Stipulated Parameters
Stipulated parameters were based on current equipment nameplates and drawings. A summary of the stipulated parameters are listed in the tables below:
Water Source Heat Pumps
Boiler Efficiency 0.94
Total Cooling Capacity 349 MBH
Total Heating Capacity 420 MBH
Adjusted Cooling Hours 2,146
Adjusted Heating Hours 2,219
Existing and Proposed EER and COP Varies, see table in Appendix A of the IGA 6 Includes a 0.90 safety factor as stated in original IGA proposal. 633 of 1021
Cortland County, NY
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VFD Improvements
Pump Load Factor 90%
Pump Efficiency 85.5%
Minimum Fluid Flow 30%
% Flow at each BIN Appendix B of the IGA
VFD Efficiency 98%
Pump Load Factor 90%
BMS Installation (Setup/Setback and Temperature Correction) Boiler Efficiency 94%
Chiller Efficiency (kW/ton) 1.2
Ventilation Rate (cfm) 1,650
Window U Factor (Btu/(h*sqft*degF)) 0.55
Wall U Factor (Btu/(h*sqft*degF)) 0.06
Roof U Factor (Btu/(h*sqft*degF)) 0.03
Window Area (ft2) 885
Wall Area (ft2) 25,920
Roof Area (ft2) 4,000
Air Infiltration Leakage (cfm/SqFt) 0.2
Building Solar Gain Heating Season (degF) 5
Building Solar Gain Cooling Season (degF) 10
Baseline Occ Heating Temperature (degF) 71.8
Baseline Unocc Heating Temperature (degF) 71.0
Proposed Occ Heating Temperature (degF) 70
Proposed Unocc Heating Temperature (degF) 72
Baseline Occ Cooling Temperature (degF) 74
Baseline Unocc Cooling Temperature (degF) 74
Proposed Occ Cooling Temperature (degF) 74
Proposed Unocc Cooling Temperature (degF) 78
Savings Measurement Procedure
M&V Option A was selected to provide a cost-effective means to evaluate savings. The post-installation measurement parameters that were made are as follows:
• Visual inspection of installed WSHPs.
• Amperage draw of 4 WSHP units for a one-week period.
• Annual VFD speed measurements from EMS.
• Space Temperature.
Energy Usage of 4 WSHP Units
SmartWatt energy engineers deployed CT loggers on the following units listed in the table below at the PSB Building for a 1-week period of time (1/19/19 – 1/22/19). The table below represents a summary of the measurements. These measurements were taken during Year 1 of the term and are reflected accordingly. 634 of 1021
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The post installation COP is calculated as follows:
𝐶𝑂𝑃 =
𝐸𝑛𝑒𝑟𝑔𝑦 𝑂𝑢𝑡𝑝𝑢𝑡 (
𝐵𝑡𝑢
ℎ𝑟
)
𝐸𝑛𝑒𝑟𝑔𝑦 𝐼𝑛𝑝𝑢𝑡 (𝑊𝑎𝑡𝑡𝑠)
Motor Power Draw on Loop Pumps
SmartWatt energy engineers retrieved trend data from the energy management system for the PSB loop transfer pumps. The post installation motor power is input into the energy savings calculations to verify post installation energy use. The minimum power is 18% in the bins of 45-60 °F. Tables 9 and 10 illustrate the change in power from what was proposed in the IGA to the verified VFD Power for Year 2 of the term. Corrections were made during Year 2 to reflect slightly more energy savings than Year 1.
During the IGA, power of the motor is calculated using the fan laws. The power is a cubic function of the speed of the motor. This means that as the speed decreases, the fan power decreases by an exponential power of 3.
During Year 2 of the term, the power was pulled directly from the building energy management system for each bin listed in the tables below. The % power was a direct relation of the average energy vs max energy use for each bin.
7 Equipment logger failed upon initiation and therefore was not included in the EER calculation.
HP Drawing
ID Model Number
Average
Amperage
(Measured)
Voltage Heating
Btuh
Calculated COP
Used in Energy
Calculations
6 50PEC12TXLECD1A1 3.39 208 13,300 5.53
157 50PEC09TXLECD1A1 - - - -
19 50PEC09TXLECD1A1 2.84 208 10,800 5.74
23 50PEC09TXLECD1A1 2.49 208 10,800 5.74
33 50PEC09TXLECD1A1 2.63 208 10,800 5.74
635 of 1021
Cortland County, NY
Year 3 Measurement and Verification Report
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Table 7: IGA Proposed VFD Power Table 8: Year 2 Verified VFD Power
Space Temperature
SmartWatt energy engineers retrieved trend data from the energy management system for the heat pumps in the Public Safety building for the 2019 calendar year. During the summer check in of the building automation system, it was confirmed that 19 of 38 heat pumps were forced into “always occ” mode. This was comparable to the year 1 observation that had 21 of 38 heat pumps that has the same status. Figure 1 is reflective of the average building space temp and set point as it relates to a representative sample of spaces throughout the building. Figure 2 below is reflective of a heat pump that has the thermostat overridden to reflect an “always occupied” status with little variation during January 2019. As indicated most of the spaces are set according to a schedule with some variation throughout the weekends. Below is a chart that describes the proposed space temperatures from the IGA along with the verified space temperatures.
BIN Hours (°F) Proposed Power
with VFD (%)
95 to 100 102%
90 to 95 75%
85 to 90 52%
80 to 85 34%
75 to 80 21%
70 to 75 11%
65 to 70 5%
60 to 65 5%
55 to 60 5%
50 to 55 5%
45 to 50 5%
40 to 45 5%
35 to 40 5%
30 to 35 5%
25 to 30 10%
20 to 25 16%
15 to 20 25%
10 to 15 35%
5 to 10 48%
0 to 5 63%
-5 to 0 81%
-10 to -6 102%
BIN Hours (°F) Verified Power
on VFD (%)
95 to 100 19%
90 to 95 23%
85 to 90 22%
80 to 85 22%
75 to 80 21%
70 to 75 20%
65 to 70 19%
60 to 65 19%
55 to 60 18%
50 to 55 18%
45 to 50 18%
40 to 45 19%
35 to 40 19%
30 to 35 19%
25 to 30 20%
20 to 25 19%
15 to 20 20%
10 to 15 20%
5 to 10 19%
0 to 5 20%
-5 to 0 19%
-10 to -6 19%
636 of 1021
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Year 3 Measurement and Verification Report
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IGA Temperatures
(°F)
Year 2 Verified
Temperatures (°F)
Post Installation Occupied
Heating Temperature 70 71
Post Installation Unoccupied
Heating Temperature 65 70
Post Installation Occupied
Cooling Temperature 74 72
Post Installation Unoccupied
Cooling Temperature 78 72
Figure 2: PSB Average Space Temp
637 of 1021
Cortland County, NY
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Figure 3: Heat Pump #2 with Overridden Setpoint
The shortfall in savings as it relates to this item of the project is associated with fewer setbacks during unoccupied times than anticipated. The occupied temperatures are also slightly higher on the heating and lower on the cooling. This results in more energy use than anticipated. SmartWatt has worked with the occupants of the building along with the county staff to address the temperatures throughout Year 2 of the reporting period.
Throughout the year, it has been noted that the schedules and temperatures were changed to address occupant requests.
638 of 1021
Cortland County, NY
Year 3 Measurement and Verification Report
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3.8 FIM 8 – Cooling Tower Replacement at PSB
Pre-Installation
Pre-Installation Energy Use (kWh/yr)
13,783
Post - Installation
Post - Installation IGA
Energy Use (kWh/yr)
Post - Installation Verified
Energy Use (kWh/yr) Variance (kWh/yr)
2,905 2,183 (722)
Energy Savings
Guaranteed Energy
Savings (kWh/yr)8
Verified Energy Savings
(kWh/yr)
Variance from
Guarantee (kWh/yr)
9,790 11,600 1,810
Overview
Installation of this FIM includes replacing the existing cooling tower located in the PSB mezzanine along with a new VFD and motor on the cooling tower fan. The measurement and verification plan outlined in the IGA required measurements for this FIM to be Performed in Year 1 only. Therefore, the measurements made below are representative from Year 1 of the project term and reflected accordingly.
Stipulated Parameters
Stipulated parameters were based on current equipment nameplates, drawings, and engineering estimates as defined in the table that follows:
Cooling Tower Fan Motor
Fan Load Factor 90%
Fan Motor Efficiency 72% High Speed, 85.5% Low Speed
New Motor Efficiency 91.7%
Minimum Fluid Flow 30%
Fan on Low Speed point for fan (°F) 50
Fan on High Speed point for fan (°F) 70
% Flow at each BIN Appendix B of IGA
VFD Efficiency 98%
Post FIM Measurement Procedure
• Power Draw on motor & flow trended through EMS
• Outside Air Temperature for the same period
8 Includes a .90 safety factor.
639 of 1021
Cortland County, NY
Year 3 Measurement and Verification Report
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Motor Power Draw on Loop Pumps
SmartWatt energy engineers retrieved trend data from the energy management system for the PSB cooling tower fan. The post installation motor power is input into the energy savings calculations to verify post installation energy use. Tables 12 and 13 illustrate the change in power from what was proposed in the IGA to the verified VFD Power. The VFD is working as designed with a slight surplus in energy savings. This is due to the lower power % during the middle temperature bins where the majority of the hours are located.
Table 12: IGA Proposed VFD Power Table 13: Verified VFD Power
BIN Hours (°F) Proposed Power
with VFD (%)
95 to 100 102%
90 to 95 77%
85 to 90 57%
80 to 85 40%
75 to 80 26%
70 to 75 16%
65 to 70 8%
60 to 65 5%
55 to 60 5%
50 to 55 5%
BIN Hours (°F) Verified Power
on VFD (%)
95 to 100 102%
90 to 95 77%
85 to 90 41%
80 to 85 11%
75 to 80 7%
70 to 75 8%
65 to 70 9%
60 to 65 10%
55 to 60 9%
50 to 55 6%
640 of 1021
Cortland County, NY
Year 3 Measurement and Verification Report
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3.9 FIM 9 – Replace Boilers in Public Safety Building
Pre-Installation
Pre-Installation Gas Use (Therm/yr)
12,730
Post - Installation
Post – Installation IGA
Natural Gas (Therm/yr)
Post - Installation Verified
Natural Gas (Therm/yr) Variance (Therm/yr)
9,977 10,292 315
Energy Savings
Guaranteed NG Savings
(Therm/yr)
Verified NG Savings
(Therm/yr)
Variance from
Guarantee (Therm/yr)
2,478 2,439 (39)
Overview
Installation of this FIM includes replacing the existing two (2) natural-gas fired boilers with two (2) high efficiency PK Mach Series 500 Boilers – Model CM500 at the Public Safety Building. The increase in combustion efficiency results in a reduction in natural gas use. The measurement and verification plan outlined in the IGA required measurements for this FIM to be Performed in Year 1 only. Therefore, the measurements made below are representative from Year 1 of the project term and reflected accordingly.
Post FIM Measurement Procedure
SmartWatt has taken a combustion efficiency measurement post installation of the two boilers. The results of the verified measurement compared to the proposed measurement are shown in the table below.
Combustion Efficiency
IGA Proposed Efficiency Verified Efficiency
94% 91%
Saving Measurement Procedure
Energy savings are calculated by increasing boiler efficiency. The calculations utilized to determine savings are provided below:
𝐴𝑛𝑛𝑢𝑎𝑙 𝑁𝐺 𝑆𝑎𝑣𝑖𝑛𝑔𝑠 = 𝐵𝑎𝑠𝑒𝑙𝑖𝑛𝑒 𝑁𝐺 𝑈𝑠𝑒 − 𝑃𝑜𝑠𝑡 𝐼𝑛𝑠𝑡𝑎𝑙𝑙𝑎𝑡𝑖𝑜𝑛 𝑁𝐺 𝑈𝑠𝑒 𝐵𝑎𝑠𝑒𝑙𝑖𝑛𝑒 𝑁𝐺 𝑈𝑠𝑒 = 𝑇𝑜𝑡𝑎𝑙 𝐹𝑎𝑐𝑖𝑙𝑖𝑡𝑦 𝑁𝐺 𝑈𝑠𝑒 − 𝐷𝐻𝑊 𝑁𝐺 𝑈𝑠𝑒
𝑃𝑜𝑠𝑡 𝐼𝑛𝑠𝑡𝑎𝑙𝑙 𝑁𝐺 𝑈𝑠𝑒 =
𝐵𝑎𝑠𝑒𝑙𝑖𝑛𝑒 𝑁𝐺 𝑈𝑠𝑒 × 𝐶𝑢𝑟𝑟𝑒𝑛𝑡 𝐵𝑜𝑖𝑙𝑒𝑟 𝐸𝑓𝑓𝑖𝑐𝑖𝑒𝑛𝑐𝑦
𝑃𝑜𝑠𝑡 𝐼𝑛𝑠𝑡𝑎𝑙𝑙𝑎𝑡𝑖𝑜𝑛 𝑀𝑒𝑎𝑠𝑢𝑟𝑒𝑑 𝐸𝑓𝑓𝑖𝑐𝑖𝑒𝑛𝑐𝑦 𝑥 𝑃𝑜𝑠𝑡 𝐼𝑛𝑠𝑡𝑎𝑙𝑙 𝐷𝑖𝑠𝑡𝑟𝑖𝑏𝑢𝑡𝑖𝑜𝑛 𝐸𝑓𝑓𝑖𝑐𝑖𝑒𝑛𝑐𝑦 641 of 1021
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𝐴𝑛𝑛𝑢𝑎𝑙 $ 𝑆𝑎𝑣𝑖𝑛𝑔𝑠 = 𝐴𝑛𝑛𝑢𝑎𝑙 𝑁𝐺 𝑆𝑎𝑣𝑖𝑛𝑔𝑠 × $/𝑇ℎ𝑒𝑟𝑚 𝑅𝑎𝑡𝑒
642 of 1021
Cortland County, NY
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3.10 FIM 10 – HVAC Upgrades at the County Office Building Pre-Installation Energy Use
Electric Usage (kWh/yr) Electric Use – Adjusted
Baseline (kWh/yr)9
Natural Gas Usage
(Therm/yr)
193,099 199,772 57,711
Post - Installation IGA Post - Installation Verified Variance Electric
Usage
(kWh/yr)
Natural
Gas Usage
(Therm/yr)
Electric
Usage
(kWh/yr)
Natural Gas
Usage
(Therm/yr)
Electric Usage
(kWh/yr)
Natural Gas
Usage
(Therm/yr)
32,678 41,621 49,688 44,134 -11,456 -2,513
Energy Savings - Guarantee10 Energy Savings - Verified Variance from IGA Guarantee
Electric
(kWh/yr)
Natural Gas
(Therm/yr)
Electric
(kWh/yr)
Natural Gas
(Therm/yr)
Electric
(kWh/yr)
Natural
(Therm/yr)
144,378 14,481 150,084 13,577 5,706 904
Overview
Installation of this FIM includes the following three upgrades:
o Install Building Automation System.
o Reduction in FCU and UV Operating Hours.
o VFDs installed on the chilled water and hot water pumps.
Stipulated Parameters
Stipulated parameters were based on current equipment nameplates, drawings, and engineering estimates. A summary of the stipulated parameters is listed in the tables below:
9 Baseline adjusted to include all temperature bins in pre and post calculation. 10 Includes a 0.90 safety factor as stated in original IGA proposal. 643 of 1021
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BMS Installation (Setup/Setback and Temperature Correction) Boiler Efficiency 92%
Chiller Efficiency (kW/ton) 1.0
Ventilation Rate (cfm) 2,625
Window U Factor (Btu/(h*sqft*°F)) 0.55
Wall U Factor (Btu/(h*sqft*°F)) 0.06
Roof U Factor (Btu/(h*sqft*°F)) 0.03
Window Area (ft²) 12,025
Wall Area (ft²) 51,205
Roof Area (ft²) 27,914
Air Infiltration Leakage (cfm/Ft²) 0.1
Building Solar Gain Heating Season (°F) Basement thru 2nd Floor 5 Building Solar Gain Cooling Season (°F) Basement thru 2nd Floor 10 Baseline Occ Heating Temperature (°F) Basement thru 2nd Floor 71.0 Baseline Unocc Heating Temperature (°F) Basement thru 2nd Floor 70.7 Proposed Occ Heating Temperature (°F) Basement thru 2nd Floor 70 Proposed Unocc Heating Temperature (°F) Basement thru 2nd Floor 65 Baseline Occ Cooling Temperature (°F) Basement thru 2nd Floor 74 Baseline Unocc Cooling Temperature (°F) Basement thru 2nd Floor 74 Proposed Occ Cooling Temperature (°F) Basement thru 2nd Floor 74 Proposed Unocc Cooling Temperature (°F) Basement thru 2nd Floor 80 Building Solar Gain Heating Season (°F) Third Floor 5
Building Solar Gain Cooling Season (°F) Third Floor 10
Baseline Occ Heating Temperature (°F) Third Floor 72.6
Baseline Unocc Heating Temperature (°F) Third Floor 71.7 Proposed Occ Heating Temperature (°F) Third Floor 70
Proposed Unocc Heating Temperature (°F) Third Floor 65
Baseline Occ Cooling Temperature (°F) Third Floor 74
Baseline Unocc Cooling Temperature (°F) Third Floor 74
Proposed Occ Cooling Temperature (°F) Third Floor 74
Proposed Unocc Cooling Temperature (°F) Third Floor 80
Boiler Efficiency 92%
Reduction in FCU and UV Operating Hours
Unit Ventilator Quantity 67
Unit Ventilator Total Power (HP) 8.4
Existing Unit Ventilator Motor Efficiency 30%
Unit Ventilator Part Load Factor 90%
Unit Ventilator Annual Operating Hours (hr/yr) 4,928
New Unit Ventilator Motor Efficiency 70%
Fan Coil Unit Quantity 55
Fan Coil Unit Total Power (HP) 0.9
Existing Fan Coil Unit Motor Efficiency 30%
Fan Coil Unit Part Load Factor 90%
644 of 1021
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Year 3 Measurement and Verification Report
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Savings Measurement Procedure
M&V Option A was selected to provide a cost-effective means to evaluate savings. The post-installation measurement parameters that were made are as follows:
• EMS Space Temperature
• FCU and UV Operating Hours
• VFD Motor Power Draw from EMS
EMS Space Temperatures
SmartWatt energy engineers retrieved trend data from the energy management system for the 2019 calendar year. The table below represents the total average space temperature for that time period for a representative sample of the building.
Fan Coil Unit Annual Operating Hours (hr/yr) 4,928
VFD Improvements
Hot Water Pump Rated Power (HP) 10
Hot Water Pump Motor Efficiency 91.0%
Hot Water Pump Load Factor 90%
Chilled Water Pump Rated Power (HP) 7.5
Chilled Water Pump Motor Efficiency 91.7%
Chilled Water Pump Load Factor 90%
Minimum Fluid Flow 30%
Heating On point for HW pump (degF) 50
Cooling On point for CW pump (degF) 55
Annual Operating Hours BinMaker Pro (See Appendix B of the IGA) % Flow at each BIN Appendix B of the IGA
VFD Efficiency 98%
Basement – 2
nd Floor Summary
IGA Temperatures
(°F)
Verified
Temperatures (°F)
Post Installation Occupied
Heating Temperature 70 70.1
Post Installation Unoccupied
Heating Temperature 65 67.4
Post Installation Occupied
Cooling Temperature 74 73.4
Post Installation Unoccupied
Cooling Temperature 80 74.2
3 rd Floor Summary
645 of 1021
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The figures below are a graphical representation of the set points along with the space temperature for the month of January 2019 to illustrate the temperature trends of the building. On some dates, space temperatures are trending higher than the programmed setpoint. The graphs below indicate that electric space heater use within the building could be attributing to the higher than anticipated space temperatures. This was noted in Year 1 and brought to the County’s attention by SmartWatt throughout Year 2 check ins.
IGA Temperatures
(°F)
Verified
Temperatures (°F)
Post Installation Occupied
Heating Temperature 70 70.3
Post Installation Unoccupied
Heating Temperature 65 67.2
Post Installation Occupied
Cooling Temperature 74 73.3
Post Installation Unoccupied
Cooling Temperature 80 75.6
646 of 1021
Cortland County, NY
Year 3 Measurement and Verification Report
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647 of 1021
Cortland County, NY
Year 3 Measurement and Verification Report
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FCU and UV Operating Hours
SmartWatt energy engineers have trended run times of the fan coil units (FCUs) and the unit ventilators (UVs) for the 2019 calendar year. The tables below represent the verified Year 2 run times compared to the verified run times from the trend data for Year 1. The verified hours of the unit ventilators are slightly lower on the first 3 floors and slightly higher on the 3rd floor. This is an overall reduction from the Year 1 run-times in the last column of the tables below.
