefficients that allocate a 

marginal reduction in end-use electricity demand to each of the five fuel types. 

5. A regression model is used to relate reductions in generation by fuel type to reductions in 

emissions of power sector pollutants. The model produces coefficients that define the change 

in total annual emissions of a given pollutant resulting from a unit change in total annual 

generation for each fuel type, as a function of time. These coefficients are combined with the 

weights calculated in step 4 to produce coefficients that relate emissions changes to changes 

in end-use demand. 

6. A regression model is used to relate reductions in generation by fuel type to reductions in 

installed capacity. The categories used for installed capacity are the same as for generation 

except for peak: NEMS uses two peak capacity types (combustion turbine/diesel and oil and 

gas steam) which are combined here into a single “peak” category. The model produces 

coefficients that define the change in total installed capacity of a given type resulting from a 

unit change in total annual generation for the corresponding fuel type. These coefficients are 

combined with the weights calculated in step 4 to produce coefficients that relate installed 

capacity changes to changes in end-use demand, as a function of time. 

7. The coefficient time-series for fuel share, pollutant emissions and capacity for the 

appropriate end use are multiplied by the stream of energy savings calculated in the NIA to 

produce estimates of the utility impacts. 

This analysis ignores pumped storage, fuel cells and distributed generation, as these 

generation types are not affected by the policy changes modeled in the EIA side cases. The 

methodology is described in more detail in K. Coughlin, “Utility Sector Impacts of Electricity 

Demand Reductions”.3

11-3 
11.3 UTILITY IMPACT RESULTS

 This section presents results of the analysis for all of the capacity types used to supply 

electricity to operate small commercial air-cooled air-conditioning and heating equipment less 

than 65,000 Btu/h and water-source heat pumps in commercial buildings. 

11.3.1 Small Three-Phase Air-Cooled Air Conditioners and Heat Pumps <65,000 Btu/h 

11.3.1.1 Installed Capacity 

The figures in this section show the changes in U.S. electricity installed capacity that 

result for each efficiency level by major plant type for selected years. Note that a negative 

number means an increase in capacity under an efficiency level. 

Figure 11.3.1 Small Commercial Air-Cooled Air Conditioners and Heat 

Pumps: Total Electric Capacity Reduction

11-4 
Figure 11.3.2 Small Commercial Air-Cooled Air Conditioners and Heat 

Pumps: Coal Capacity Reduction 

Figure 11.3.3 Small Commercial Air-Cooled Air Conditioners and Heat 

Pumps: Nuclear Capacity Reduction

11-5 
Figure 11.3.4 Small Commercial Air-Cooled Air Conditioners and Heat 

Pumps: Gas Combined Cycle Capacity Reduction

Figure 11.3.5 Small Commercial Air-Cooled Air Conditioners and Heat 

Pumps: Peaking Capacity Reduction 

11-6 
Figure 11.3.6 Small Commercial Air-Cooled Air Conditioners and Heat 

Pumps: Renewables Capacity Reduction

11.3.1.2 Electricity Generation

The figures in this section show the annual change in electricity generation that result for 

each efficiency level by fuel type. Note that a negative number means an increase in generation

under an efficiency level. 

11-7 
Figure 11.3.7 Small Commercial Air-Cooled Air Conditioners and Heat 

Pumps: Total Generation Reduction

Figure 11.3.8 Small Commercial Air-Cooled Air Conditioners and Heat 

Pumps: Coal Generation Reduction

11-8 
Figure 11.3.9 Small Commercial Air-Cooled Air Conditioners and Heat 

Pumps: Nuclear Generation Reduction

Figure 11.3.10 Small Commercial Air-Cooled Air Conditioners and Heat 

Pumps: Gas Combined Cycle Generation Reduction

11-9 
Figure 11.3.11 Small Commercial Air-Cooled Air Conditioners and Heat 

Pumps: Oil Generation Reduction

Figure 11.3.12 Small Commercial Air-Cooled Air Conditioners and Heat 

Pumps Renewables Generation Reduction

11-10
11.3.1.1 Results Summary 

Table 11.3.1 presents a summary of the utility impact results for small commercial aircooled air-conditioning and heating equipment less than 65,000 Btu/h. 

Table 11.3.1 Small Commercial Air-Cooled Air Conditioners and Heat Pumps: Summary 

of Utility Impact Results

ASHRAE 

Level/ EL0 EL 1 EL 2 EL 3 EL 4 EL 5

Installed Capacity Reduction (MW)

2020 9.78 15.69 35.10 42.19 49.37 53.91

2025 35.65 90.44 198.97 241.48 283.41 307.82

2030 65.55 162.17 342.56 417.99 489.80 529.42

2035 96.39 231.28 467.68 574.52 672.11 722.42

2040 124.02 292.01 561.97 696.29 813.12 867.95

Electricity Generation Reduction (GWh)

2020 27.99 44.90 100.46 120.74 141.31 154.29

2025 80.39 203.96 448.70 544.56 639.11 694.16

2030 142.12 351.61 742.73 906.28 1061.98 1147.89

2035 197.52 473.91 958.30 1177.23 1377.19 1480.30

2040 242.25 570.38 1097.69 1360.06 1588.25 1695.36

11.3.2 Water-Source Heat Pumps

11.3.2.1 Installed Capacity 

The figures in this section show the changes in U.S. electricity installed capacity that 

result for each efficiency level by major plant type for selected years. Note that a negative 

number means an increase in capacity under an efficiency level. 