COB UV & FCU Fan Run Times B-2
nd Floor
IGA Proposed Run
Time (Hours)
Verified Run Time -
Year 2 (Hours)
Verified Run Time -
Year 1 (Hours)
Unit Ventilators - 750 CFM 1095 746 817
Unit Ventilators - 1,000 CFM 1095 746 817
Unit Ventilators - 1,250 CFM 1095 746 817
Unit Ventilators - 1,500 CFM 1095 746 817
Fan Coil Units 1095 1267 2071
COB UV & FCU Fan Run Times 3rd Floor
IGA Proposed Run
Time (Hours)
Verified Run Time
– Year 2 (Hours)
Verified Run Time
– Year 1 (Hours)
Unit Ventilators 1095 1623 1057
Fan Coil Units 1095 1059 2780
648 of 1021
Cortland County, NY
Year 3 Measurement and Verification Report
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VFD Motor Power Draw
SmartWatt energy engineers retrieved trend data from the energy management system for the COB Chilled water and hot water loop pumps. The post installation motor power is input into the energy savings calculations to verify post installation energy use.
During the IGA, power of the motor is calculated using the fan laws. The power is a cubic function of the speed of the motor. This means that as the speed decreases, the fan power decreases by an exponential power of 3.
During Year 2 of the term, the power was pulled directly from the building energy management system for each bin listed in the tables below. The % power was a direct relation of the average energy vs max energy use for each bin.
Tables 11 and 12 illustrate the change in power from what was proposed in the IGA to the verified VFD power.
During Year 1 The verified power represented a larger power draw during the middle temperature bins. This was addressed during Year 2 of the term and the lower percent power is reflective during the cooling bins.
Table 9: IGA Proposed VFD Power Table 10: Year 2 - Verified VFD Power The shortfall in savings as it relates to this item of the project is associated with reduced setbacks during unoccupied times than anticipated. The occupied temperatures are also slightly higher on the heating and lower BIN Hours Proposed Power
with VFD (%)
95 to 100 102%
90 to 95 75%
85 to 90 52%
80 to 85 34%
75 to 80 21%
70 to 75 11%
65 to 70 5%
60 to 65 5%
55 to 60 5%
50 to 55 0%
45 to 50 5%
40 to 45 5%
35 to 40 5%
30 to 35 5%
25 to 30 10%
20 to 25 16%
15 to 20 25%
10 to 15 35%
5 to 10 48%
0 to 5 63%
-5 to 0 81%
-10 to -6 102%
BIN Hours Verified Power
on VFD (%)
95 to 100 41%
90 to 95 51%
85 to 90 11%
80 to 85 5%
75 to 80 3%
70 to 75 2%
65 to 70 1%
60 to 65 2%
55 to 60 1%
50 to 55 2%
45 to 50 2%
40 to 45 69%
35 to 40 34%
30 to 35 71%
25 to 30 71%
20 to 25 72%
15 to 20 72%
10 to 15 73%
5 to 10 74%
0 to 5 76%
-5 to 0 78%
-10 to -6 102%
649 of 1021
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on the cooling. This results in more energy use than anticipated. SmartWatt has worked with the occupants and County staff during Year 2 of the term to address the temperatures through frequent check-ins. However, the schedules and temperatures are still being overridden and, in some cases, result in the temperatures being slightly higher than anticipated. This is an improvement from Year 1, but the overall measure is still slightly below the anticipated savings amount.
650 of 1021
Cortland County, NY
Year 3 Measurement and Verification Report
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3.11 FIM 11 – Replace RTUs in the County Office Building Pre-Installation
Pre-Installation Electric Use (kWh/yr)
106,912
Post - Installation
Post – Installation IGA
Electric Use (kWh/yr)
Post - Installation Verified
Electric Use (kWh/yr) Variance (kWh/yr)
40,415 43,853 (3,438)
Energy Savings
Guaranteed kWh
Savings11 (kWh/yr)
Verified kWh Savings
(kWh/yr)
Variance from
Guarantee (kWh/yr)
59,847 63,059 3,212
Overview
Installation of this FIM included the following upgrades:
• Replaced 5 existing rooftop units with 5 new Carrier roof top units. • Reduced RTU unoccupied motor run time.
The measurement and verification plan outlined in the IGA required measurements for this FIM to be Performed in Year 1 only. Therefore, the measurements made below are representative from Year 1 of the project term and reflected accordingly.
Stipulated Parameters
Stipulated parameters were based on current equipment nameplates, drawings, and engineering estimates. A summary of the stipulated parameters is listed in the table below:
11 Includes a 0.90 safety factor as stated in original IGA proposal. 651 of 1021
Cortland County, NY
Year 3 Measurement and Verification Report
(C) 2021 Centrica plc.
Savings Measurement Procedure
M&V Option A was selected to provide a cost-effective means to evaluate savings. The post-installation measurement parameters that were made are as follows:
• Visual Inspection of RTUs and SEER
• Operating hours during unoccupied periods
• RTU motor power and energy from as-built package
Post FIM Measurement Procedure
SmartWatt has verified the SEER of the units being installed compared to the proposed SEER from the as-built package. The Verified SEER was approximately 13% lower than anticipated. Due to the guarantee being at 90% and the slight surplus in verified unoccupied run times, the measure has a net positive total of 3,212 kWh.
SEER
IGA Proposed SEER Verified SEER
17.1 14.8
The tables below represent the verified reduction in runtime during unoccupied hours compared to the runtime hours proposed in the IGA. The RTU fan run times were taken from the EMS trends over a 1 year period (2018).
COB RTUs
Total Cooling Rating (Tons) 60
Average EER of RTUs including degradation 6.16
Equivalent Full Load Operating Hours (hr/yr) from NYS Tech Manual 667 Total Supply Fan Rating (HP) 11
Supply Fan Runtime During Unoccupied Periods 3,528
Supply Fan Part Load Factor 90%
Existing Supply Fan Efficiency 90%
Proposed Supply Fan Efficiency 92%
RTU Run Times During Unoccupied Hours
IGA Proposed Run
Time (Hours)
Verified Run Time
(Hours)
AC-1 1536 1369
AC-2 1536 1444
AC-3 1536 1123
AC-4 1536 1654
AC-5 1536 1519
652 of 1021
Cortland County, NY
Year 3 Measurement and Verification Report
(C) 2021 Centrica plc.
The verified run hours were approximately 7.5% (571 hours) lower than proposed and resulted in a slight surplus in energy savings.
Saving Measurement Procedure
Energy savings are calculated through the increase in RTU efficiency (EER) as well as a reduction in the supply fan run time during unoccupied periods. Each saving calculation is defined below:
𝐸𝐸𝑅𝑀𝑒𝑎𝑠𝑢𝑟𝑒𝑑 =
𝑅𝑎𝑡𝑒𝑑 𝐵𝑡𝑢 𝑜𝑓 𝐶𝑜𝑜𝑙𝑖𝑛𝑔 𝑇𝑜𝑛𝑠
𝑀𝑒𝑎𝑠𝑢𝑟𝑒𝑑 𝑊𝑎𝑡𝑡 ℎ𝑜𝑢𝑟𝑠
Energy efficiency savings are calculated as follows:
𝐸𝑛𝑒𝑟𝑔𝑦 𝐸𝑓𝑓𝑖𝑐𝑖𝑒𝑛𝑐𝑦 𝑆𝑎𝑣𝑖𝑛𝑔𝑠 (
𝑘𝑊ℎ
𝑦𝑟 ) = 𝐶𝑢𝑟𝑟𝑒𝑛𝑡 𝑅𝑇𝑈 𝑈𝑠𝑎𝑔𝑒 − 𝑃𝑜𝑠𝑡 𝐼𝑚𝑝𝑙𝑒𝑚𝑒𝑛𝑡𝑎𝑡𝑖𝑜𝑛 𝑅𝑇𝑈 𝑈𝑠𝑎𝑔𝑒 𝐶𝑜𝑠𝑡 𝑆𝑎𝑣𝑖𝑛𝑔𝑠 = (𝑘𝑊ℎ 𝑆𝑎𝑣𝑖𝑛𝑔𝑠 ∗
$
𝑘𝑊ℎ
𝑅𝑎𝑡𝑒)
𝐶𝑢𝑟𝑟𝑒𝑛𝑡 𝑅𝑇𝑈 𝑈𝑠𝑎𝑔𝑒
= 𝐶𝑜𝑜𝑙𝑖𝑛𝑔 𝑡𝑜𝑛𝑠 𝑥 12,000
𝐵𝑡𝑢
𝑡𝑜𝑛
𝑥 𝐶𝑜𝑜𝑙𝑖𝑛𝑔 𝐹𝑢𝑙𝑙 𝐿𝑜𝑎𝑑 𝐻𝑜𝑢𝑟𝑠 ÷ 𝐸𝐸𝑅𝐶𝑢𝑟𝑟𝑒𝑛𝑡 ÷ 1,000 𝑊/𝑘𝑊
𝑃𝑜𝑠𝑡 𝐼𝑚𝑝𝑙𝑒𝑚𝑒𝑛𝑡𝑎𝑡𝑖𝑜𝑛 𝑅𝑇𝑈 𝑈𝑠𝑎𝑔𝑒 =
= 𝐶𝑜𝑜𝑙𝑖𝑛𝑔 𝑡𝑜𝑛𝑠 𝑥 12,000
𝐵𝑡𝑢
𝑡𝑜𝑛
𝑥 𝐶𝑜𝑜𝑙𝑖𝑛𝑔 𝐹𝑢𝑙𝑙 𝐿𝑜𝑎𝑑 𝐻𝑜𝑢𝑟𝑠 ÷ 𝐸𝐸𝑅𝑀𝑒𝑎𝑠𝑢𝑟𝑒𝑑 ÷ 1,000 𝑊/𝑘𝑊
653 of 1021
Cortland County, NY
Year 3 Measurement and Verification Report
(C) 2021 Centrica plc.
3.12 FIM 12 – Replace Domestic Hot Water Heater at the COB Pre-Installation
Pre-Installation Electric Use (kWh/yr)
0 Post - Installation
Post – Installation IGA
Electric (kWh/yr)
Post - Installation Verified
Electric (kWh/yr) Variance (kWh/yr)
1,950 1,950 0
Energy Savings
Guaranteed Electric
Savings (kWh/yr)
Verified Electric Savings
(kWh/yr)
Variance from
Guarantee (kWh/yr)
(1,950) (1,950) 0
Overview
SmartWatt installed a new 40 gallon storage-type electric hot water heater adjacent to the locker rooms serving the gymnasium area. This unit acts as a supplementary heater for the locker room showers. The installation of this measure results in a negative savings due to the baseline being zero. The measurement and verification plan outlined in the IGA required measurements for this FIM to be Performed in Year 1 only. Therefore, the measurements made below are representative from Year 1 of the project term and reflected accordingly.
Stipulated Parameters
The unit heating capacity is based on the manufacturer’s rating of 4.5 kW.
Post FIM Measurement Procedure
SmartWatt has verified that the installed water heater has been installed as proposed and designed.
Saving Measurement Procedure
Energy savings were calculated by using the equations below:
𝐴𝑛𝑛𝑢𝑎𝑙 𝐸𝑛𝑒𝑟𝑔𝑦 𝑆𝑎𝑣𝑖𝑛𝑔𝑠 = 𝐵𝑎𝑠𝑒𝑙𝑖𝑛𝑒 𝐸𝑛𝑒𝑟𝑔𝑦 𝑈𝑠𝑎𝑔𝑒 − 𝑃𝑜𝑠𝑡 𝐼𝑛𝑠𝑡𝑎𝑙𝑙𝑎𝑡𝑖𝑜𝑛 𝐸𝑛𝑒𝑟𝑔𝑦 𝑈𝑠𝑎𝑔𝑒 𝐴𝑛𝑛𝑢𝑎𝑙 $ 𝑆𝑎𝑣𝑖𝑛𝑔𝑠 = 𝐴𝑛𝑛𝑢𝑎𝑙 𝐸𝑛𝑒𝑟𝑔𝑦 𝑆𝑎𝑣𝑖𝑛𝑔𝑠 ×
$
𝑘𝑊ℎ
𝑅𝑎𝑡𝑒
𝐵𝑎𝑠𝑒𝑙𝑖𝑛𝑒 𝐸𝑛𝑒𝑟𝑔𝑦 𝑈𝑠𝑎𝑔𝑒 = 0
𝑘𝑊ℎ
𝑦𝑟
(𝑛𝑜 𝑒𝑥𝑖𝑠𝑡𝑖𝑛𝑔 𝑢𝑛𝑖𝑡)
𝑃𝑜𝑠𝑡 𝐼𝑛𝑠𝑡𝑎𝑙𝑙𝑎𝑡𝑖𝑜𝑛 𝐸𝑛𝑒𝑟𝑔𝑦 𝑈𝑠𝑎𝑔𝑒 = 𝑈𝑛𝑖𝑡 𝐻𝑒𝑎𝑡𝑖𝑛𝑔 𝐶𝑎𝑝𝑐𝑖𝑡𝑦 𝑥 𝐴𝑛𝑛𝑢𝑎𝑙 𝑂𝑝𝑒𝑟𝑎𝑡𝑖𝑛𝑔 𝐻𝑜𝑢𝑟𝑠 654 of 1021
Cortland County, NY
Year 3 Measurement and Verification Report
(C) 2021 Centrica plc.
3.13 FIM 13 – HVAC Upgrades at the Courthouse
Pre-Installation Energy Use
Electric Usage (kWh/yr) Natural Gas Usage
(Therm/yr)
43,734 111,621
Post - Installation IGA Post - Installation Verified Variance Electric
Usage
(kWh/yr)
Natural
Gas Usage
(Therm/yr)
Electric
Usage
(kWh/yr)
Natural Gas
Usage
(Therm/yr)
Electric Usage
(kWh/yr)
Natural Gas
Usage
(Therm/yr)
23,982 60,115 33,065 71,002 9,083 10,887
Energy Savings - Guarantee12 Energy Savings - Verified Variance from IGA Guarantee
Electric (kWh/yr)
Natural
Gas
(Therm/yr)
Electric
(kWh/yr)
Natural Gas
(Therm/yr)
Electric
(kWh/yr)
Natural
(Therm/yr)
17,777 46,355 10,668 40,619 (7,109) (5,736)
Overview
Installation of this FIM included the following three upgrades:
o Installation of BMS (Unoccupied Period Setback/Setup) o Reduction in AHU Operating Hours
o Steam Trap Replacement
Stipulated Parameters
Stipulated parameters were based on current equipment nameplates, drawings, and engineering estimates. A summary of the stipulated parameters is listed in the tables below:
12 Includes a 0.90 safety factor as stated in original IGA proposal. 655 of 1021
Cortland County, NY
Year 3 Measurement and Verification Report
(C) 2021 Centrica plc.
BMS Installation (Setup/Setback and Temperature Correction) Boiler Efficiency 80%
Chiller Efficiency (kW/ton) 1.0
Ventilation Rate (cfm) 8,850
Window U Factor (Btu/(h*sqft*°F)) 0.9
Wall U Factor (Btu/(h*sqft*°F)) 0.12
Roof U Factor (Btu/(h*sqft*°F)) 0.06
Window Area (ft²) 5,673
Wall Area (ft²) 31,287
Roof Area (ft²) 13,409
Air Infiltration Leakage (cfm/Ft²) 0.3
Building Solar Gain Heating Season (°F) 5
Building Solar Gain Cooling Season (°F) 10
Baseline Occ Heating Temperature (°F) 74.0
Baseline Unocc Heating Temperature (°F) 73.3
Proposed Occ Heating Temperature (°F) 70
Proposed Unocc Heating Temperature (°F) 64
Baseline Occ Cooling Temperature (°F) 74
Baseline Unocc Cooling Temperature (°F) 74
Proposed Occ Cooling Temperature (°F) 74
Proposed Unocc Cooling Temperature (°F) 80
Reduction in AHU Operating Hours
AHU Quantity 2
AHU Fan Total Power (HP) 4.5
Existing Fan Motor Efficiency 87.2%
Fan Part Load Factor 90%
Current Annual Operating Hours (hr/yr) 4,777
Steam Trap Replacements
Steam Trap Inventory See Appendix E of the IGA
Total Number of Steam Traps 178
Percentage of Failed Steam Traps (from survey) 49%
Total Number of Failed Steam Traps with 1/16”
Diameter Orifice
37 Total Number of Failed Steam Traps with 3/32”
Diameter Orifice
50 Steam Hours of Operation (hr/yr) 4,996
Boiler Efficiency 80%
Steam Pressure 5 psig
656 of 1021
Cortland County, NY
Year 3 Measurement and Verification Report
(C) 2021 Centrica plc.
Savings Measurement Procedure
M&V Option A was selected to provide a cost-effective means to evaluate savings. The post-installation measurement parameters that were made are as follows:
• EMS Space Temperature
• AHU Operating Hours
• Steam Trap Installation Verification
EMS Space Temperatures
SmartWatt energy engineers retrieved trend data from the energy management system for the 2019 calendar year. The table below represents the total average space temperature for that time period for a representative sample of the building.
The figure below is a representative sample of the set points along with the space temperature for the month of January 2019 to illustrate the temperature trends of the building. Most of the time, space temperatures are trending higher than the programmed setpoint. The setback temperatures, particularly in the cooling season are not reaching the designed setback temperatures. In addition to the lack of setback, the schedule runs in occupied mode from 6:00am – 9:00PM in most areas. These temperatures and schedules are noted and were addressed with the County staff during Year 2 of the term. However, during frequent check-ins, the schedules are still being overridden and adjusted to reflect the run times noted above.
Courthouse Temperature Summary
IGA Temperatures
(°F)
Verified
Temperatures (°F)
Post Installation Occupied
Heating Temperature 70 71.8
Post Installation Unoccupied
Heating Temperature 64 69.8
Post Installation Occupied
Cooling Temperature 74 72.9
Post Installation Unoccupied
Cooling Temperature 80 73.5
657 of 1021
Cortland County, NY
Year 3 Measurement and Verification Report
(C) 2021 Centrica plc.
AHU Operating Hours
SmartWatt energy engineers have trended run times of the AHUs for the 2019 calendar year. The baseline runtime of the units was 4777 annual hours. The tables below represent the proposed run times compared to the verified run times from the EMS trend data for Year 2.
The verified run times for Year 2 were net lower for the 2 AHUs combined. This was addressed during Year 2 of the term to allow for increased verified energy savings.
Steam Trap Replacements
SmartWatt has replaced 178 steam traps and verified the proper installation of the new equipment to be sure they operate as designed. The new steam traps match closely with the proposed steam traps represented in the IGA. This was verified in Year 1 of the term.
COB UV & FCU Fan Run Times B-2
nd Floor
IGA Proposed Run
Time (Hours)
Verified Run Time –
Year 2 (Hours)
Verified Run Time –
Year 1 (Hours)
AHU-1 955 840 729
AHU-2 955 684 1770
Figure 4: Courthouse Temperature Summary - January
658 of 1021
Cortland County, NY
Year 3 Measurement and Verification Report
(C) 2021 Centrica plc.
3.14 FIM 14 – Insulate Basement Steam Piping at Courthouse Pre-Installation
Pre-Installation Gas Use (Therm/yr)
924
Post - Installation
Post – Installation IGA
Natural Gas (Therm/yr)
Post - Installation Verified
Natural Gas (Therm/yr) Variance (Therm/yr)
69 69 0
Energy Savings
Guaranteed NG Savings
(Therm/yr)
Verified NG Savings
(Therm/yr)
Variance from
Guarantee (Therm/yr)
855 855 0
Overview
SmartWatt installed 3” insulation on approximately 50’ of 3” steam condensate pipes located in the south-east area of the basement. The measurement and verification plan outlined in the IGA required measurements for this FIM to be Performed in Year 1 only. Therefore, the measurements made below are representative from Year 1 of the project term and reflected accordingly.
Stipulated Parameters
The unit heating capacity is based on the manufacturer’s rating of 4.5 kW.
Post FIM Measurement Procedure
Visual inspection of insulation to be sure insulation thickness and pipe temperatures were verified accordingly.
During installation of the project 3” fiberglass pipe insulation was installed. This exceeds the specifications of the original pipe insulation.
Pipe Insulation Stipulated Parameters
Heating Hours of Operation 5,024
Boiler Efficiency 80%
Insulation Conductivity k
(Btuh/ft² * °F/inch) 0.26
Insulation Surface Resistance
Rs (ft² * °F/Btuh) 0.50
659 of 1021
Cortland County, NY
Year 3 Measurement and Verification Report
(C) 2021 Centrica plc.
Saving Measurement Procedure
Energy savings were calculated by using the equations below:
𝐸𝑛𝑒𝑟𝑔𝑦 𝑆𝑎𝑣𝑖𝑛𝑔𝑠 (𝑄) = 𝐵𝑎𝑠𝑒𝑙𝑖𝑛𝑒 𝐻𝑒𝑎𝑡𝑙𝑜𝑠𝑠 − 𝑃𝑟𝑜𝑝𝑜𝑠𝑒𝑑 𝐻𝑒𝑎𝑡 𝐿𝑜𝑠𝑠 𝐵𝑎𝑠𝑒𝑙𝑖𝑛𝑒 𝐻𝑒𝑎𝑡𝑙𝑜𝑠𝑠 =
𝑏𝑎𝑟𝑒 𝑝𝑖𝑝𝑒 ℎ𝑒𝑎𝑡 𝑙𝑜𝑠𝑠 𝑝𝑒𝑟 𝑓𝑜𝑜𝑡 𝑥 𝑝𝑖𝑝𝑒 𝑙𝑒𝑛𝑔𝑡ℎ 𝑥 ℎ𝑒𝑎𝑡𝑖𝑛𝑔 ℎ𝑜𝑢𝑟𝑠 𝑜𝑓 𝑜𝑝𝑒𝑟𝑎𝑡𝑖𝑜𝑛 𝑏𝑜𝑖𝑙𝑒𝑟 𝑒𝑓𝑓𝑖𝑐𝑖𝑒𝑛𝑐𝑦
𝑃𝑟𝑜𝑝𝑜𝑠𝑒𝑑 𝐻𝑒𝑎𝑡𝑙𝑜𝑠𝑠 = ((𝑇𝑠 − 𝑇𝑎) ∗ 𝐴/(rs + 𝐼𝑇 ∗
ln(
𝑟𝑠
𝑟𝑝)
𝑘
+ 𝑅𝑠)/(𝑏𝑜𝑖𝑙𝑒𝑟 𝑒𝑓𝑓𝑖𝑐𝑖𝑒𝑛𝑐𝑦)) x pipe length x heating
hours of operation
𝐸𝑛𝑒𝑟𝑔𝑦 𝐶𝑜𝑠𝑡 𝑆𝑎𝑣𝑖𝑛𝑔𝑠 $ = (
𝐸𝑛𝑒𝑟𝑔𝑦 𝑆𝑎𝑣𝑖𝑛𝑔𝑠
100,000 ) 𝑥
$
𝑡ℎ𝑒𝑟𝑚
𝑁𝑎𝑡𝑢𝑟𝑎𝑙 𝐺𝑎𝑠
Where:
Ts = Pipe surface temperature equal to fluid temperature (°F) Ta = Ambient Temperature (°F)
A = Surface Area (sqft/ft)
rs = radius of outer surface (in)
IT = Insulation Thickness (in)
rp = Pipe Radius (in)
k = Thermal conductivity of insulation, Btuh/(sqft* °F/inch) Rs = Surface resistance (sq ft*°F/Btuh)
660 of 1021
Cortland County, NY
Year 3 Measurement and Verification Report
(C) 2021 Centrica plc.
3.15 FIM 15 – Replace Suite 301 AC Unit at the Courthouse Pre-Installation
Pre-Installation Electric Use (kWh/yr)
12,487
Post - Installation
Post – Installation IGA
Electric Use (kWh/yr)
Post - Installation Verified
Electric Use (kWh/yr) Variance (kWh/yr)
5,973 5,197 (776)
Energy Savings
Guaranteed kWh
Savings13 (kWh/yr)
Verified kWh Savings
(kWh/yr)
Variance from
Guarantee (kWh/yr)
5,863 7,290 1,427
Overview
Installation of This FIM includes replacing the existing 10-ton DX cooling unit with a new high efficiency Carrier Unit. The measurement and verification plan outlined in the IGA required measurements for this FIM to be Performed in Year 1 only. Therefore, the measurements made below are representative from Year 1 of the project term and reflected accordingly.
Stipulated Parameters
Stipulated parameters were based on current equipment nameplates, drawings, and engineering estimates. A summary of the stipulated parameters is listed in the table below:
Post FIM Measurement Procedure
SmartWatt has verified the SEER of the units being installed compared to the proposed SEER. The Verified SEER was approximately 13% higher than anticipated. This was the reason for the slight surplus in savings for this measure.
SEER
13 Includes a 0.90 safety factor as stated in original IGA proposal.
COB RTUs
Total Cooling Rating (Tons) 60
Average EER of RTUs including degradation 6.16
Equivalent Full Load Operating Hours (hr/yr) from NYS Tech Manual 667 661 of 1021
Cortland County, NY
Year 3 Measurement and Verification Report
(C) 2021 Centrica plc.
IGA Proposed SEER Verified SEER
13.4 15.4
Saving Measurement Procedure
Energy savings are calculated through the increase in RTU efficiency (SEER). The saving calculation is defined below:
𝑆𝐸𝐸𝑅𝑀𝑒𝑎𝑠𝑢𝑟𝑒𝑑 =
𝑅𝑎𝑡𝑒𝑑 𝐵𝑡𝑢 𝑜𝑓 𝐶𝑜𝑜𝑙𝑖𝑛𝑔 𝑇𝑜𝑛𝑠
𝑀𝑒𝑎𝑠𝑢𝑟𝑒𝑑 𝑊𝑎𝑡𝑡 ℎ𝑜𝑢𝑟𝑠
Energy efficiency savings are calculated as follows:
𝐸𝑛𝑒𝑟𝑔𝑦 𝐸𝑓𝑓𝑖𝑐𝑖𝑒𝑛𝑐𝑦 𝑆𝑎𝑣𝑖𝑛𝑔𝑠 (
𝑘𝑊ℎ
𝑦𝑟 ) = 𝐶𝑢𝑟𝑟𝑒𝑛𝑡 𝑅𝑇𝑈 𝑈𝑠𝑎𝑔𝑒 − 𝑃𝑜𝑠𝑡 𝐼𝑚𝑝𝑙𝑒𝑚𝑒𝑛𝑡𝑎𝑡𝑖𝑜𝑛 𝑅𝑇𝑈 𝑈𝑠𝑎𝑔𝑒 𝐶𝑜𝑠𝑡 𝑆𝑎𝑣𝑖𝑛𝑔𝑠 = (𝑘𝑊ℎ 𝑆𝑎𝑣𝑖𝑛𝑔𝑠 ∗
$
𝑘𝑊ℎ
𝑅𝑎𝑡𝑒)
𝐶𝑢𝑟𝑟𝑒𝑛𝑡 𝑅𝑇𝑈 𝑈𝑠𝑎𝑔𝑒
= 𝐶𝑜𝑜𝑙𝑖𝑛𝑔 𝑡𝑜𝑛𝑠 𝑥 12,000
𝐵𝑡𝑢
𝑡𝑜𝑛
𝑥 𝐶𝑜𝑜𝑙𝑖𝑛𝑔 𝐹𝑢𝑙𝑙 𝐿𝑜𝑎𝑑 𝐻𝑜𝑢𝑟𝑠 ÷ 𝑆𝐸𝐸𝑅𝐶𝑢𝑟𝑟𝑒𝑛𝑡 ÷ 1,000 𝑊/𝑘𝑊
𝑃𝑜𝑠𝑡 𝐼𝑚𝑝𝑙𝑒𝑚𝑒𝑛𝑡𝑎𝑡𝑖𝑜𝑛 𝑅𝑇𝑈 𝑈𝑠𝑎𝑔𝑒 =
= 𝐶𝑜𝑜𝑙𝑖𝑛𝑔 𝑡𝑜𝑛𝑠 𝑥 12,000
𝐵𝑡𝑢
𝑡𝑜𝑛
𝑥 𝐶𝑜𝑜𝑙𝑖𝑛𝑔 𝐹𝑢𝑙𝑙 𝐿𝑜𝑎𝑑 𝐻𝑜𝑢𝑟𝑠 ÷ 𝑆𝐸𝐸𝑅𝑀𝑒𝑎𝑠𝑢𝑟𝑒𝑑 ÷ 1,000 𝑊/𝑘𝑊
662 of 1021
Cortland County, NY
Year 3 Measurement and Verification Report
(C) 2021 Centrica plc.
3.16 FIM 16 – Water Fixture Upgrades
Pre-Installation Pre-Installation
Pre-Installation Water Use (kGal/yr) Pre-Installation Water Use – Adjusted Baseline (kGal/yr)14
932 935
Post - Installation
Post - Installation
Water Use (kGal/yr)
Post - Installation Verified
Water Use (kGal/yr) Variance (kGal/yr)
407 408 1
Water Savings
Guaranteed Water
Savings (kGal/yr)
Verified Electric Savings
(kGal/yr)
Variance from
Guarantee (kGal)
525 527 2
Energy Savings
Guaranteed NG Savings
(Therm/yr)
Verified NG Savings
(Therm/yr)
Variance from
Guarantee (Therm/yr)
682 685 3
Overview
SmartWatt has replaced existing water fixtures (toilets, flushometers, faucet flow restrictors) as described in the IGA report. The as-built water fixtures are included in Appendix 3. The measurement and verification plan outlined in the IGA required measurements for this FIM to be Performed in Year 1 only. Therefore, the measurements made below are representative from Year 1 of the project term and reflected accordingly.
Post FIM Measurement Procedure
SmartWatt has verified the proper installation and quantities of the water fixtures included in the scope of work.
The as-built quantities reflect the post installation water fixtures after project completion with the following exceptions.
• 1 Additional faucet verified in the County Office Building. • 2 Additional toilets verified in the County Office Building.
Savings Calculation Method
Water and energy savings were calculated based on the reduction in water consumption and lowered fuel or natural gas use associated with a reduction in hot water. A water and energy model was developed using the parameters stipulated in the IGA and are provided in Appendix B of the IGA. Appendix 3 of this report 14 Adjusted baseline to reflect added fixtures during construction. 663 of 1021
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(C) 2021 Centrica plc.
represents a sample flow rate measurement that was taken on site that match the stipulated flow rates in the IGA.
𝐴𝑛𝑛𝑢𝑎𝑙 𝑊𝑎𝑡𝑒𝑟 𝑆𝑎𝑣𝑖𝑛𝑔𝑠
= 𝐵𝑎𝑠𝑒𝑙𝑖𝑛𝑒 𝑤𝑎𝑡𝑒𝑟 𝑐𝑜𝑛𝑠𝑢𝑚𝑝𝑡𝑖𝑜𝑛 𝑓𝑜𝑟 𝑎𝑓𝑓𝑒𝑐𝑡𝑒𝑑 𝑓𝑖𝑥𝑡𝑢𝑟𝑒𝑠
− 𝑃𝑜𝑠𝑡 𝑖𝑛𝑠𝑡𝑎𝑙𝑙𝑎𝑡𝑖𝑜𝑛 𝑤𝑎𝑡𝑒𝑟 𝑐𝑜𝑛𝑠𝑢𝑚𝑝𝑡𝑖𝑜𝑛 𝑓𝑜𝑟 𝑎𝑓𝑓𝑒𝑐𝑡𝑒𝑑 𝑓𝑖𝑥𝑡𝑢𝑟𝑒𝑠 𝐴𝑛𝑛𝑢𝑎𝑙 𝐹𝑢𝑒𝑙 𝑆𝑎𝑣𝑖𝑛𝑔𝑠
= 𝐵𝑎𝑠𝑒𝑙𝑖𝑛𝑒 𝑓𝑢𝑒𝑙 𝑐𝑜𝑛𝑠𝑢𝑚𝑝𝑡𝑖𝑜𝑛 𝑓𝑜𝑟 𝐷𝐻𝑊 𝑓𝑖𝑥𝑡𝑢𝑟𝑒𝑠
− 𝑃𝑜𝑠𝑡 𝑖𝑛𝑠𝑡𝑎𝑙𝑙𝑎𝑡𝑖𝑜𝑛 𝑓𝑢𝑒𝑙 𝑐𝑜𝑛𝑠𝑢𝑚𝑝𝑡𝑖𝑜𝑛 𝑓𝑜𝑟 𝐷𝐻𝑊 𝑓𝑖𝑥𝑡𝑢𝑟𝑒𝑠
𝐴𝑛𝑛𝑢𝑎𝑙 $ 𝑆𝑎𝑣𝑖𝑛𝑔𝑠 = 𝐴𝑛𝑛𝑢𝑎𝑙 𝑤𝑎𝑡𝑒𝑟 𝑠𝑎𝑣𝑖𝑛𝑔𝑠 ×
$
𝑘𝐺𝑎𝑙 𝑅𝑎𝑡𝑒 + 𝑎𝑛𝑛𝑢𝑎𝑙 𝑛𝑎𝑡𝑢𝑟𝑎𝑙 𝑔𝑎𝑠 𝑠𝑎𝑣𝑖𝑛𝑔𝑠 ×
$
𝑇ℎ𝑒𝑟𝑚
𝑅𝑎𝑡𝑒
664 of 1021
Cortland County, NY
Year 3 Measurement and Verification Report
(C) 2021 Centrica plc.
3.17 FIM 17 – Replace Transformers
SmartWatt has replaced twelve (12) transformers at the following locations:
• 10 at the County Office Building
• 1 at the Recycle Center
• 1 at the Highway Garage
Pre-Installation
Pre-Installation Energy Use (kWh/yr)
87,235
Post - Installation
Post - Installation
Electric Usage (kWh/yr)
Post - Installation Verified
Energy Use (kWh/yr) Variance (kWh/yr)
18,839 18,839 0
Energy Savings
Guaranteed Electric
Savings (kWh/yr)
Verified Electric Savings
(kWh/yr)
Variance from
Guarantee
68,396 68,486 90
Overview
Installation of this FIM includes replacement of the transformers at the County Office Building, Recycle Center, and Highway Garage with high efficiency low loss transformers. The measurement and verification plan outlined in the IGA required measurements for this FIM to be Performed in Year 1 only. Therefore, the measurements made below are representative from Year 1 of the project term and reflected accordingly.
Post FIM Measurement Procedure
SmartWatt has verified the proper installation of the transformers along with measuring post install input power on a sample of transformers. The post install kVA of the transformers was equal to the proposed kVA of the transformers.
Savings Calculation Method
Energy savings are calculated based on a decrease in transformer losses. Based on the results of the metering sample the expected efficiencies were determined. The losses of the custom-built transformers were tested at the manufacturer at the same input load as measured on-site.
𝐴𝑛𝑛𝑢𝑎𝑙 𝑘𝑊ℎ 𝑆𝑎𝑣𝑖𝑛𝑔𝑠 = 𝑀𝑒𝑎𝑠𝑢𝑟𝑒𝑑 𝐵𝑎𝑠𝑒𝑙𝑖𝑛𝑒 𝐿𝑜𝑠𝑠𝑒𝑠 − 𝑀𝑒𝑎𝑠𝑢𝑟𝑒𝑑 𝑃𝑜𝑠𝑡 𝐼𝑛𝑠𝑡𝑎𝑙𝑙𝑎𝑡𝑖𝑜𝑛 𝐿𝑜𝑠𝑠𝑒𝑠 𝐴𝑛𝑛𝑢𝑎𝑙 $ 𝑆𝑎𝑣𝑖𝑛𝑔𝑠 = 𝐴𝑛𝑛𝑢𝑎𝑙 𝑘𝑊ℎ 𝑆𝑎𝑣𝑖𝑛𝑔𝑠 ×
$
𝑘𝑊ℎ
𝑅𝑎𝑡𝑒
665 of 1021
Cortland County, NY
Measurement and Verification Report
(C) 2019 SmartWatt Energy, Inc., All Rights Reserved
61 666 of 1021
Appendix C –
Sample Performance
Energy Contract
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DESIGN-BUILD ENERGY SERVICES AGREEMENT
THIS DESIGN-BUILD ENERGY SERVICES AGREEMENT (this “Agreement”) is made and effective ____________________________ (the “Effective Date”), by and between ________________________________________________ (“Owner”), with an address at ________________________________________________, and CENTRICA BUSINESS SOLUTIONS SERVICES, INC. (“Centrica Business Solutions” or sometimes referred, “Contractor”), with an address at 2111 Ellsworth Boulevard, Malta, New York 12020. Owner and Centrica Business Solutions Services, Inc. are sometimes referred to herein, individually, as a “Party”, and, collectively, as the “Parties”.
RECITALS
A. Owner is a ____________________________________ incorporated under the laws of the State of California, and is a Public Agency within the meaning of the California Government Code 4217.10 et seq. (“4217 Code”)
B. Owner owns and operates certain facilities described on the attached Schedule 1 (the “Facilities”), and desires to procure long-term energy cost savings and reduce related expenses in the operation of such Facilities.
C. Centrica Business Solutions is a New York business corporation and is duly authorized to do business in the State of California and is a Qualified Energy Service Company within the meaning of the 4217 Code, engaged in the business of and having experience and capabilities in providing energy efficiency services, including Energy Conservation Measures (“ECMs”), as defined in the 4217 Code.
D. Pursuant to Centrica Business Solutions' Proposal, Centrica Business Solutions and Owner entered into an Investment Grade Audit Agreement, pursuant to which Centrica Business Solutions conducted an investment grade audit and delivered to Owner a detailed engineering and economic report (the “IGA Report’) that specifically identifies the ECMs that are recommended to be installed and/or implemented at the Facilities.
E. The governing body of Owner has determined, in its lawful discretion, prior to approval or ratification of this Agreement, that this Agreement meets all criteria required pursuant to California Government Code Sections 4217.10 et seq.
F. Pursuant to the IGA Report, Owner now desires to enter into this Agreement with Centrica Business Solutions as a Design-Build Energy Services Agreement for the installation and implementation of the ECMs at the Facilities (the “Project”).
NOW, THEREFORE, the Parties agree as follows:
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ARTICLE I
PRELIMINARY MATTERS
1.1 INCORPORATION. The Recitals set forth above are hereby incorporated into the body of this Agreement and made a binding part hereof.
1.2 THE IGA REPORT. The IGA Report is attached hereto as Exhibit A.
Owner acknowledges that it has approved and accepted the IGA Report, which identifies all ECMs to be performed under this Agreement.
1.3 CONTRACT DOCUMENTS. The entire agreement of the Parties with respect to the Project is contained in the “Contract Documents”, which consist of: 1) this Agreement ii) any Change Orders or other amendments to this Agreement, and iii) the following Exhibits and Schedules:
Exhibit A: The IGA Report
Exhibit B; Certificate of Substantial Completion
Exhibit C: Savings Reconciliation Report
Schedule 1: The Facilities
Schedule 2A: Scope of ECM Work
Schedule 2B: Scope of MM&V Services
Schedule 3: ECM Work Schedule
Schedule 4: As-Built Drawings Requirements
Schedule 5: Energy Savings Schedule
Schedule 6A: ECM Work Schedule of Values
Schedule 6B: MM&V Services Schedule of Values
The provisions of this Agreement shall control in the event of any conflict between its terms and those contained in any of the Exhibits or Schedules
ARTICLE II
SCOPE AND TERM
2.1 SCOPE OF THE PROJECT. The Project shall consist of two phases: 1) the “Construction & Installation Phase”, in which the Equipment (as hereinafter defined) will be designed, constructed and/or installed into the Facilities and the ECMs shall be implemented (the “ECM Work”), and 2) the “MM&V Services Phase”, in which Centrica Business Solutions will provide ongoing energy savings monitoring and reporting services, and management and/or modification of the Equipment (the “MM&V Services”). The full scope of the ECM Work and the MM&V Services are set forth and detailed, respectively, on the “Scope of ECM Work” attached as Schedule 2A, and the “Scope of MM&V Services” attached as Schedule 2B. Centrica Business Solutions shall be responsible for the professional and technical accuracy of the ECM Work and the MM&V Services, whether performed by Centrica Business Solutions or by subcontractors or others on its behalf.
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2.2 TERM. The term of this Agreement (the “Term”) shall commence on the Effective Date, and, unless sooner terminated in accordance with the terms hereof, shall continue for a period of _______________________________ (__________) years from the MM&V Services Commencement Date (as hereinafter defined), but subject to the termination rights provided in Sections 2.2.1.
2.2.1 RIGHT TO PARTIAL TERMINATION. At any time following the first (1st) anniversary of the MM&V Services Commencement Date, and upon at least sixty (60) days’ prior written notice to Centrica Business Solutions, Owner shall have the right to terminate non-required MM&V Services set forth on Schedule 2B. If Owner so elects to partially terminate, all of the then-applicable terms and provisions of this Agreement shall continue in full force and effect, except that the MM&V Services Fee shall be equitably adjusted by the Parties in a manner consistent with Schedule 6B.
ARTICLE III
THE ECM WORK
3.1 CONSTRUCTION AND INSTALLATION OF THE ECM WORK. Subject to the other provisions of this Agreement, Centrica Business Solutions will act as a turn-key designbuilder assuming total responsibility for the design, procurement of labor and materials for the improvements to the Facilities, and the installation and start-up of the energy efficiency equipment (the “Equipment”), as set forth in and in accordance with the Scope of ECM Work.