11-11
Figure 11.3.13 Water-Source Heat Pumps: Total Electric Capacity Reduction

Figure 11.3.14 Water-Source Heat Pumps: Coal Capacity Reduction 

0

500

1000

1500

2000

2500

2016202120262031203620412046205120562061206620712076208120862091209621012106

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Total

ASHRAE TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

0

20

40

60

80

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120

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2016202120262031203620412046205120562061206620712076208120862091209621012106

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Coal

ASHRAE TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

11-12
Figure 11.3.15 Water-Source Heat Pumps: Nuclear Capacity Reduction

Figure 11.3.16 Water-Source Heat Pumps: Gas Combined Cycle Capacity 

Reduction

0

5

10

15

20

25

2016202120262031203620412046205120562061206620712076208120862091209621012106

MW

Nuclear

ASHRAE TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

0

100

200

300

400

500

600

2016202120262031203620412046205120562061206620712076208120862091209621012106

MW

NGCC

ASHRAE TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

11-13
Figure 11.3.17 Water-Source Heat Pumps: Peaking Capacity Reduction 

Figure 11.3.18 Water-Source Heat Pumps: Renewables Capacity Reduction

0

200

400

600

800

1000

1200

2016202120262031203620412046205120562061206620712076208120862091209621012106

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Peaking

ASHRAE TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

0

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2016202120262031203620412046205120562061206620712076208120862091209621012106

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Renewable

ASHRAE TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

11-14
11.3.2.2 Electricity Generation

The figures in this section show the annual change in electricity generation that result for 

each efficiency level by fuel type. Note that a negative number means an increase in generation

under an efficiency level. 

Figure 11.3.19 Water-Source Heat Pumps: Total Generation Reduction 

Figure 11.3.20 Water-Source Heat Pumps: Coal Generation Reduction 

0

500

1000

1500

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3000

3500

4000

4500

5000

2016202120262031203620412046205120562061206620712076208120862091209621012106

GWh

Total

ASHRAE TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

0

200

400

600

800

1000

1200

2016202120262031203620412046205120562061206620712076208120862091209621012106

GWh

Coal

ASHRAE TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

11-15
Figure 11.3.21 Water-Source Heat Pumps: Nuclear Generation Reduction

Figure 11.3.22 Water-Source Heat Pumps: Gas Combined Cycle Generation 

Reduction

0

20

40

60

80

100

120

140

160

180

2016202120262031203620412046205120562061206620712076208120862091209621012106

GWh

Nuclear

ASHRAE TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

0

500

1000

1500

2000

2500

3000

2016202120262031203620412046205120562061206620712076208120862091209621012106

GWh

NGCC

ASHRAE TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

11-16
Figure 11.3.23 Water-Source Heat Pumps: Oil Generation Reduction

Figure 11.3.24 Water-Source Heat Pumps: Renewables Generation Reduction

11.3.2.3 Results Summary 

Table 11.3.2 presents a summary of the utility impact results for water-source heat 

pumps. 

0

5

10

15

20

25

2016202120262031203620412046205120562061206620712076208120862091209621012106

GWh

Oil

ASHRAE TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

0

100

200

300

400

500

600

700

2016202120262031203620412046205120562061206620712076208120862091209621012106

GWh

Renewable

ASHRAE TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

11-17
Table 11.3.2 Water-Source Heat Pumps: Summary of Utility Impact Results

ASHRAE 

Level/ EL0* EL 1 EL 2 EL 3 EL 4 EL 5

Installed Capacity Reduction (MW)

2020 - 2.08 19.96 36.77 50.42 71.04

2025 - 13.45 146.57 272.27 373.37 523.72

2030 - 23.73 271.34 506.24 693.22 966.08

2035 - 34.10 394.49 738.04 1008.29 1393.85

2040 - 43.63 504.36 945.74 1288.17 1763.56

Electricity Generation Reduction (GWh)

2020 - 6.65 63.66 117.28 160.79 226.58

2025 - 34.83 379.64 705.24 967.11 1356.54

2030 - 58.74 671.65 1253.09 1715.92 2391.31

2035 - 79.48 919.62 1720.51 2350.51 3249.31

2040 - 96.60 1116.59 2093.74 2851.85 3904.29 *

There are no reductions for the ASHRAE level because there is no market share projected at 

the federal baseline in the base case.

11-18
REFERENCES

1. U.S. Department of Energy-Energy Information Administration, National Energy 

Modeling System: An Overview, 2009. Report No. DOE/EIA-0581(2009). 

<http://www.eia.gov/oiaf/aeo/overview/> 

2. U.S. Department of Energy-Energy Information Administration, Annual Energy Outlook 

2014 with Projections to 2040, 2014. Washington, DC. 

<http://www.eia.gov/forecasts/aeo/> 

3. Coughlin, K., Utility Sector Imacts of Reduced Electricity Demand, 2014. Lawrence 

Berkeley National Laboratory. Report No. LBNL-6864E. 

11-19