3.1.1 CONSTRUCTION SCHEDULE. The Construction and Installation Phase will commence upon either the issuance by Owner of a written notice to proceed or the written agreement of the Parties fixing such commencement date. The performance of the ECM Work shall be carried out and proceed in accordance with the schedule (the “ECM Work Schedule”) attached as Schedule 3. The ECM Work Schedule may be amended from time to time by the Parties due to changes in the ECM Work or other events affecting the completion of the ECM Work.
3.1.2 STATUTORY COMPLIANCE. In the performance of the ECM Work, including the installation of the Equipment, Centrica Business Solutions shall, and shall require all of its contractors, subcontractors, and all subcontractors under them to, as applicable, comply with the requirements of all applicable statutes and regulations. Without limiting the foregoing, Centrica Business Solutionsshall otherwise give all notices and comply with all laws and ordinances legally enacted at the date of execution of the Agreement that govern the proper performance of the ECM Work.
3.1.3 CALIFORNIA CONTRACTORS’ LICENSE. At all times during performance of construction services, Contractor shall be duly licensed and in good standing by the California Contractors State License Board under License #947569.
3.1.4 CONTRACTOR/SUBCONTRACTOR REGISTRATION. Pursuant to Labor Code Section 1771.1, “A contractor or subcontractor shall not be qualified to bid on, be listed in a bid proposal, subject to the requirements of Section 4104 of the Public Contract 670 of 1021
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Code, or engage in the performance of any contract for public work, as defined in this chapter, unless currently registered and qualified to perform public work pursuant to Labor Code Section 1725.5.” Contractor’s public works contractor registration number, issued by the Department of Industrial Relations is 1000661242.
3.1.5 PERMITS AND APPROVALS. Centrica Business Solutions shall be responsible for obtaining all necessary permits and approvals for the ECM Work, including the installation of the Equipment, and shall pay any and all permit fees. Owner shall use its best efforts to assist Centrica Business Solutions in obtaining all such necessary permits and approvals. The Equipment and the operation of the Equipment by Centrica Business Solutions shall conform to all federal, state and local code requirements in effect at the time of installation. Before Centrica Business Solutions commences any portion of the ECM Work that requires a permit or license, Centrica Business Solutions shall furnish copies of each such permit or license to Owner.
3.1.6 PERFORMANCE. Owner and Centrica Business Solutions shall coordinate the activities associated with the installation of the Equipment by Centrica Business Solutions with any ECM Work or installations by Owner, its employees and agents. Centrica Business Solutions shall not commit or permit any act that will materially interfere with the performance of business activities conducted by Owner or its employees without the prior written approval of Owner, which shall not be unreasonably withheld, and provided that the ECM Work Schedule shall be modified if Owner requires Centrica Business Solutions to delay or re-sequence the ECM Work in order to accommodate Owner’s operations. Centrica Business Solutions shall perform all of the ECM Work in such a manner so as not to harm the structural integrity of the Facilities or their operating systems.
Centrica Business Solutions shall repair and restore to its original condition any area of damage caused by Centrica Business Solutions' performance under this Agreement. Owner reserves the right to review the ECM Work and to direct Centrica Business Solutions to take corrective action if, in the reasonable opinion of Owner, the structural integrity of the Facilities or its systems is or will be harmed. All costs associated with such corrective action to address damage caused by Centrica Business Solutions' performance of the ECM Work shall be borne by Centrica Business Solutions. In addition, Centrica Business Solutions shall be responsible for the professional and technical accuracy of all ECM Work performed, whether by its own forces or by its subcontractors or others on its behalf.
Centrica Business Solutions is responsible for general broom cleaning, and shall, to the fullest extent practicable, at all times keep the Facilities clean and free of debris, rubbish and dust. At the completion of the ECM Work, Centrica Business Solutions shall remove from the worksite all construction equipment, tools, surplus materials, waste materials and debris.
3.2 DESIGN AND CONSTRUCTION DOCUMENTS. Drawings, specifications, and other documents, including those in electronic form, furnished or utilized by Centrica Business Solutions are instruments of service (the “Instruments of Service”). Centrica Business Solutions shall retain all common law, statutory and other reserved rights, including copyrights in the Instruments of Service. Drawings, specifications, and other documents and materials and electronic data are furnished for use solely with respect to the Project.
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3.2.1 Centrica Business Solutions grants to Owner a non-exclusive license to reproduce and use the Instruments of Service solely in connection with the Project, provided that Owner shall comply with all obligations, including prompt payment of sums when due.
Owner shall not assign or transfer any license herein to another party without prior written agreement of Centrica Business Solutions Any unauthorized reproduction or use of the Instruments of Service by Owner shall be at Owner’s sole risk and expense without liability to Centrica Business Solutions, and its design professionals. Termination of this Agreement due to the default of Owner shall terminate this license. If this Agreement is terminated for any reason other than the default of Owner, Owner shall have a nonexclusive license to use the Instruments of Service for the completion, use and maintenance of the Project. Submission or distribution of Centrica Business Solutions' documents to meet official regulatory requirements or for similar purposes in connection with the Project is not to be construed as publication in derogation of the rights reserved here.
3.2.2 Centrica Business Solutions shall pay all royalties and license fees that may be due on the inclusion of any patented or copyrighted materials, methods or systems selected by Centrica Business Solutions and incorporated in the ECM Work. Centrica Business Solutions shall defend, indemnify and hold Owner harmless from all suits or claims for infringement of any patent rights or copyrights arising out of such selection. Owner agrees to defend, indemnify and hold Centrica Business Solutions harmless from all suits or claims of infringement of any patent rights or copyrights arising out of any patented or copyrighted materials, methods or systems specified by Owner.
3.2.3 Centrica Business Solutions shall prepare and submit to Owner final marked up asbuilt drawings to the extent and as set forth in the attached Schedule 4.
3.3 WARRANTIES.
3.3.1 Centrica Business Solutions warrants that all materials and equipment furnished under the Construction and Installation Phase of this Agreement will be new unless otherwise specified, of good quality, in conformance with the Scope of ECM Work and all documents associated therewith, and free from defective workmanship and materials.
Warranties with respect to the ECM Work, or applicable portion of the ECM Work, as the case may be, shall commence on the date of Substantial Completion thereof (as hereinafter defined). Centrica Business Solutions agrees to correct all ECM Work that is defective in workmanship and/or materials within a period of one (1) year from the date of Substantial Completion.
3.3.2 Centrica Business Solutions shall collect, deliver, and, to the extent permissible, assign all manufacturers’ warranties and Equipment manuals to Owner. There are no warranties that extend beyond the description on the face of any such warranty.
3.3.3 ALL WARRANTIES NOT EXPRESSLY INCLUDED IN THIS AGREEMENT,
EXPRESS OR IMPLIED, INCLUDING THE WARRANTY OF MERCHANTABILITY
AND THE WARRANTY OF FITNESS FOR A PARTICULAR PURPOSE, ARE 672 of 1021
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EXPRESSLY DISCLAIMED. In addition, the warranties shall be void and do not extend to any ECM Work that has been abused, altered, or misused, or that has been repaired by Owner or third parties without the supervisions or prior written approval of Centrica Business Solutions
3.4 SAFETY OF PERSONS AND PROPERTY. Centrica Business Solutions shall endeavor to avoid injury, loss or damage to persons or property by taking reasonable steps to protect: a) its employees and other persons at the worksite, and b) materials, supplies and equipment stored at the worksite for use in performance of the ECM Work. Centrica Business Solutions shall also oversee the safety precautions and programs of its subcontractors and suppliers at the worksite. Centrica Business Solutions' safety program shall include all actions and programs necessary for compliance with California or federally statutorily mandated workplace safety programs, including without limitation, compliance with the California Drug Free Workplace Act of 1990 (California Government Code 8350 et seq.).
3.5 HAZARDOUS MATERIALS.
3.5.1 A “Hazardous Material” is any substance or material identified now or in the future as hazardous under any federal, state or local law or regulation, or any other substance or material that may be considered hazardous or otherwise subject to statutory or regulatory requirements governing handling, disposal and/or clean-up. Centrica Business Solutions shall not be obligated to commence or continue the ECM Work until any Hazardous Material discovered at the Project site has been removed, rendered or determined to be harmless by Owner as certified by an independent testing laboratory approved by the appropriate government agency.
3.5.2 If after the commencement of the ECM Work, Hazardous Material is discovered at the Project site, Centrica Business Solutions shall be entitled to immediately stop ECM Work in the affected area. Centrica Business Solutions shall report the condition to Owner and, if required, to the government agency with jurisdiction. If any Hazardous Material is discovered at the Project site, Owner shall be responsible for retaining any independent testing laboratory to determine the nature of the materials encountered and whether it is a Hazardous Material requiring corrective measures and/or remedial action. Such measures shall be the sole responsibility of Owner, and shall be performed in a manner minimizing any adverse effects upon the ECM Work. Centrica Business Solutions shall resume ECM Work in the area affected by any Hazardous Material only upon written agreement between the Parties after the Hazardous Material has been removed or rendered harmless and only after approval, if necessary, of the governmental agency or agencies with jurisdiction.
3.5.3 Centrica Business Solutions shall not be required to perform any ECM Work relating to or in the area of any Hazardous Material without written mutual agreement of the Parties.
3.5.4 If Centrica Business Solutions incurs additional costs and/or is delayed due to the presence or remediation of Hazardous Material, Centrica Business Solutions shall be entitled to an equitable adjustment in compensation and/or the ECM Work Schedule. 673 of 1021
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3.5.5 To the extent not caused by the negligent acts or omissions of Centrica Business Solutions, or its subcontractors or suppliers, and their agents, officers, and employees of each of them, Owner shall defend, indemnify and hold harmless Centrica Business Solutions, its subcontractors, suppliers, and their agents, officers and employees, from and against any and all claims, damages, penalties, losses, expenses, and other liabilities, including attorney’s fees, arising out of or relating to the performance of the ECM Work in any area affected by Hazardous Material.
3.5.6 During the performance of the ECM Work, Centrica Business Solutions shall be responsible for the proper handling of all materials brought by it to the worksite. The provisions of this Section 3.5 shall also apply to the MM&V Services, and, without limiting the foregoing, on and after the MM&V Services Commencement Date, Owner shall be responsible under this Section 3.5 for materials and substances brought to the site by Centrica Business Solutions if such materials or substances are required by the Contract Documents.
3.5.7 The terms of this Section 3.5 shall survive the completion of the ECM Work and the termination of this Agreement.
3.6 SYSTEMS START-UP AND TRAINING.
3.6.1 Upon Substantial Completion of the ECM Work, with the assistance of Owner’s personnel, Centrica Business Solutions shall direct the checkout of Equipment and start-up operations, and adjusting and balancing of Equipment and for readiness. Centrica Business Solutions shall also secure required certificates of inspection, testing and/or approval and deliver them to Owner.
3.6.2 Centrica Business Solutions shall conduct the training program described in Schedule 2A. The training specified in Schedule 2A shall be completed prior to Final Completion (as hereinafter defined) of the ECM Work.
3.7 SUBSTANTIAL COMPLETION/FINAL COMPLETION
3.7.1 “Substantial Completion” means that stage in the progress of the ECM Work when the ECM Work is sufficiently complete in accordance with this Agreement such that Owner can use or occupy the Facilities and utilize the ECM Work or designated portion thereof for its intended use. Upon Substantial Completion, the Parties shall execute a Certificate of Substantial Completion fixing the date of Substantial Completion and listing all unfinished items of ECM Work, in substantially the form attached hereto as Exhibit B.
3.7.2 “Final Completion” means the point when all of the ECM Work is fully and finally complete in accordance with the requirements of this Agreement, and Owner has accepted the ECM Work, which acceptance shall not be unreasonably delayed or conditioned by Owner.
ARTICLE IV
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THE MM&V SERVICES
4.1 COMMENCEMENT OF THE MM&V SERVICES. The date of the commencement of Centrica Business Solutions' obligations under the MM&V Services Phase (the “MM&V Services Commencement Date”) shall be the date that: (i) Substantial Completion has been achieved for all portions of the ECM Work, and (ii) the systems start-up and training obligations under Section 3.6 have been completed. Centrica Business Solutions' obligations under the MM&V Services Phase shall thereafter continue until the conclusion of the Term or any earlier termination of this Agreement.
4.2 THE MM&V SERVICES.
4.2.1 During the MM&V Services Phase Centrica Business Solutions shall perform those MM&V Services set forth in and in accordance with the Scope of MM&V Services.
Without limiting the foregoing, Centrica Business Solutions shall perform and carry out the duties and obligations set forth below in Section 4.2.2.
4.2.2 For each year of the Term after the MM&V Services Commencement Date, within sixty (60) days of the anniversary date of the MM&V Services Commencement Date, Centrica Business Solutions shall provide Owner with an annual energy savings guarantee reconciliation report (the “Savings Reconciliation Report”) in substantially the form attached hereto as Exhibit C, that calculates annual energy savings according to the Energy Savings Methodologies defined in the “Energy Savings Schedule” attached hereto as Schedule 5. Centrica Business Solutions will provide Owner with an explanation as to any variations between annual energy savings and the Guaranteed Energy Savings (as hereinafter defined) shown in the Savings Reconciliation Report. The Savings Reconciliation Report shall initially be submitted by Centrica Business Solutions to Owner in draft form whereupon Centrica Business Solutions and Owner shall use their best efforts to resolve any discrepancies in the draft Savings Reconciliation Report as soon as possible so as to arrive at mutually acceptable Savings Reconciliation Report. Centrica Business Solutions and Owner will indicate their acceptance of the Savings Reconciliation Report by signing at the end thereof. Failure of Owner to respond within 60 days of receipt of the report shall indicate Owner’s acceptance of the report.
4.3 GUARANTEED ENERGY SAVINGS.
4.3.1 Centrica Business Solutions has formulated and hereby guarantees the energy and operations savings (the “Guaranteed Energy Savings”) to be achieved as a result of the installation and operation of the ECM Work and the provisions of the MM&V Services, as set forth in the Energy Savings Schedule (Schedule 5). The amount of the Guaranteed Energy Savings is subject to modification based upon i) changes in the ECM Work after the Effective Date, ii) changes in the MM&V Services after the Effective Date, and iii) Material Changes, and the Parties shall reflect all such modifications by revising accordingly the Guaranteed Energy Savings and any other applicable portions of the Energy Savings Schedule.
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4.3.2 Commencing with the first twelve (12) month period following the MM&V Services Commencement Date, and for each twelve (12) month period within the Term thereafter, where the energy savings, as calculated using the method defined in the Energy Savings Schedule, are less than the Guaranteed Energy Savings, Centrica Business Solutions agrees to pay to Owner the difference between the Guaranteed Energy Savings and the sum of the actual energy savings as calculated. Centrica Business Solutions will make any such Guaranteed Energy Savings payment within ninety (90) days of the date of Owner’s acceptance of the Savings Reconciliation Report pursuant to Section 4.3.1.
4.4 EQUIPMENT SERVICE AND MODIFICATION.
4.4.1 Owner shall not move, remove, modify, alter, or change the Equipment or any part thereof (“Alterations”) in any way without the prior written approval of Centrica Business Solutions, except in the event of a bona fide emergency where it is not reasonably possible to notify Centrica Business Solutions before carrying out Alterations. In the event of such an emergency, Owner shall take reasonable steps to protect the Equipment from damage or injury, shall follow any instructions for emergency action provided in advance by Centrica Business Solutions, and shall notify Centrica Business Solutions within three (3) business days of such emergency. Any telephonic notice of such emergency shall be followed within one (1) business day by written notice to Centrica Business Solutions from Owner. Owner agrees to maintain the Facilities in good repair and to protect and preserve all portions thereof that may in any way affect the operation or maintenance of the Equipment.
4.4.2 In the event that any actions of Owner, including but not limited to the carrying out of Alterations, affect the performance of the Equipment, the Guaranteed Energy Savings shall be adjusted to reflect the impact of such actions. If Owner unreasonably delays in notifying Centrica Business Solutions of changes resulting from an emergency and/or Owner does not receive written approval to carry out Alterations, all Guaranteed Energy Savings obligations of Centrica Business Solutions under Section 4.3 and elsewhere in this Agreement shall automatically cease and be of no further force or effect.
4.4.3 At all times during the Term, Centrica Business Solutions shall have the right, subject to Owner's prior written approval, which approval shall not be unreasonably withheld, to change the Equipment or any related energy automation management systems, revise any procedures for the operation thereof, and/or implement other energy saving actions in the Facilities, provided that: (i) such modifications are necessary, in Centrica Business Solutions' reasonable judgment, to enable Centrica Business Solutions to achieve the Guaranteed Energy Savings at the Facilities, and (ii) any cost incurred relative to such modifications, additions or replacement of the Equipment, or operational changes or new procedures shall be the responsibility of Centrica Business Solutions All such modifications, additions or replacements of the Equipment or revisions to operating or other procedures shall be described in a supplemental schedule to be provided to Owner.
ARTICLE V
OWNER’S RESPONSIBILITIES
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5.1 GENERAL RESPONSIBILITIES.
5.1.1 Upon request of Centrica Business Solutions, Owner shall provide all available information in a timely manner regarding requirements for the Project, including all existing reports or studies regarding the physical characteristics of the site (such as surveys, site evaluations and existing conditions reports), legal descriptions, plans and drawings, building controls, systems, apparatus, equipment and machinery.
5.1.2 Owner shall promptly notify Centrica Business Solutions of all known unusual or materially change to the operating conditions that affect any Facilities, or any condition that may affect the ECM Work or the MM&V Services.
5.1.3 Owner shall appoint an authorized representative to facilitate Centrica Business Solutions' performance of the ECM Work and the MM&V Services. The representative shall:
a) be fully acquainted with the ECM Work and the MM&V Services; b) agree to furnish the information and MM&V Services required of Owner so as not to delay Centrica Business Solutions' performance of its obligations under this Agreement; and
c) shall have authority to bind Owner in all matters requiring Owner’s approval, authorization or written notice. If Owner changes its representative or the representative’s authority as listed above, Owner shall notify Centrica Business Solutions in advance.
5.2 RESPONSIBILITIES DURING CONSTRUCTION & INSTALLATION PHASE.
5.2.1 Owner shall review the ECM Work Schedule as set forth in Section 3.1.1, timely approve any milestone dates set forth, and timely respond to its obligations thereunder.
5.2.2 Owner shall provide sufficient space at the Project site for the performance of the ECM Work. Owner shall provide access to the Project site and Facilities for Centrica Business Solutions to perform any function related to this Agreement during regular business hours, and at such other reasonable times as may be requested by Centrica Business Solutions Owner shall not unreasonably restrict Centrica Business Solutions' access to the Project site or Facilities to make emergency repairs or corrections as Centrica Business Solutions may determine are needed.
5.2.3 Owner shall provide inspection and testing services during construction as required by law or as mutually agreed in writing.
5.2.4 Contractor shall have no responsibility for compliance with the California Environmental Quality Act, other than as may be expressly included in the ECM Work in order to comply with mitigation measures designated by Owner. 677 of 1021
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5.2.5 Contractor and the Owner acknowledge that under California Government Code Section 4215, the Owner assumes the responsibility for the timely removal, relocation, or protection of existing main or trunkline utility facilities located on the Project site which are not identified in the drawings, specifications or other Contract Documents. Prior to commencing any underground work on this Project, Contractor shall: take all reasonable steps to confirm the location of such utility facilities sufficient to assure itself that no conditions exist at or about the Project site which would require revision to the ECM Work, ECM Work Price, dates for Substantial Completion or Final Completion, or any other material provision of this Agreement; and, contact the appropriate Underground Service Alert (“USA”) and arrange to have the Project area marked by USA for underground utilities. In addition, Contractor shall review the Owner’s as-built drawings, survey’s and other site documents produced and/or made available to Contractor to locate and verify all underground utilities or other underground obstacles or site conditions. In the event that underground utilities or other underground obstacles or site conditions are discovered by Contractor that were not reflected in the results of the USA underground service inspection or in the Owner’s as-built drawings, survey’s and other site documents produced to Contractor, such matters shall be deemed unforeseen circumstances and Contractor shall be entitled to a reasonable extension of time and a reasonable increase in the ECM Work Price based upon the time and increased costs and expenses incurred by Contractor as a result of such inaccuracies. Contractor and the Owner agree that the provisions of California Government Code Section 4215 requiring that the utilities be identified in the invitation for bids shall not apply to this Agreement insofar as Contractor has the responsibility for design of the Project as well as construction of the Project. Rather, Contractor and the Owner agree that the scope of Contractor’s responsibilities relating to design of the Project includes review of Owner-provided existing condition information and interface with Underground Service Alert.
5.2.6 If Owner becomes aware of any error, omission or failure of Contractor to meet the requirements of this Agreement or any fault or defect in the ECM Work, Owner shall give prompt written notice to Centrica Business Solutions.
5.3 RESPONSIBILITIES DURING THE MM&V SERVICES PHASE.
5.3.1 Owner shall provide Centrica Business Solutions with complete energy usage information and energy-using equipment information, as requested by Centrica Business Solutions This information will include, but not be limited to:
a) Copies of all utility and fuel bills for the Facilities; for the two years prior to the MM&V Services Commencement Date and ongoing throughout the Term. b) Direct access, by telephone modem or other reasonable means installed at Centrica Business Solutions' expense, to any and all energy management systems or building automation systems installed in or used in connection with the Facilities, with permission granted to Centrica Business Solutions to download any and all information from these systems and to store such information for the Term;
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c) Permission to install, at Centrica Business Solutions' expense, add-on devices to any and all utility and energy use meters, to enable Centrica Business Solutions to directly observe Facility utility usage, with permission granted to Centrica Business Solutions to download any and all information from these systems and to store such information for the Term;
d) Permission, as an agent of Owner, to obtain and utilize any and all energy usage information from any and all utilities or energy suppliers providing service to the Facilities, with permission granted to Centrica Business Solutions to download any and all information from these systems and to store such information for the Term. In connection herewith, Owner agrees to execute such permission or authorization forms, which utilities or energy suppliers may from time to time require to release such information to Centrica Business Solutions; and
e) Copies of any and all energy-using equipment repair orders or invoices for repairs or maintenance ECM Work not subject to the direct control of Centrica Business Solutions
5.3.2 Failure by Owner to provide the information required in this Section 5.3 or otherwise comply with its obligations under this Agreement in timely fashion, will suspend the Energy Savings Guarantee described in the Energy Savings Schedule until the information is provided or other obligation is met. The failure of Owner to provide this information within ninety (90) days of the end of the applicable annual period shall be deemed a material breach of this Agreement in accordance with Section 8.2.1(d) hereof.
ARTICLE VI
COMPENSATION AND PAYMENT
6.1 COMPENSATION FOR THE ECM WORK.
6.1.1 For the performance of the ECM Work, and all obligations in connection therewith under this Agreement, Owner agrees to pay Centrica Business Solutions the following sum (the “ECM Work Price”): ___________________________________ ($_________________). A detailed “ECM Work Schedule of Values”, setting forth the breakdown of the total ECM Work Price, is attached hereto as Schedule 6A.
6.1.2 Based upon itemized applications for payment submitted to Owner by Centrica Business Solutions during the Construction and Installation Phase, Owner shall make payment to Centrica Business Solutions of the ECM Work Price as follows:
a) The period covered by each application for payment shall be one calendar month ending on the last day of the month. Provided an application for payment is received by Owner not later than the 5th day of a month, Owner shall make payment pursuant to such application to Centrica Business Solutions not later 679 of 1021
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than the 20th day of the same month. If an application for payment is received by Owner after the application date fixed above, payment shall be made by Owner not later than twenty (20) days after receipt of the application for payment.
b) Each application for payment shall provide such detail and back-up information or data as Owner may reasonably require, and shall be based upon the ECM Work completed and materials stored on Project site and/or at locations approved by Owner in its reasonable discretion for the period ending on the last day of the applicable month. The ECM Work Schedule of Values shall be used in establishing percentages of completion in payment applications. c) Final payment, constituting the entire unpaid balance of the ECM Work Price, shall be made by Owner to Centrica Business Solutions within fifteen (15) days of the date of Final Completion.
d) Payments due and unpaid shall bear interest from the date due at the legal rate prevailing from time to time at the place where the Project is located.
6.2 COMPENSATION FOR THE MM&V SERVICES.
6.2.1 For the performance of the MM&V Services during the Term, Owner agrees to pay Centrica Business Solutions the following fee (the “MM&V Services Fee”):
___________________________ ($_______________). A detailed “MM&V Services Schedule of Values”, setting forth the breakdown of the total MM&V Services Fee for each item of MM&V Services, is attached hereto as Schedule 6B.
6.2.2 Effective as of each one year anniversary of the MM&V Services Commencement Date, the MM&V Services Fee shall be increased by an amount equal to three (3%) percent of the amount of the MM&V Services Fee for the immediately preceding one (1) year period.
6.2.3 The MM&V Services Fee shall be paid in arrears in equal annual installments on the first (1st) day of the month in which the one year anniversary of the MM&V Services Commencement Date occurs.
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ARTICLE VII
CHANGES
7.1 CHANGE ORDERS. Changes in the ECM Work or MM&V Services that are within the general scope of this Agreement, and that are not minor changes in the ECM Work or MM&V Services, shall be accomplished without invalidating this Agreement by a written instrument executed by both Parties in accordance with this Article VII (a “Change Order”). Centrica Business Solutions may request or Owner may order changes in the ECM Work or MM&V Services within the general scope of this Agreement consisting of adjustment to the ECM Work Price and/or MM&V Services Fee, respectively, or the ECM Work Schedule. All such changes in the ECM Work shall be authorized by applicable Change Order.
7.1.1 Owner and Centrica Business Solutions shall negotiate in good faith an appropriate adjustment, as applicable, to the ECM Work Price, MM&V Services Fee and/or the ECM Work Schedule, and shall conclude these negotiations as expeditiously as possible.
Acceptance of the Change Order and any adjustment in the ECM Work Price, MM&V Services Fee and/or ECM Work Schedule shall not be unreasonably withheld. An increase or decrease in the ECM Work Price or MM&V Services Fee resulting from a change in the scope of the ECM Work or MM&V Services shall be determined by one or more of the following methods:
a) unit prices set forth in this Agreement or as subsequently agreed in writing by the Parties;
b) a mutually accepted, itemized lump sum; or
c) if an increase or decrease cannot be agreed upon as set forth in this Section 7.1, the adjustment in the ECM Work Price or MM&V Services Fee shall be determined by the reasonable expense and savings of the performance of the ECM Work resulting from the change. If there is a net increase in the ECM Work Price or MM&V Services Fee, then a reasonable adjustment shall be made for Centrica Business Solutions' overhead and profit. In the case of a net decrease in cost, the amount of the decrease in the ECM Work Price or MM&V Services Fee shall not include reduction for overhead and profit.
7.2 MINOR CHANGES IN THE ECM WORK. Centrica Business Solutions may make minor changes in the design and construction of the ECM Work consistent with the intent of this Agreement that do not involve an adjustment in the ECM Work Price or MM&V Services Fee or the ECM Work Schedule, so long as such changes do not materially and adversely affect the ECM Work, the quality of the materials or equipment specified herein, the performance of any materials, equipment or systems specified herein, or the quality of the workmanship required by this Agreement.
7.3 CHANGES AFFECTING THE GUARANTEED ENERGY SAVINGS. The Parties acknowledge that changes that negatively or positively affect the scope of the ECM Work will necessarily affect the Guaranteed Energy Savings set forth in Section 4.3. Any Change Order 681 of 1021
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documents containing such scope changes shall also delineate any corollary Guaranteed Energy Savings adjustments.
7.4 UNKNOWN CONDITIONS. If in the performance of the ECM Work or the MM&V Services Centrica Business Solutions finds latent, concealed or other conditions that materially differ from the conditions Centrica Business Solutions reasonably anticipated, or if the physical conditions are different from those normally encountered and generally recognized as inherent in the kind of ECM Work or MM&V Services provided for in this Agreement, then the ECM Work Price or the MM&V Services Fee shall be equitably adjusted, and, as applicable, the ECM Work Schedule and Guaranteed Energy Savings shall be appropriately modified, by a Change Order within a reasonable time after the conditions are first observed. Centrica Business Solutions shall provide Owner with written notice of its discovery of any of the foregoing conditions as soon as practicable after such discovery.
7.5 EMERGENCIES. In any emergency affecting the safety of persons or property, Centrica Business Solutions shall act, at its discretion, to prevent threatened damage, injury or loss. Any change in the ECM Work Price, MM&V Services Fee or ECM Work Schedule on account of such emergency ECM Work shall be determined as provided in this Article VII.
7.6 CHANGES IN LAW. In the event any changes in laws or regulations affecting the performance of the ECM Work are enacted after the date of this Agreement, the ECM Work Price, the MM&V Services Fee and/or the ECM Work Schedule or Guaranteed Savings shall be equitably adjusted by Change Order.
7.7 MATERIAL CHANGES.
7.7.1 Definition. A “Material Change” is any change in or to the Facilities, whether structural, operational or otherwise in nature that reasonably can be expected, in the judgment of Owner and Centrica Business Solutions to decrease annual energy savings in accordance with the provisions and procedures set forth in the Energy Savings Schedule (Schedule 5) after adjustments for climatic variations. Actions by Owner that may result in a Material Change include, but are not limited to the following; a) The manner of use of the Facilities by Owner;
b) The hours of operation for the Facilities or for any Equipment or energy using systems operating at the Facilities;
c) Permanent changes in the comfort and service parameters set forth in Scope of ECM Work (Schedule 2A);
d) Occupancy of the Facilities;
e) The structure of the Facilities;
f) The types and quantities of equipment used at the Facilities; 682 of 1021
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g) The modification, renovation or construction at the Facilities (other than the ECM Work);
h) Owners’ failure to provide maintenance of and repairs to the Equipment; or i) Any other conditions other than climate affecting energy use at the Facilities.
7.7.2 Reported Material Changes. Owner shall use best efforts to deliver to Centrica Business Solutions a written notice describing all actual or proposed Material Changes at least thirty (30) days prior to the implementation of such Material Change, or as soon as is practicable after an emergency or other unplanned event. After Centrica Business Solutions' review of the notice, the Parties shall meet as soon as practicable to agree upon adjustments to the Energy Savings Schedule and the MM&V Services Fee, which adjustments shall be set forth in a Change Order.
ARTICLE VIII
TERMINATION
8.1 TERMINATION BY OWNER FOR CAUSE. Upon thirty (30) days’ advance written notice to Centrica Business Solutions, Owner may terminate this Agreement for Cause (as hereinafter defined) if after giving Centrica Business Solutions written notice of such Cause, Centrica Business Solutions fails to cure the same within thirty (30) days following receipt of such notice or, if such cure cannot reasonably be effected within thirty (30) days, such cure is undertaken within such time period and is thereafter continued diligently until completion.
8.1.1 For purposes of this Agreement, “Cause” shall mean the occurrence of any of the following:
a) Any material failure on the part of Centrica Business Solutions to perform or comply with the terms and conditions of this Agreement; or b) The commencement by or on behalf of Centrica Business Solutions of any voluntary or involuntary case or matter relating to or associated with the U.S.
Bankruptcy Code, or for liquidation, reorganization, or an arrangement pursuant to any other U.S. or state bankruptcy laws, or Centrica Business Solutions being adjudicated a debtor or declared bankrupt or insolvent under the U.S. Bankruptcy Code, or any other U.S. Federal or state laws relating to bankruptcy, insolvency, winding-up, or adjustment of debts, or Centrica Business Solutions making a general assignment for the benefit of creditors, or admitting in writing its inability to pay its debts generally as they become due, and/or if a custodian, receiver, trustee or liquidator of Centrica Business Solutions, all or substantially all of the assets or business of Centrica Business Solutions or of Centrica Business Solutions' interest in this Agreement, is appointed in any proceeding.
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8.1.2 If termination occurs during the Construction and Installation Phase, Owner shall be responsible for paying for all ECM Work performed by Centrica Business Solutions through the effective date of termination, and Owner may deduct from the amount due to Centrica Business Solutions the reasonable cost to Owner of any necessary remediation required with respect to the matters resulting in such termination. In the event that Centrica Business Solutions is terminated by Owner under this provision and it is later determined that such termination was improper, Centrica Business Solutions shall be entitled to the remedies set forth in Section 8.3 below.
8.1.3 If termination occurs during the MM&V Services Phase, Owner shall be responsible for paying for all reasonable costs and expenses incurred by Centrica Business Solutions under Section 4.4 hereof prior to the effective date of termination, but subject to Owner’s right to deduct its remediation costs in the same manner as provided in Section
8.1.2. 8.2 TERMINATION BY CENTRICA BUSINESS SOLUTIONS SERVICES, INC.
8.2.1 Upon ten (10) days’ advance written notice to Owner, Centrica Business Solutions may, in addition to any other rights or remedies, terminate this Agreement for any of the following reasons:
a) If the ECM Work has been stopped for at least thirty-day period under court order or order of other governmental authorities having jurisdiction, or as a result of the declaration of a national emergency or other governmental act during which, through no fault of Centrica Business Solutions, materials, supplies, tools, and construction equipment and machinery for the ECM Work are not available;
b) If Owner has failed to pay any compensation due to Centrica Business Solutions in accordance with this Agreement for a period of thirty (30) days or more; provided however, in lieu of immediate termination, Centrica may suspend the Work, in its sole discretion, pending payment and reimbursement of its unavoidable suspension costs from Owner. In the event of such written notice of suspension by Centrica, Centrica shall be required to provide an additional five (5) days’ advance written notice to Owner to terminate this Agreement. c) If the ECM Work has been suspended for any reason by Owner for a continuous period exceeding sixty (60) days;
d) If Owner has materially hindered or delayed Centrica Business Solutions in the performance of any of its obligations under this Agreement, or Owner has otherwise has materially breached any covenant, agreement, warranty or representation set forth in this Agreement, and if after giving Owner written notice of thereof Owner fails to cure the same within thirty (30) days following receipt of such notice or, if such cure cannot reasonably be effected within thirty 684 of 1021
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(30) days, such cure is undertaken within such time period and is thereafter continued diligently until completion.
8.2.2 Upon such termination, Centrica Business Solutions shall be entitled to recover from Owner as provided in Section 8.3.
Upon the payment of amounts due under this Section 8.2, neither Party shall have any further liability to the other except for those obligations expressly specified in this Agreement to survive its termination.
8.3 TERMINATION BY OWNER WITHOUT CAUSE.
8.3.1 If Owner terminates this Agreement other than pursuant to Section 8.1, Centrica Business Solutions shall be entitled to recover from Owner as follows:
a) If termination occurs during the Construction and Installation Phase, Owner shall be responsible for paying for all ECM Work performed by Centrica Business Solutions through the effective date of termination; b) If termination occurs during the MM&V Services Phase, Owner shall be responsible for paying for all reasonable costs and expenses incurred by Centrica Business Solutions under Section 4.2 hereof prior to the effective date of termination;
c) Owner shall pay for all demobilization costs incurred by Centrica Business Solutions, and purchase or rental costs incurred by Centrica Business Solutions, for any equipment acquired by the Centrica Business Solutions in connection with the ECM Work and MM&V Services;
8.3.2 In addition to the foregoing, Owner shall further assume and become liable for obligations, commitments, and unsettled claims that Centrica Business Solutions has previously undertaken or incurred in good faith on behalf of Owner in connection with the Project hereof.
8.4 GUARANTEED ENERGY SAVINGS. Upon the termination of this Agreement pursuant to either Section 8.2 or Section 8.3, all Guaranteed Energy Savings obligations of Centrica Business Solutions under Section 4.3 and elsewhere in this Agreement shall automatically cease and be of no further force or effect.
ARTICLE IX
INDEMNIFICATION/INSURANCE/BONDING/WAIVERS
9.1 INDEMNIFICATION.
9.1.1 Centrica Business Solutions shall indemnify and hold Owner and its employees harmless from and against all third party claims, losses, or damages arising from the 685 of 1021
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performance of the ECM Work or the MM&V Services provided that the same are attributable to bodily injury, death and/or damage to property, but only to the extent caused by the negligent, reckless or wrongful acts or omissions acts or omissions of Centrica Business Solutions or anyone for whose acts Centrica Business Solutions is liable. In no event shall this indemnification apply to liability to the extent caused by the negligence or willful misconduct of the party to be indemnified or held harmless. This indemnification shall not be limited to damages, compensation or benefits payable under insurance policies, any worker’s compensation act, or other employee benefit acts.
9.1.2 Owner shall indemnify and hold Centrica Business Solutions and its employees and subcontractors and agents harmless from and against all third party claims for bodily injury, death, and/or damage to property (excluding damage for which Owner assumes the risk of loss or damage to the ECM Work itself) that may arise in connection with the Project but only to the extent caused by the negligent, reckless or wrongful acts or omissions acts or omissions of Owner or anyone for whose acts Owner is liable. In no event shall this indemnification apply to liability to the extent caused by the negligence or willful misconduct of the party to be indemnified or held harmless. This indemnification shall not be limited to damages, compensation or benefits payable under insurance policies, any worker’s compensation act, or other employee benefit acts..
9.2 CENTRICA BUSINESS SOLUTIONS SERVICES, INC.’S INSURANCE. At all times during the Term, Centrica Business Solutions shall provide and maintain the insurance set forth in this Section 9.2. All insurers shall be authorized and licensed to provide insurance in the State of California, and shall be rated as A- or better by A.M. Best
9.2.1 Workers’ Compensation. Centrica Business Solutions shall obtain and maintain Worker’s Compensation insurance with statutory limits and Employers’ Liability insurance in the amount of $1,000,000.
9.2.2 Commercial General Liability. Centrica Business Solutions shall obtain and maintain Commercial General Liability Insurance written on an occurrence basis, with the following limits:
Each Occurrence Limit: $1,000,000
General Aggregate Limit: $2,000,000
Products/Completed
Operations Aggregate
Limit: $2,000,000
Personal and Advertising
Injury Limit: $1,000,000
Medical Pay: $5,000
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9.2.3 Automobile Liability. Centrica Business Solutions shall obtain and maintain Business Automobile Liability Insurance covering owned, non-owned, and hired automobiles, with the following limits:
Combined Single Limit
Bodily Injury and
Property Damage: $1,000,000 Each Occurrence
9.2.4 Professional Liability. Centrica Business Solutions shall obtain and maintain professional liability or errors & omissions insurance for claims arising from the negligent performance of any professional MM&V Services under this Agreement, which shall be General Office Coverage, with the following limits:
Per claim: $1,000,000
Aggregate: $2,000,000
9.2.5 Excess Umbrella. All liability insurance may be arranged under a single policy for the full limits required or by a combination of primary, excess, and/or umbrella liability policies.
9.2.6 Policy Terms. Owner shall be named as an additional insured on all coverage obtained to the extent of the negligence of Centrica Business Solutions under all liability policies except Professional Liability and Workers’ Compensation, on a primary and noncontributory with respect to any liability coverage maintained by Owner. Centrica Business Solutions will not cancel coverage without at least thirty (30) days’ prior written notice has been given to Owner. Upon request, a certificates of insurance will be provided to Owner.
9.3 OWNER’S INSURANCE.
9.3.1 Liability Insurance. Owner shall obtain and maintain its own liability insurance for protection against claims arising out of the performance of this Agreement.
9.3.2 Property Insurance.
a) Owner shall obtain and maintain Builder’s Risk or equivalent property insurance in a form reasonably acceptable to Centrica Business Solutions upon the entire Project, including the Equipment and the Facilities and all other existing structures in which any of the ECM Work is to be performed, as well as all Project structures that are fully or partially owned or occupied by Owner or its affiliates, for the full cost of replacement at the time of any loss. This insurance shall include as insureds Owner, Centrica Business Solutions, Centrica Business Solutions' subcontractors, and all other subcontractors and suppliers, as their interests may appear. This insurance shall insure against loss from the perils of fire and extended coverage, and shall include “all risk” coverage including at a minimum coverage for theft, vandalism, malicious 687 of 1021
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mischief, inland transit, collapse, temporary buildings, debris removal, flood, earthquake, wind, testing, and damage resulting from defective design, workmanship, or material. Owner shall increase limits of coverage, if necessary, to reflect estimated replacement cost. Owner shall be responsible for all premiums and any co-insurance penalties, exclusions, sublimits, or deductibles.
b) On or before the MM&V Services Commencement Date, Owner shall procure and thereafter maintain at all times during the Term, at its sole cost and expense a policy or policies of property damage insurance on all fixtures and improvements and betterments to the Facilities, including the Equipment, against any peril generally included within the classification “all risks”, including, but not limited to, risks covered by fire, extended coverage, vandalism and malicious mischief, in amounts at least equal to the full replacement cost thereof (without deduction for depreciation). Such coverage shall include boiler and machinery and equipment breakdown insurance.
Centrica Business Solutions shall be included as an insured or loss payee on all such policies, as its interests may appear.
9.3.3 Policies. Upon Centrica Business Solutions' request, Owner shall provide Centrica Business Solutions with a copy of all policies including all endorsements thereto. Centrica Business Solutions shall be given thirty (30) days’ prior written notice of cancellation, nonrenewal, or any endorsements restricting or reducing coverage.
9.3.4 Loss Adjustment. Any insured loss shall be adjusted with Owner and Centrica Business Solutions and made payable to Owner as trustee for the insureds, as their interests may appear, subject to any applicable mortgagee clause.
9.4 WAIVER OF CLAIMS AND SUBROGATION.
9.4.1 Property Damage. Owner and Centrica Business Solutions waive all claims and other rights they may have against each other for loss of and/or damage to (i) the Project, including the Equipment and Facilities, (ii) all materials, machinery, equipment, and other items used in accomplishing the ECM Work and/or to be incorporated into the Project, while the same are in transit, at the Project site, during erection, and otherwise, and (c) all property owned by or in the custody of Owner and its affiliates, however such loss or damage shall occur, except the rights each Party has to the proceeds of such insurance held by Owner as trustee in accordance with Section 9.3.4.
9.4.2 Waiver of Subrogation. Owner and Centrica Business Solutions shall have their respective insurers waive all rights of subrogation they may have against one another for claims arising thereunder. If the policies of insurance referred to in this Article IX require an endorsement to provide for continued coverage where there is a waiver of subrogation, the Parties will cause them to be so endorsed.
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9.4.3 Damages Waiver. Except to the extent of applicable insurance coverage under insurance policies procured pursuant to this Agreement, Owner and Centrica Business Solutions agree to waive all claims against the other for all special, indirect, consequential, remote, punitive, exemplary, or similar damages that may arise out of or relate to this Agreement. This waiver includes, but is not limited to, Owner’s loss of use of the Facilities, all rental expenses incurred, loss of services of employees, or loss of reputation, and Centrica Business Solutions' loss of business, loss of financing, principal office overhead and profits, loss of profits not related to this Project, or loss of reputation. The provisions of this Section 9.4.3 shall survive the termination of this Agreement.
9.4.4 Limitation of Liability. The Parties have discussed the risk and rewards associated with the ECP Work, as well as Centrica Business Solutions' compensation for the MM&V Services. The Parties agree that Centrica Business Solutions shall procure and maintain insurance policies with such coverages and amounts and for such periods of time as required by this Agreement. In light of the foregoing, Owner agrees that Centrica Business Solutions' liability under this Agreement, regardless of the form of action, shall in no event exceed the amount of the compensation actually received by Centrica Business Solutions pursuant to Section 6.1 and Section 6.2 of this Agreement. The provisions of this Section 9.4.4 shall survive the termination of this Agreement.
9.5 BONDING.
9.5.1 Performance and Payment Bonds are required of Centrica Business Solutions as a condition to the commencement and performance of the ECM Work. All Bonds must be acceptable to Owner, and its reasonable discretion, and shall: i) be issued by good and sufficient sureties licensed in the State of California, ii) The Surety on any bond required under the Contract Documents shall be an Admitted Surety Insurer as that term is defined in California Code of Civil Procedure 995.120.
ARTICLE X
CASUALTY AND CONDEMNATION
10.1 CASUALTY.
10.1.1 After the MM&V Services Commencement Date, Owner assumes and shall bear the risk of damage, loss, theft, or destruction, partial or complete, of the Equipment and the Facilities (a “Casualty Loss”), however arising, except to the extent that the same may be caused by the negligent or willful acts or omissions of Centrica Business Solutions that is not covered by insurance to be procured pursuant to this Agreement. If Owner fails to repair or replace any Casualty Loss within a reasonable time, and in no event more than one hundred twenty (120) days from its occurrence (except to the extent that the Casualty Loss is the responsibility of Centrica Business Solutions in accordance with the foregoing), Centrica Business Solutions may, at its option: (i) terminate this Agreement by delivery of a written notice to Owner, and such termination shall be deemed a termination without Cause and will be subject to the provisions of Section 8.3 hereof, or (ii) require Owner to 689 of 1021
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amend this Agreement in a manner that equitably accounts for the loss of such Equipment and/or Facilities.
10.1.2 In the event of a Casualty Loss caused by the negligent or willful acts or omissions of Centrica Business Solutions that is not covered by insurance to be procured pursuant to this Agreement, Owner may require Centrica Business Solutions to promptly repair or replace the damaged or destroyed Equipment and/or Facilities, and in the event of Centrica Business Solutions' failure to do so, Owner may, at its option: (i) repair or replace such items and recover the reasonable cost thereof from Centrica Business Solutions, or (ii) terminate this Agreement for Cause pursuant to Section 8.1 hereof.
10.2 CONDEMNATION.
10.2.1 In the event of the condemnation resulting in a taking of substantially all of the Facilities, this Agreement shall terminate upon the effective date of such taking, and such termination shall be deemed a termination without Cause in accordance with Section 8.3 hereof, provided, however, that the proceeds of such condemnation shall belong to Owner.
10.2.2 In the event of a condemnation resulting in a taking of less than substantially all of the Facilities, the Parties shall amend this Agreement in a manner that equitably accounts for such taking.
ARTICLE XI
COMPLIANCE OBLIGATIONS
11.1 STATUTORY AND REGULATORY COMPLIANCE. Centrica Business Solutions will comply with all applicable provisions of federal, state and local law when performing the ECM Work AND the MM&V Services. Where required by law, all drawings, plans, reports, and other documents delivered to Owner as part of the ECM Work must bear the stamp or seal of architects or engineers licensed by the State of California
11.2 FAILURE TO COMPLY. If Centrica Business Solutions performs and ECM Work or MM&V Services knowing or having reason to know that such ECM Work or MM&V Services are contrary to applicable laws, rules and/or regulations, Centrica Business Solutions shall be responsible for payment of all reasonable costs and expenses arising therefrom. 690 of 1021
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ARTICLE XII
GENERAL PROVISIONS
12.1 NOTICE. All notices required under this Agreement shall be in writing and shall be given either by: (i) personal delivery; or (ii) a nationally-recognized overnight delivery service that provides proof of delivery and addressed to the other Party at such Party’s address specified below.
Such address may be changed by a Party giving notice thereof in accordance with this provision.
To Owner: _______________________________
________________________________
________________________________
________________________________
To: Centrica Business Solutions Services, Inc.
2111 Ellsworth Blvd.
Malta, New York 12020
Attn: Business Unit Manager
12.2 INDEPENDENT CAPACITY. The Parties agree that Centrica Business Solutions is an independent contractor, and that Centrica Business Solutions and its employees and agents, shall act in an independent capacity in the performance of this Agreement, and shall not be construed as officers, employees, or agents of Owner. In addition, this Agreement shall not be construed as creating any partnership or joint venture between the Parties.
12.3 FORCE MAJEURE. If causes beyond a Party’s reasonable control delay, impair or prevent the performance of any of such Party’s obligations hereunder, expressly excepting, however, the payment of money, the time for such performance shall be extended for a reasonable period of time commensurate with the time and nature of the cause. Such causes shall include, but not be limited to: changes ordered in the ECM Work, acts or omissions of the other Party or others beyond the control of the Party whose performance is required, adverse weather conditions not reasonably anticipated, fire, unusual transportation delays, general labor disputes impacting the ECM Work, acts of governmental agencies, or unavoidable accidents or circumstances, Hazardous Materials or differing site conditions.
12.4 FURTHER DOCUMENTS. The Parties agree to execute and deliver all further documents and perform all further acts that may be reasonably necessary to effectuate the provisions of this Agreement.
12.5 GOVERNING LAW. This Agreement shall be governed by and interpreted in accordance with the laws of the State of California. The titles of the various Sections of this Agreement and elsewhere in the Contract Documents are used for convenience of reference only and are not intended to, and shall in no way, enlarge or diminish the rights or obligations of the Owner or Contractor and shall have no effect upon the construction or interpretation of the Contract Documents. The Contract Documents shall be construed as a whole in accordance with their fair meaning and not strictly for or against the Owner or Contractor. .
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12.6 SEVERABILITY. The partial or complete invalidity of any one or more provisions of this Agreement shall not affect the validity or continuing force and effect of any other provision.
12.7 NO WAIVER OF PERFORMANCE. The failure of either Party to insist, in any one or more instances, on the performance of any of the terms, covenants or conditions of this Agreement, or to exercise any of its rights hereunder, shall not be construed as a waiver or relinquishment of such term, covenant, condition or right with respect to further performance.
12.8 INTERPRETATION. The Parties agree that the following shall govern the interpretation of this Agreement:
12.8.1 Headings and captions are for convenience of reference only and shall not affect the construction or interpretation of this Agreement.
12.8.2 The grouping of the articles in this Agreement and of specifications under the various headings is solely for the purpose of convenient organization and in no event shall the grouping of provisions, the use of paragraphs or the use of headings be construed to limit or alter the meaning of any provisions.
12.8.3 The terms “herein,” “hereof” and “hereunder,” and words of similar import, refer to this Agreement as a whole and not to any particular Section, Subsection or Schedule or Exhibit.
12.8.4 The Parties have participated jointly in the negotiation and drafting of this Agreement, and no presumption or burden of proof shall arise favoring or disfavoring either Party by virtue of the authorship of any of the provisions hereof.
12.9 CENTRICA BUSINESS SOLUTIONS SERVICES, INC. PROPERTY. All property used by Centrica Business Solutions in connection with the ECM Work and the MM&V Services, including equipment, tools, drawings, designs, documentation, schematics, test equipment, software, and associated media remain the exclusive property of Centrica Business Solutions Owner agrees not to use such property for any purpose at any time. Owner agrees to allow Centrica Business Solutions personnel to retrieve and to remove all such materials remaining after the ECM Work has been completed or at the end of the Term. Owner acknowledges that any Centrica Business Solutions software included in the ECM Work is proprietary and will be delivered only after execution of and pursuant to a Centrica Business Solutions standard licensing agreement.
12.10 BINDING EFFECT. This Agreement and the Contract Documents shall inure to the benefit of, and be forever binding upon, the Parties and their respective successors, legal representatives and permitted assigns.
12.11 AMENDMENT. This Agreement may be amended, modified or supplemented only by written agreement signed by the Parties.
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12.12 ASSIGNMENT. Centrica Business Solutions acknowledges that Owner seeks to enter into this Agreement by, among other things, the qualifications of Centrica Business Solutions Accordingly, Centrica Business Solutions agrees that this Agreement shall not be assigned in whole or in part to another person or entity, without the prior written approval of Owner.
12.13 ENTIRE AGREEMENT. This Agreement, including all Schedules and Exhibits hereto, constitutes the entire agreement and understanding of the Parties and supersedes all prior agreements and understandings between the Parties with respect to the subject matter hereof. Each Party acknowledges that no Party has made any promises, representations, warranties, covenants or understandings other than those expressly set forth herein.
12.14 EXECUTION. This Agreement may be executed in several counterparts, each of which, when executed, shall be deemed to be an original, but all of which together shall constitute one and the same instrument. The transmission of the signature of a Party by facsimile, email or other electronic means shall be deemed an original thereof by the Party receiving such signature.
12.15 SUCCESSORS AND ASSIGNS. Except as otherwise expressly provided in the Contract Documents, all terms, conditions and covenants of the Contract Documents shall be binding upon, and shall inure to the benefit of the Owner and Contractor and their respective heirs, representatives, successors-in-interest and assigns.
12.16 NO WAIVER. No action or failure to act by the Owner or Centrica Business Solutions is a waiver of a right or remedy under the Contract Documents or at law nor does a Party’s failure to act constitute approval of or acquiescence in a breach hereunder.
12.17 GENDER AND NUMBER. Whenever the context of the Contract Documents so require, the neuter gender includes the feminine and masculine, the masculine gender includes the feminine and neuter, the singular number includes the plural and the plural number includes the singular. [Signature Page Immediately Follows]
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IN WITNESS WHEREOF, the Parties have executed this Agreement by their duly authorized representatives as of the Effective Date.
CENTRICA BUSINESS SOLUTIONS SERVICES, INC.
By:
Name:
Title:
________________________________
By:
Name:
Title:
694 of 1021
Response to
Request for Proposals for Investment Grade Assessment (“IGA”) for University of the Pacific (“UOP”)
CENTRICA BUSINESS SOLUTIONS SERVICES, INC. ENERGY MANAGEMENT TEAM © 2024 CENTRICA BUSINESS SOLUTIONS, ALL RIGHTS RESERVED. PAGE | 29 Find out more.
At Centrica Business Solutions Services, Inc., we provide energy expertise and solutions to organizations worldwide to improve their operational efficiency, increase resilience, and help them become a sustainable business.
We are part of Centrica plc, an international energy services and solutions company focused on helping businesses and households live sustainably and affordably.
To find out more about how we can help:
E: [email protected]
T: (916) 860-9032
W: centricabusinesssolutions.com/us
#thisispositiveenergy
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City of Cotati
Energy/Water Audit
and Implementation Projects
August 22, 2024
Prepared For:
City of Cotati
201 West Sierra Avenue
Cotati, CA 94931
Prepared By:
ENGIE Services U.S.
500 12th Street, Suite 300
Oakland, CA 94607
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City of Cotati | Energy/Water Audit and Implementation Projects Proposal
City of Cotati
Energy/Water Audit and Implementation Projects
August 22, 2024
Prepared For:
Damien O'Bid, City Manager
City of Cotati
201 West Sierra Avenue
Cotati, CA 94931
Prepared By:
ENGIE Services U.S.
500 12th Street, Suite 300
Oakland, CA 94607
Amar Tiwari
Senior Program Development Manager
415-264-2642
[email protected]
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© 2024 ENGIE
This proposal, in whole or in part, is to be used only for evaluation purposes. If the proposal is accepted and a contract entered into then, to the extent, federal or state law requires disclosure, advance notice to ENGIE Services U.S. Inc. is requested with a right to oppose or seek to narrow the disclosure. The data subject to this restriction is contained in all sheets marked, “Use or disclosure of data contained on this sheet is subject to the restriction on the title page of this proposal or quotation.”
ENGIE Services U.S. Inc. is not a municipal advisor and cannot give advice with respect to municipal securities or municipal financial products. This information is provided for educational purposes about possible financing options and is not the provision of advice, or a recommendation to pursue, any financing option. Consult with your municipal advisor or financial advisor about the financing option appropriate for your situation.
ENGIE Services U.S. Inc. can provide information to your municipal advisor or financial advisor about the hypothetical assumptions and educational scenarios used in these materials. To ensure compliance with requirements imposed by the IRS under Circular 230, we inform you that any U.S. federal tax advice contained in this communication (including any attachments), unless otherwise specifically stated, was not intended or written to be used, and cannot be used, for the purpose of (1) avoiding penalties under the Internal Revenue Code or (2) promoting, marketing or recommending to another party any matters addressed herein.
The information contained herein is general in nature and based on authorities that are subject to change. ENGIE Services U.S. Inc. recommends that you consult your tax adviser to understand its applicability to specific situations. ENGIE Services U.S. Inc., the Respondent, is a wholly owned subsidiary of ENGIE Holdings Inc.
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City of Cotati | Energy/Water Audit and Implementation Projects i Table of Contents
Table of Contents ............................................................................................................. i Cover Letter ...................................................................................................................... ii
1. Background .................................................................................................................. 1
1.1 Unique Qualifications .......................................................................................... 1
2. Project Team & Management Structure .................................................................. 3
2.1 Team Organizational Chart ................................................................................ 3
2.2 Resumes ............................................................................................................... 3
2.3 Key Individuals ..................................................................................................... 8
3. Project History & References .................................................................................... 9
3.1 Capabilities, Experience, and Approach .......................................................... 9
4. Project Approach ...................................................................................................... 15
4.1 Approach to Performing Services ................................................................... 15
4.2 Additional Benefits and Value Added Elements ........................................... 20
5. Contract ...................................................................................................................... 23
6. Acknowledgement of Addenda ............................................................................... 24 Appendix A – Audited Financial Report
Appendix B – M&V Report
Appendix C – Sample Performance Energy Contract
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City of Cotati | Energy/Water Audit and Implementation Projects ii Cover Letter
August 22, 2024
Damien O'Bid, City Manager
City of Cotati
201 West Sierra Avenue
Cotati, CA 94931
RE: Request for Proposals for Energy/Water Audit and Implementation Projects With its storied history, the City of Cotati has thrived over time and deserves a partner who will carry forward this legacy of longevity and innovation, much like the City’s distinctive hexagonal plaza. We bring 50 years of successful partnerships with Bay Area municipalities and are committed to delivering an outstanding project for you!
Dear Mr. O’Bid:
The City of Cotati’s (City or Cotati) dedication to fighting climate change is clear, and your Climate Protection Measures since 2001 show your commitment. We commend you for your fiscally responsible program that supports residents and meets sustainability goals.
We are excited to respond to your energy and water audit RFP and would be honored to partner with you. Our extensive experience in the public sector allows us to align with your vision, offer expert support, and provide tailored funding solutions. We aim to help you achieve the City Council’s strategic goals to protect Cotati’s quality of life, ensure fiscal sustainability, and promote community engagement and increased equity and inclusion, while advancing the County’s Climate Action 2020 and Beyond Plan.
Below is a summary of our experience with similar technologies and public agency partners. • Solar PV: ENGIE has installed more than 300 MW of customer-sited solar PV systems in California and our solar PV projects performed at over 105% of their stated outputs for the most recently reconciled year. We have installed more public sector solar than any other builder. • Microgrids: With a dedicated team of microgrid and BESS subject matter experts (SMEs) that focus on resiliency solutions for our customers, ENGIE currently has over 190 MW in operation and 23 MW under construction. In California, our microgrid experience includes Solano County, City of Milpitas, Santa Rita Jail, Chula Vista ESD, SSWC Anza Electric, and Borrego Springs. • Battery Energy Storage Systems (BESS): We have built over 190 BESS, providing 57.9 MWh of storage capacity with 30 MWh enrolled and participating in 8 grid services programs throughout the country.
• Electric Vehicle Charging Stations (EVCS): ENGIE has installed EVCS alongside our solar projects, procured incentives on behalf of our customers, and have a full e-Mobility team to support the City’s efforts to provide clean transportation options.
Additional distinguishing features include:
• Track Record of Outstanding Local Projects: ENGIE has undertaken numerous projects around the Bay Area. Figure 1 on the next page highlights relevant projects constructed in the last 5 years in the adjacent map. We have outstanding references and post-construction customer satisfaction scores.
In Northern CA, we are currently in construction in Solano County and the cities of Menlo Park, and Milpitas and developing projects for San Joaquin County and the cities of American Canyon (phase 2) and Pittsburg.
The Respondent, ENGIE
Services U.S. Inc. (ENGIE),
is part of the ENGIE Group,
a global company in lowcarbon energy services.
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Cover Letter
City of Cotati | Energy/Water Audit and Implementation Projects iii • More resources in California than any of our competitors:
– 190+ personnel dedicated to the public sector in CA
– 35 licensed engineering professionals in CA
– 31 employees providing Operations & Maintenance (O&M) in CA managing 158 contracts with the longest guarantee contract term of 25 years
• Secured over $100 million in
state and utility incentives or
rebate funding on behalf of our
customers in California. ENGIE
will help Cotati maximize the
game-changing Inflation
Reduction Act funding in the
coming months and years. The
expanded Investment Tax Credit
will provide the City with the
opportunity to obtain tax credits
and potentially more credits
depending on whether the
project meets the domestic
content, energy community
and/or disadvantaged
community guidelines.
• ENGIE’s Community Engagement team will work with the City to engage the broader community around clean energy and sustainability. The team is prepared to support the creation of program for disadvantaged communities, engage youth around STEM, and spearhead innovative technology pilots to improve public safety.
As you review this response, you'll see that we focus entirely on providing municipal solutions tailored to the City’s specific needs. Our team is prepared to handle every aspect of the project from start to finish, ensuring successful implementation.
Our goal is to deliver a comprehensive program that the City of Cotati community can take pride in, and that complements the outstanding work that has already been done to achieve the goals of the City.
Thank you for the opportunity to respond to the City of Cotati Energy/Water Audit and Implementation project.
For questions regarding our response, please contact Amar Tiwari, Senior Program Development Manager at 415-264-2642 or [email protected].
Sincerely,
Courtney Jenkins
President
Authorized to Sign on Behalf of
ENGIE Services U.S. Inc.
Figure 1. Map of Local Area Projects Constructed in Last 5 Years “With a single project, the city will
reduce our energy costs and save
$12 million over the life of the project
that can be reinvested into other city
and neighborhood services.”
Mayor Lori Wilson, City of Suisun City
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Section 1 – Background
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City of Cotati | Energy/Water Audit and Implementation Projects 1
1. Background
1.1 Unique Qualifications
Our unique qualifications set us apart in the industry, combining specialized expertise with innovative solutions. The following list contains a few of the differentiators detailed in the cover letter:
• Track Record of Outstanding Local Projects:
• More resources in California than any of our competitors • Secured over $100 million in state and utility incentives or rebate funding on behalf of our customers in California
• ENGIE’s Community Engagement Team
1.1.1 Years in Business
We have been involved in the energy-efficiency related business for 50 years; and has offered performance contracting services for 50 years nationally and in the state of California.
1.1.2 Fiscal Strength
ENGIE is a financially secure and stable company—backed by the global financial strength of ENGIE Group. We have a proven record as a globally trusted and financially solid partner with an investment grade credit rating and significant balance sheet strengths. ENGIE Group is listed on the Euronext Paris, Euronext Brussels, Regulated Market of the Luxembourg Stock Exchanges, and Dow Jones Stoxx 600, just to mention a few.
1.1.2.1 Most Recent Audited Financial Report
Our 2023 Audited Financial Report is in Appendix A.
1.1.3 Meeting Minimum Qualifications
ENGIE not only meets the minimum qualifications, but be also exceed them, as demonstrated below.
Exceeding minimum qualifications means not just meeting basic requirements but also delivering exceptional value and performance. We enhance project outcomes through innovative solutions, superior quality, and proactive service.
This approach reflects our commitment to not only fulfill but surpass expectations, ensuring greater efficiency, satisfaction, and long-term success. Our dedication to excellence drives us to offer more than what’s required, creating added benefits and delivering results that truly stand out.
1.1.3.1 Current NAESCO accreditation
We are accredited at the Energy Services Provider level, the highest level an ESCO can attain.
1.1.3.2 On the U.S. DOE’s qualified list of ESCOs
ENGIE is an approved performance contractor for the DOE for many years.
1.1.3.3 Active G.C. license in CA
We have been a general contractor for 50 years and maintained the same license in California under license #995037. ENGIE has General A, B, C10, and C46 licenses.
1.1.3.4 Minimum of $30 million in bonding capacity
ENGIE has a $75 million single project bonding limit, with an aggregate bonding capacity of $300 million.
1.1.3.5 Successful implementation of similar projects
Please refer to Section 3 – Project History & References for details and references. 703 of 1021
1. Background
City of Cotati | Energy/Water Audit and Implementation Projects 2
1.1.3.6 Demonstrated experience in retrofitting municipal infrastructure to reduce energy and water consumption
ENGIE excels in retrofitting municipal infrastructure to cut energy and water usage. We have a proven history of upgrading systems and applying innovative solutions, which helps municipalities lower operational costs and boost sustainability. Notable projects include work with the Cities of Milpitas, Hercules, and Suisun City.
We focus on your unique needs, crafting tailored strategies to optimize resource use and achieve measurable improvements. Our practical, hands-on experience guarantees that we implement effective, proven methods to enhance efficiency and support your sustainability goals.
1.1.3.7 Proven ability to provide a team of California licensed mechanical, electrical, structural, and civil engineers as may be necessary
Our team includes 35 registered California PEs with experience in mechanical, electrical, and civil engineering.
1.1.3.8 IPMVP and M&V Reports
Section 4.1.3 discusses IPMVP. The M&V Reports are in Appendix B.
1.1.3.9 Pending or recent litigation
No pending or recent litigation in the past 36 months associated with the savings performance and/or M&V of a guaranteed energy savings project.
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Section 2 - Project Team &
Management Structure
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City of Cotati | Audit and Implementation of Energy and Water Resources Efficiency Improvement Projects 3
2. Project Team & Management Structure
2.1 Team Organizational Chart
ENGIE’s team members for the City’s Project are shown in Figure 2 below.
Figure 2. Team Organizational Chart
2.2 Resumes
ENGIE prides itself on our dedicated and experienced team members. We have a talented and robust team dedicated to this Project. Every key personnel listed on the following pages is familiar and readily available to support this Project.
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2. Project Team
City of Cotati | Energy/Water Audit and Implementation Projects 4 Amar Tiwari
Senior Program
Development
Manager
Role: Amar brings over 15 years of experience
as a Process Design Engineer and Project
Manager. He manages the customer lifecycle
from project development through to postconstruction.
Amar supports new business development
initiatives and keeps up to date on new
technologies available, giving him a strong
comprehension of energy saving technologies.
Years of Experience: 15 years
Education: MBA, University of California,
Berkeley, CA
BS, Chemical Engineering, Auburn
University, Auburn, AL
Relevant California Experience:
• Adventist Health West
• City of Hercules
• County of Solano
• Contra Costa County Fire
Protection District
• Dublin USD
• Milpitas USD
• Salinas City ESD
• San Mateo-Foster City SD
• San Mateo UHSD
• Tamalpais UHSD
John Seminoff
Project Manager
Role: John provides design solutions,
estimates of implementation-costs, develops
construction schedules, and manages the
construction and implementation processes.
His central concerns are the client’s
understanding and satisfaction with the
systems and improvements.
Years of Experience: 30+ years
Education: BS, Energy Management and
Design, Sonoma State University, Rohnert
Park, CA
License(s)/Registration: Licensed
Contractor – C-46
Relevant California Experience:
• Alameda County Fairgrounds
• Adventist Health
• City of Hayward
• City of Menlo Park
• DeSoto Next Generation Solar
Energy Center
• Quinto Solar Project
• Solar Star Projects
• State Compensation Insurance
Fund
• Sutter Health
Doug
Ledbetter, PE
Senior Electrical
Engineer
Role: Doug develops power distribution,
power transmission, power system
protection, substation engineering, and
power generation systems, including
interconnection of power plants to public
utility grids.
Education: BS, Electrical Engineering,
University of California Santa Barbara
License(s)/Registration(s):
Registered Professional Engineer—
Electrical, CA: 22601
Relevant California Experience:
• City of American Canyon
• City of Firebaugh
• City of Fremont
• City of Gonzales
• City of Grass Valley
• City of Hayward
• City of Livermore
• City of Madera
• City of Marysville
• City of Menlo Park
• City of Milpitas
• City of Salinas
• City of Yuba City
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2. Project Team
City of Cotati | Energy/Water Audit and Implementation Projects 5 Aaron Gusak,
PE
Senior Project
Engineer
Role: Aaron provides engineering support
for energy efficiency and renewable energy
projects for public sector customers such
as school districts, universities, and cities in
Northern California. These projects allow
customers to use energy more efficiently and
provide long-term cost savings.
Years of Experience: 15 years
Education: BS, Mechanical Engineering,
California State University, Sacramento, CA
License(s)/Registration(s): Professional
Engineer – Electrical, CA: 23632
Relevant California Experience:
• Adventist Health West
• City of Firebaugh
• City of Madera
• City of Mendota
• El Dorado UHSD
• Escalon USD
• Gustine USD
• Merced UHSD
• Salinas UHSD
• State Fund
• Sutter Health
Lea Pfeffer
Community
Engagement
Manager
Role: Lea develops programs that
complement and build on the energy work.
She collaborates with the customer at every
phase of the project, serving as an ongoing
point of contact and resource for the
customer with our education and
engagement programs.
Years of Experience: 8 years
Education: MS, International Relations,
Sciences Po Doctoral School, Paris
BS, Political Science, University of California,
Los Angeles
Relevant California Experience:
• Adventist Health West
• City of Hercules
• City of Milpitas
• Cupertino USD
• Hayward USD
• John Swett USD
• Livermore JUSD
• Mountain View-Whisman
• Santa Clara County COE
Neal Bartek
Microgrid Specialist
Role: Neal delivers solutions that improve
customers’ resiliency and continuity of
critical operations and services. He is
responsible for tracking ever-evolving
technology and organizational best
practices for the competitive design,
procurement, construction, and operation
of microgrids.
Years of Experience: 26 years
Education: Operations Research &
Industrial Engineering, Cornell University,
Ithaca, NY
Relevant California Experience:
• Adventist Health Portfolio,
Statewide CA
• City of Menlo Park
• City of Milpitas
• County of Solano
• Sierra Southwest Cooperative
• West County Wastewater
District
• Yucaipa Valley Water District
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2. Project Team
City of Cotati | Energy/Water Audit and Implementation Projects 6 Peter Holliday,
PE
Construction
Manager
Role: Peter has extensive construction
industry management experience in
building shell and core, complicated
renovations, and energy efficient upgrades.
His responsibilities on this project will include
on-site supervision, client interactions, and
contract negotiations.
Years of Experience: 30+ years
Education: BS, Construction Management
Technology, California State University,
Sacramento
License(s)/Certifications(s): 30 hour OSHA
Certified First Aid – AED
Certified Fall Protection
Relevant California Experience:
• City of Dublin
• West County Wastewater
District
• Travis USD
• Hayward USD
• Mountain House New
College Campus
• Wasco Prison
• Valley Village Santa Clara
Matthew Hobbs
O&M Manager
Role: Matthew has over 24 years of industry
experience. His diverse background in various
roles includes PV installer, Superintendent,
Lead Electrician, and O&M Field Manager.
He holds certifications in OSHA 30, CPR,
NFPA 70E, and is a California Certified
Journeyman since 2018, highlighting his
commitment to safety and excellence in
the industry.
Years of Experience: 26 years
Certification(s): CPR and First aid certified
OSHA Certified Equipment Trainer
OSHA 30
Relevant California Experience:
• City of Dublin
• County of Santa Cruz
• County of Shasta
• County of Sutter
• South San Francisco USD
Roger Chung
Commercial & Risk
Director (Project
Finance)
Role: Roger has arranged more than $400
million in paid from savings project
financings in various structures. He is
responsible for analyzing client needs/
concerns and then structuring and
coordinating all project financing activities
to assure the optimal form and cost of
financing is obtained.
Years of Experience: 20 years
Education: BS, Management Science,
University of California San Diego, CA
Relevant California Experience:
• Adventist Health West
• Alisal USD
• City of Milpitas
• East Side UHSD
• El Dorado UHSD
• Hayward USD
• Merced UHSD
• Mountain View-Whisman SD
• Salinas UHSD
• Santa Barbara USD
• State Fund
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2. Project Team
City of Cotati | Energy/Water Audit and Implementation Projects 7 Christina
McCormick, JD
Senior Legal
Counsel
Role: Chris drafts and negotiates various
legal agreements with customers, vendors,
and subcontractors, including program
development agreements, energy services
agreements, operations and maintenance
agreements, engineering, procurement and
construction agreements, subcontracts, and
purchase orders.
Years of Experience: 30 years
Education: JD, University of Michigan Law
School, Ann Arbor, MI, 1994
BA, Finance, University of Illinois,
Champaign-Urbana, 1989
Relevant California Experience:
• Adventist Health West
• City of Milpitas
• East Side UHSD
• El Dorado UHSD
• Franklin McKinley USD
• Gustine USD
• Hayward USD
• Merced UHSD
• Mountain View-Whisman SD
• North Monterey County USD
• Salinas UHSD
• State Fund
Ed Jakimzak
M&V Manager
Role: Ed manages M&V work and ongoing
customer services for ENGIE’s west region.
He coordinates and performs all physical
measurements and creates the reports in
accordance with the IPMVP.
Years of Experience: 18 years
Education: MS, Energy Management,
New York Institute of Technology, Old
Westbury, NY
BS, Electrical Engineering, California State
University, Northridge, CA
Relevant California Experience:
• Adventist Health West
• City of Milpitas
• El Dorado UHSD
• East Side UHSD
• Escalon USD
• Gustine USD
• Hayward USD
• Merced UHSD
• Mountain View-Whisman SD
• North Monterey County USD
• Salinas CESD
• Salinas UHSD
Clint Hummer
Health & Safety
Manager
Role: Clint specializes in construction
safety consulting, risk assessment, training,
and regulatory compliance. He provides a
broad spectrum of loss control, risk
management, environmental and safety
services.
Years of Experience: 17 years
Education: BA, Public Administration,
Rutgers University, Camden, NJ
Relevant California Experience:
• Adventist Health West
• City of Milpitas
• East Side UHSD
• El Dorado UHSD
• Escalon USD
• Gustine USD
• Hayward USD
• Mountain View-Whisman SD
• North Monterey County USD
• Paso Robles JUSD
• Salinas CESD
• Salinas UHSD
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2. Project Team
City of Cotati | Energy/Water Audit and Implementation Projects 8
2.3 Key Individuals
Name Role Percentage of Full-time
Commitment
Amar Tiwari Senior Program Development Manager 100%
John Seminoff Project Manager 100%
Doug Ledbetter, PE Senior Electrical Engineer 50%
Neal Bartek Microgrid Specialist 50%
Table 1. Our Key Individuals
ENGIE’s management team is committed to ensuring that the key staff members listed in Table 1 will be dedicated to the project according to the percentage of their time or effort specified. 711 of 1021
Section 3 - Project History &
References
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City of Cotati | Audit and Implementation of Energy and Water Resources Efficiency Improvement Projects 9
3. Project History & References
As one of only a handful of companies that offers true design-build general construction services specializing in energy and water conservation, building system retrofits, and renewable energy projects, ENGIE has the people, processes, technology, and delivery model to meet and exceed the City of Cotati needs.
3.1 Capabilities, Experience, and Approach
3.1.1 Capabilities
During the auditing phase, viable energy savings opportunities for the facilities ‒ control systems, air conditioning, heating systems, lighting, building structure (envelope), water and sewer systems, process equipment and compressed air, plug loads, and scheduling procedures ‒ are further scrutinized.
A major reason for ENGIE’s success with energy efficiency projects is the quality of our technical site analysis. The audit process is not only our opportunity to learn how a building operates, but more importantly, to understand what challenges the staff and community face, and how we can help solve them.
We have extensive and unparalleled experience conducting similar audits. On average, we audit 150 million square feet a year. In the past year in California alone, ENGIE audited hundreds of municipal facilities, covering over 7 million total square feet of space in cities both large and small. The data and experience gained through conducting these audits across a broad spectrum of public agencies will be leveraged to apply industry-leading best practices to the benefit of the City of Cotati.
3.1.2 Highlighted Projects
We provide detailed project information for 5 references on the following pages. 713 of 1021
3. Project History and References
City of Cotati | Energy/Water Audit and Implementation Projects 10
3.1.2.1 Project 1
City of Milpitas
Milpitas, CA
Project Description • Facilities Water Fixture Retrofits • Water Meter Upgrades
• SCADA & Remote Communication,
Pumping, and Automated Water
Treatment
• Upgraded Facilities and Pumping
Stations Lighting
• Upgraded Parks Lighting
• Upgraded 4,453 street light controls
• Retrofitted 2,185 City-wide LED
streetlights
• Upgraded Sports Field Lighting
• Installed 200 kW of solar PV
• Provided BESS and microgrid
solution for backup resiliency at
critical community facilities
• Installed EV Charging Stations
• Improved HVAC Ventilation
Proximity to City of Cotati 86 miles
Benefits & Payback • 4.2 million kWh reduction in annual utility electricity consumption • $1.5 million saved in energy and water costs annually • $30 million net lifetime savings through ENGIE's program • Improves city services and infrastructure for residents and businesses • Energy resiliency (backup power) for community centers • Addresses safety, efficiency, and climate action goals • Provides workforce and education opportunities
Key Staff that worked on the
project
Amar Tiwari, Doug Ledbetter, Neal Bartek
Total Annual Energy/Water
Savings Cost Savings/Avoidance
• Year 1 – $1,508,673
• Year 2 – $1,576,170
• Year 3 – $1,646,688
• Year 4 – $1,720,365
• Year 5 – $1,797,340
Project Size $35,048,004
Additional Value Created • Sponsored CivicSpark fellow
• Created Water Meter and
Sustainability Web pages and
outreach campaigns
• Dashboard of streaming solar data
• Community Earth Day celebration
• Developed City Sustainability
bike tour
Finance and Funding Approach • Bond Funds/COP
• Cash Contribution (GF, CIP, etc.)
• Incentive Rebates/Loans/On-Bill
• Tax Exempt Bonds and Leases
Client reference name and
current contact information
Elaine Marshall
Deputy Director of Public Works
City of Milpitas
408-586-2603
[email protected]
714 of 1021
3. Project History and References
City of Cotati | Energy/Water Audit and Implementation Projects 11
3.1.2.2 Project 2
City of Hercules
Hercules, CA
Project Description • One new solar PV canopy array provides 257 kW of electricity to city hall, the senior center, and the library
• Another new solar PV canopy array provides 126 kW to the community center's pool, gym, and teen center
• LED lighting retrofit throughout interior and exterior of city facilities • Retrofitting of 576 streetlights to LEDs, so that 95% of streetlights throughout Hercules are now LEDs
• HVAC modernization through repair/replacement of legacy systems at city hall, the library, and the senior center
• Installation of smart thermostats and software controls throughout city buildings
Proximity to City of Cotati 52 miles
Benefits & Payback • 500,000 kWh reduction in annual utility electricity consumption • $200k saved in energy and O&M costs annually
• $3 million net lifetime savings through ENGIE's program • Improves city infrastructure for residents
• Addresses safety, efficiency, and climate action goals • Provides education opportunities
Key Staff that worked on the
project
Amar Tiwari
Total Annual Energy/Water
Savings Cost Savings/Avoidance
• Year 1 – $192,941
• Year 2 – $201,982
• Year 3 – $211,447
• Year 4 – $221,355
• Year 5 – $231,727
Project Size $4,005,348
Additional Value Created • Dashboard of streaming solar data • STEM for preschool and after
school care
Finance and Funding Approach • Tax Exempt Lease Purchase Client reference name and
current contact information
Mike Roberts
Public Works Director
510-799-8241
[email protected]
715 of 1021
3. Project History and References
City of Cotati | Energy/Water Audit and Implementation Projects 12
3.1.2.3 Project 3
City of American
Canyon
American Canyon, CA
Project Description • 1.2 MW of solar PV canopies and ground-mounts across 3 sites • 120 kW BESS at Water Reclamation Facility for energy arbitrage and future islanding
• 4 emergency generators installed at critical facilities • LED lighting upgrades (over 2,000 fixtures) and 168 occupancy sensors • HVAC upgrades
• EV charging stations at City Hall
Proximity to City of Cotati 37 miles
Benefits & Payback • 1.7 million kWh reduction in annual utility electricity consumption • $400k saved in energy and O&M costs annually
• $9 million net lifetime savings through ENGIE's program • Reduce energy consumption and utility costs at city facilities • Replace or upgrade end-of-life equipment and/or inefficient systems at no out-of-pocket cost
• Reduce greenhouse gas (GHG) emissions
• Where relevant, phase-in reliability and resiliency measures to address grid de-energization risks at critical facilities
Key Staff that worked on the
project
Doug Ledbetter
Total Annual Energy/Water
Savings Cost Savings/Avoidance
• Year 1 – $401,262 (includes SGIP rebate)
• Year 2 – $386,021 (includes SGIP rebate)
• Year 3 – $401,103 (includes SGIP rebate)
• Year 4 – $415,799 (includes SGIP rebate)
• Year 5 – $418,269
Project Size $6,785,442
Additional Value Created • Paid high school and community college internships • Parks & Rec Nature Camps
• Earth Day Home Kids
• Community energy savings tips and pollution prevention week Finance and Funding Approach • TELP
• Cal OES (Office of Emergency Services) Grant
• Enterprise Funds
Client reference name and
current contact information
Jason Holley
City Manager
707-647-5323
[email protected]
716 of 1021
3. Project History and References
City of Cotati | Energy/Water Audit and Implementation Projects 13
3.1.2.4 Project 4
State
Compensation
Insurance Fund
Various Locations, CA
Project Description • 9.8 MW of solar across 6 sites
• 120 EV chargers
• 4.2 MWh of battery storage at 3 sites
Proximity to City of Cotati Various Locations throughout California Benefits & Payback • 311 GWh over 20 years, projected solar energy production, enough to power 26,500 homes.
• 230,000 tons of GHG emissions offset over 20 years
Key Staff that worked on the
project
John Seminoff, Doug Ledbetter, Aaron Gusak, Roger Chung, Chris McCormick, Ed Jakimzak, Clint Hummer
Total Annual Energy/Water
Savings Cost Savings/Avoidance
• Year 1 – $2,351,968 (0% rate escalation years 1-5)
• Year 2 – $2,340,207
• Year 3 – $2,328,505
• Year 4 – $2,316,864
• Year 5 – $2,305,279
Project Size $50,478,763
Additional Value Created • Hedge against rising utility costs Finance and Funding Approach • Cash
Client reference name and
current contact information
Teresa Navarec
Program Manager, State Fund
707-975-6858
[email protected]
717 of 1021
3. Project History and References
City of Cotati | Energy/Water Audit and Implementation Projects 14
3.1.2.5 Project 5
Mountain ViewWhisman School
District
Mountain View, CA
Project Description • Installed 1589 kW of canopy and roof-mount solar PV • Installation of EV charging stations
Proximity to City of Cotati 86 miles
Benefits & Payback • 2.3 million kWh reduction in annual utility electricity consumption • $600k saved in energy and O&M costs annually
• Improves school infrastructure for children and teachers • Addresses safety, efficiency, and climate action goals • Provides education opportunities
Key Staff that worked on the
project
Roger Chung, Chris McCormick, Ed Jakimzak, Clint Hummer Total Annual Energy/Water
Savings Cost Savings/Avoidance
• Year 1 – $586,681
• Year 2 – $615,243
• Year 3 – $641,066
• Year 4 – $664,005
• Year 5 – $691,898
Project Size $10,843,710
Additional Value Created • STEAM Literacy support
• Elementary Summer School support
• Hands-on Solar lessons and kits for each school
• Professional Development
Finance and Funding Approach • Bond Financing
Client reference name and
current contact information
Rebecca Westover
650-526-3550
[email protected]
718 of 1021
Section 4 - Project Approach
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City of Cotati | Audit and Implementation of Energy and Water Resources Efficiency Improvement Projects 15
4. Project Approach
4.1 Approach to Performing Services
As one of only a handful of companies that offers true design-build general construction services specializing in energy and water conservation, building system retrofits, and renewable energy projects, ENGIE has the people, processes, technology, and delivery model to meet and exceed the City’s needs.
4.1.1 Phase I: Audit and Project Development
Our approach for developing the City’s energy and water savings program includes the following steps shown in Figure 3:
Figure 3. Audit and Project Development
4.1.1.1 Project Kickoff and Utilities Analysis
Our team will create an energy and utility usage index for the selected buildings, facilities, and equipment to prioritize savings opportunities using available electricity, gas, and water usage/billing data. We then benchmark the usage data and the dollar cost to building square footage to gain an advanced picture of the opportunities present for energy, water, and resource reduction.
4.1.1.2 Energy Audit
Energy and Water Audit Capabilities
During the auditing phase, viable energy savings opportunities for the facilities ‒ control systems, air conditioning, heating systems, lighting, building structure (envelope), water and sewer systems, process equipment and compressed air, plug loads, and scheduling procedures ‒ are further scrutinized.
A major reason for our success with energy efficiency projects is the quality of our technical site analysis.
The audit process is not only our opportunity to learn how a building operates, but more importantly, to understand what challenges the staff and community face, and how we can help solve them.
ENGIE has extensive and unparalleled experience conducting similar audits.
On average, we audit 150 million square feet
a year. In the past year in California alone, we audited hundreds of municipal facilities, covering over 7 million total square feet of space in cities both large and small. The data and experience gained through conducting these audits across a broad spectrum of public agencies will be leveraged to apply industry-leading best practices to the benefit of the City of Cotati.
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4. Project Approach
City of Cotati | Energy/Water Audit and Implementation Projects 16 Energy and Water Audit Plan
We created the following preliminary audit management plan, shown in Figure 4, for the City of Cotati.
This is, of course, subject to feedback and direction from the City staff and leadership and will be discussed during the kickoff phase.
Figure 4. Energy Conservation Measure (ECM) Selection and Validation
4.1.1.3 Recommendations
To support your goals, we'll present a detailed plan for enhancing energy and water savings. This plan will outline specific measures, associated costs, anticipated savings, and the scope of work involved. Our recommendations will be included in the Final IGA, reflecting both the audit findings and your input.
Throughout the project, you'll have key roles in (decision-making, including selecting the most effective energy conservation measures, evaluating their payback periods, exploring funding options, and determining the best methods for measuring and verifying energy savings.
4.1.1.4 Financing
Our customers benefit from access to our highly experienced project finance team, who bring decades of expertise in public and energy finance. We offer a range of financing options to meet your needs, including municipal tax-exempt leases with non-appropriation clauses, Certificates of Participation (COPs), Power Purchase Agreements (PPAs), revenue and other bonds, and on-bill financing (OBF) options like those provided by PG&E. We also support financing through internal cash flow. Our goal is to help you choose the best financial solution for your project’s success.
As part of our commitment to service, we charge no fee for the provision of information to customers about its financing options. Our project finance team brings decades of experience in energy and public finance.
Furthermore, just as we are not tied to a single manufacturer for the purchase of project equipment, neither is it partial to a single funding source. Instead, our project finance team can help educate you about, and connect you to, a broad spectrum of options, allowing the City to select the financing source with the best rates, terms and conditions for your project and budgetary needs.
4.1.2 Phase II: Construction and Implementation
At ENGIE, we prioritize your project's success by managing every aspect of design and compliance. Our team handles all necessary permits and is backed by 35 licensed professional design engineers and a 721 of 1021
4. Project Approach
City of Cotati | Energy/Water Audit and Implementation Projects 17 network of highly qualified consultants. We specialize in developing comprehensive plans and specifications, ensuring robust construction support.
Our extensive experience with neighboring public agencies equips us with a deep understanding of relevant codes, standards, and legal requirements, particularly for energy conservation and generation programs.
To deliver top-notch quality and cost-effective solutions, we blend our in-house expertise with carefully selected subcontracted installation labor. As a local company with our corporate headquarters within 50 miles from Cotati, we are deeply invested in preserving the City’s heritage while advancing its energy and infrastructure objectives. We are committed to engaging local subcontractors and taking full responsibility for the entirety of your project—regardless of its scope, site, or number of components.
4.1.2.1 Procurement and Installation of New Equipment/Refurbishment of Existing Equipment
We pride ourselves on being the global leader in energy efficiency services. As a major buyer of lighting, HVAC equipment, and automation systems, we have a proven track record. In 2023, over $100 million in lighting construction was completed across Federal, County, City, and School districts nationwide, with even more projected for 2024. Each year, we also secure over 1 GW of solar PV modules.
Our procurement specialists are committed to finding the best solutions for you. By evaluating your needs through evaluating your needs through an overall cost assessment, we ensure you receive top-quality equipment at the most competitive prices.
As a design-build firm, ENGIE is dedicated exclusively to energy efficiency and renewable power generation services. Unlike equipment manufacturers or suppliers, our vendor-neutral stance prevents any conflicts of interest, allowing us to focus solely on delivering the best solutions for our clients.
Our commitment to providing superior solutions at optimal prices sets us apart and ensures we help you achieve the greatest energy savings possible.
4.1.2.2 Construction Management
We prioritize your convenience and project success with our comprehensive design-build approach. Unlike many competitors, we offer a streamlined experience by providing a single point of contact throughout both the development and construction phases. You can have peace of mind knowing that a dedicated ENGIE construction manager (CM) will be on-site whenever work is underway, ensuring everything runs smoothly.
We are committed to completing projects on time and within budget while minimizing disruption to your facility’s occupants. To keep your project efficient and cost-effective, we develop a site survey schedule that aims to reduce on-site time, thereby accelerating your savings. We identify opportunities to perform work outside of regular business hours or in ways that cause minimal disruption during business hours.
When any work might impact building occupants, we coordinate closely with your facilities maintenance staff to ensure a smooth and considerate process. Clear communication is central to our approach, helping us deliver a seamless implementation and achieve the best results for you.
During the implementation phase, our on-site CM holds weekly or bi-weekly construction meetings with designated facilities maintenance staff and contractors. These meetings consist of reviewing the previous week’s construction progress, outstanding issues, and action items. It will also cover the anticipated schedule for the next few weeks.
“I have been impressed with the quality
of subcontractors and ENGIE Services’
ability to schedule construction to
minimize impacting occupants of
adjacent structures. The ability to make
change was remarkable and smooth.”
– Joe Kuderca, Engineering Manager,
City of Livermore, CA
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4. Project Approach
City of Cotati | Energy/Water Audit and Implementation Projects 18 The CM will coordinate the anticipated installation/retrofit of equipment with the City’s facilities maintenance staff. In addition, we use proven construction methods to ensure ongoing operations are maintained to extent possible, including:
During the implementation phase, we ensure seamless communication and coordination through regular construction meetings. Our on-site CM will hold weekly or bi-weekly meetings with your designated facilities maintenance staff and contractors. These meetings will review progress, address any outstanding issues, and outline the upcoming schedule, keeping everyone informed and aligned.
Our CM will closely coordinate with your facilities maintenance team to plan and schedule equipment installations or retrofits. We are committed to maintaining your facility’s ongoing operations with minimal disruption by using proven construction methods, including:
• Strict Safety Protocols: We adhere to OSHA safety guidelines for all work, especially hazardous tasks like roof work, ensuring the safety of our workers and the secure handling of materials. • On-Site Supervision: We monitor contractor attendance and enforce the use of personal protective equipment to maintain a safe work environment. • Compliance with Protocols: We are experienced in fingerprinting and documenting site workers and will fully comply with your City’s protocols and procedures. • Efficient Installation: Our accelerated installation process is designed to minimize the impact on local activities and keep the project moving swiftly.
• Enhanced Security: If needed, we deploy security personnel to monitor job sites overnight and manage traffic changes, such as during street light installations, to ensure safety and smooth flow. • Minimized Disruption: Any work that affects parking availability will be carefully scheduled in coordination with the City to limit disruption to daily activities.
Our goal is to ensure a smooth and efficient construction process, with minimal impact on your operations and maximum attention to detail.
4.1.3 Phase III: Commissioning, Guarantee, and Monitoring
4.1.3.1 Projecting and Proving Energy Savings
For the success of any energy services performance contracting program, having a robust Measurement and Verification (M&V) plan is crucial. We understand the importance of this and adhere to the International Performance M&V Protocol (IPMVP), the industry standard recognized by NAESCO for accurately measuring energy savings from conservation projects.
Our M&V professionals will collaborate closely with the City to create a customized M&V plan that aligns with IPMVP guidelines. This ensures that your energy savings are measured effectively and with the highest level of confidence. The IPMVP provides various options for measuring and verifying savings, which we will review and select the best approach to fit your specific needs.
By following these best practices, we ensure transparency and reliability in tracking the success of your energy projects, giving you clear insights and assurance that your goals are being met.
The IPMVP options are categorized in Figure 5 on the next page. 723 of 1021
4. Project Approach
City of Cotati | Energy/Water Audit and Implementation Projects 19 Figure 5. IPMVP Options
4.1.3.2 Methodology, Formulas, and Reporting of Savings We guarantee performance by establishing a baseline energy use, predicting the savings reduction by using industry established building modeling and calculations, and monitoring and verifying the energy reduction throughout the guarantee. Our goal is to select a straightforward M&V approach that can be easily verified by the customer and/or their third-party reviewer.
4.1.3.3 Monitoring Services Available After Installation to Ensure Continued Savings ENGIE has one of the largest, most experienced M&V teams in the industry. A Certified M&V Professional (CMVP) with more than 25 years in performance contracting leads a team of full-time dedicated staff, with 7 certified staff members, and an average time in performance contracting of over 15 years each. The team has overseen hundreds of guarantees and currently has more than 240 clients with ongoing guarantees.
The team has one of the highest success rates in the industry — 109% for the most recently reconciled year — for achieving our guaranteed performance on projects. If project performance does not meet or exceed our guaranteed performance, ENGIE writes the customer a check for the difference, without delay or hassle. This outstanding monitoring department sets ENGIE apart from other companies that engage in performance-based energy programs.
Our M&V team has extensive expertise in commissioning, monitoring, and troubleshooting over 16 different types of energy management control systems. Not only is this team responsible for delivering a functional system, but they also continue to train and support our customers on that system for the duration of the contract.
4.1.3.4 “Energy Intelligent” M&V
The exact scope for monitoring required for the City is determined during the design phase and tailored to the energy measures to be implemented. ENGIE uses a proprietary web-based system, UtilityvisionTM, to monitor data acquired from our energy projects. As a standard, we provide monthly value reports from Utilityvision that we customize based on project and customer needs. Administrative personnel can use the software to create summary reports, while facility managers can set alarms and run trend analysis diagrams with the click of a button. Figure 6 displays a screenshot example of Utilityvision. 724 of 1021
4. Project Approach
City of Cotati | Energy/Water Audit and Implementation Projects 20 Figure 6. Utilityvision Summary Page
4.2 Additional Benefits and Value Added Elements
4.2.1 Our Approach
ENGIE’s business model is tailored for successful partnerships in the public sector. We actively manage projects to ensure clear communication with stakeholders and timelines that align with your needs. Our expert team is here to tackle the City’s challenges and partner with you to create a program that delivers real results for both your business and the community.
Our community impact team, made up of former educators, nonprofit leaders, and outreach experts, is dedicated to understanding and addressing your goals. We collaborate closely with you to design and implement programs that meet your specific needs. For example, we can help educate your staff and residents about the climate crisis and strategies for mitigation as outlined in your 2019 Climate Emergency Resolution. Our team's expertise and creativity can support various departments within the City, ensuring a tailored and impactful approach.
Other cities have met their specific goals in the following ways: a CivicSpark Fellow working on organic waste reduction and processing for County of Solano; providing workforce development internships for City of Ventura in partnership with the Boys and Girls Club; or supporting community placemaking through murals in City of Oceanside and City of Vacaville. Below are examples of various engagement scopes for energy programs we have designed and implemented to meet needs in California.
4.2.1.1 City of Milpitas
With a water infrastructure program ranging from residential and business AMI to automated water testing and treatment, to secure web-based systems, ENGIE enhanced the project with:
• Successful application for an international Smart 50 award for the smart city work done around wastewater, residential water, and overall energy and resiliency. • Development of an informational web page, 24-hour call center, and multi-lingual print outreach for the smart water meter roll out to residents and businesses. • Creation of educational signage at the community center to explain the installed microgrid technology and its benefits to residents.
• Field trip for local middle and high school students to learn about the energy project 725 of 1021
4. Project Approach
City of Cotati | Energy/Water Audit and Implementation Projects 21
4.2.1.2 City of American Canyon
Supporting their Marketing Department of one and building an employee pipeline for their Wastewater Department by attracting local talent; ENGIE partnered with the City to deliver:
• Paid internships to support the City’s Wastewater and Marketing departments • Communications support through City newsletter articles and project updates • Supporting City Earth Day events over multiple years with youth activities and hands-on materials, energy savings tips, and other handouts and giveaways.
4.2.1.3 City of Hercules
With the goal of supporting City youth, ENGIE partnered with the City to provide:
• After School Program including 5 STEM challenges, hands-on materials and professional development for facilitators
• Preschool STEM support including 5 activities, hands-on materials and PD for teachers
4.2.2 Potential Community Engagement Program Elements
4.2.2.1 Greenhouse Gas Reduction & Carbon Mitigation
Our core approach is to provide our customers the opportunity to make the transition to a zero-carbon footprint. Innovative energy solutions, renewable development and environmental stewardship will reduce energy consumption, minimize emissions and lead to a sustainable future. We are committed to continual improvement as we will never waver in our adherence to social responsibility as a core ethic.
4.2.2.2 Living Laboratory
Our community facing dashboards provide real-time data to explain your energy projects to residents.
The dashboards can highlight project impact, provide energy saving tips to residents, and visualize the GHG reduction and impact to your project.
The Living Laboratory Online Dashboard features data such as:
• Carbon Dioxide offset
• Solar electricity production
• Solar insolation
• Multiple timescales
4.2.2.3 Reduced Operational Costs
At ENGIE, centering around your most important goals allows us to create a program that not only brings efficiency to your operations, but also optimizes the usability of your built environment with long-term benefits. Depending upon the scope of ECMs installed, there will be savings to the City for reduced operational costs associated with older technology and equipment.
4.2.2.4 STEM Education
We can enhance the County's existing youth programs, like Summer Camp and after-school activities, by providing hands-on STEM activities. This support includes materials, printed facilitator guides, and professional development for facilitators, all aimed at reducing program costs.
ENGIE can support programs for preschool through high school as shown in Figure 7. We can work with the City to incorporate important themes to the City such as music or agriculture.
Figure 7. Youth STEM Engagement
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4. Project Approach
City of Cotati | Energy/Water Audit and Implementation Projects 22
4.2.2.5 Technical Training
ENGIE can provide a training program for City of Cotati personnel and/or contractors for each installed ECMs. This encompasses instruction on operation, troubleshooting, maintenance, and repair of ECMs, and all maintenance plans and manuals. Trainings can also be filmed or designed from inception to be video based trainings to easily bring new employees and contractors up to speed.
4.2.3 Economic Development Within the City
4.2.3.1 Local Subcontractor Workshops
To support local subcontractors, ENGIE invites local companies to learn about the project, meet the project team, learn about our procurement process, and pre-qualify their companies. Our June 2024 event in City of Oceanside has already resulted in the hiring of a local roofing contractor for the project.
4.2.3.2 Civic Spark Fellow
ENGIE can leverage our partnership with CivicSpark, a resiliency focused division of AmeriCorps, to bring a full-time fellow to the District. CivicSpark Fellows, recruited from the country’s top sustainability-focused undergraduate programs, spend 11 months with agencies to help build capacity for research, planning, and implementation of projects looking at sustainability, climate change, energy, and water.
4.2.3.3 Paid Internships
Our internship program gives local high school, community college and university students the same challenging work as our own team members on energy projects for our customers. We have put time and thought into developing an internship program that provides youth with real work experience, enriching and networking engagement with mentors, and communication with interns nationwide.
4.2.4 Publicity, Branding, & Marketing
4.2.4.1 Award Identification and Application
ENGIE wants to share your sustainability leadership
and impacts with the broader community. Bringing
attention to your sustainability work both inspires
other communities and recognizes and rewards
your dedication and work for your residents.
We research award opportunities, develop a
strong and comprehensive application, and
handle the submission, fees, and follow-up
process. Figure 8 shows a few of the awards
our clients have received with our input.
4.2.4.2 Communications
We provide presentations at Board meetings or
community events, develop social media posts, utility bill inserts, flyers or postcards for community centers and events, create museum quality signage, and even videos to educate residents about the energy project. From updates about our project to articles about climate change and sustainability topics, we can support your outreach and communication goals.
4.2.4.3 Community Events
ENGIE Is happy to support community events, from providing planning support, booths, and activities for existing events to creating a new custom outreach event for the City. The City of Vacaville wanted to develop, implement, and publicize a Tree Infusion Program to mitigate the necessary tree removal for energy upgrade work, so ENGIE provided residents with smaller trees to ensure the program message and benefits were reaching residents across the City.
Figure 8. Customer Awards
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Section 5 – Pricing
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City of Cotati | Audit and Implementation of Energy and Water Resources Efficiency Improvement Projects 23
5. Contract
A sample Performance Energy Contract is located in Appendix C.
PE/IGA Pricing Proposal
RFP
DESIGN-BUILD ENERGY SERVICE
Pursuant to and in compliance with your Notice Requesting Proposals and all other documents relating thereto, the undersigned respondent, having familiarized him/herself with the terms and conditions of the proposal documents, hereby proposes and agrees to perform the work to be done and to provide all labor and materials necessary to perform the work.
Name of Respondent: ENGIE Services U.S. Inc.
Preliminary Evaluation (PE)
If the respondent charges fees to perform a preliminary evaluation, please provide the price and indicate if it’s waived if the City proceeds to the IGA.
$ 0 Fees waived if the City proceeds to IGA?
Investment Grade Audit (IGA):
Does the respondent require an IGA agreement to be entered into before a Guaranteed Savings Agreement scope of work, price and savings can be finalized? NO
If an IGA agreement is required, does it include exit fees and/or penalties in the event the City chooses to not implement some or all of the IGA findings?
NO
If the City implements some or all of the IGA findings with the proposer, is the price of the IGA waived? YES
What is the respondent’s price to complete an IGA?
$ 0
Certification by proposer
I hereby certify that I am able to commit the firm to the proposal submitted.
Company: ENGIE Services U.S. Inc.
Name (printed): Courtney Jenkins
Title: President
Signature: Date: August 22, 2024
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Section 6 – Acknowledgement
of Addenda
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City of Cotati | Audit and Implementation of Energy and Water Resources Efficiency Improvement Projects 24
6. Acknowledgement of Addenda
ENGIE confirms that we did not receive any responses to written questions during the proposal period. 731 of 1021
Appendix A – Audited Financial
Report
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2023 MANAGEMENT REPORT
AND ANNUAL CONSOLIDATED
FINANCIAL STATEMENTS
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ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
2 CONTENTS
01 MANAGEMENT REPORT
1 ENGIE 2023 RESULTS..............................................................................................................................................6 2 OTHER INCOME STATEMENT ITEMS............................................................................................................... 17 3 CHANGES IN NET FINANCIAL DEBT................................................................................................................. 19 4 OTHER ITEMS IN THE STATEMENT OF FINANCIAL POSITION.................................................................. 23 5 PARENT COMPANY FINANCIAL STATEMENTS............................................................................................. 24 02 CONSOLIDATED FINANCIAL STATEMENTS
INCOME STATEMENT.......................................................................................................................................................... 26 STATEMENT OF COMPREHENSIVE INCOME............................................................................................................... 27 STATEMENT OF FINANCIAL POSITION........................................................................................................................... 28 STATEMENT OF CHANGES IN EQUITY........................................................................................................................... 30 STATEMENT OF CASH FLOWS......................................................................................................................................... 32 03 NOTES TO THE CONSOLIDATED FINANCIAL
STATEMENTS
Note 1 ACCOUNTING FRAMEWORK AND BASIS FOR PREPARING THE CONSOLIDATED FINANCIAL STATEMENTS ......................................................................................................................................................... 35 Note 2 MAIN SUBSIDIARIES AT DECEMBER 31, 2023................................................................................................ 40 Note 3 INVESTMENTS IN EQUITY METHOD ENTITIES.............................................................................................. 46 Note 4 MAIN CHANGES IN GROUP STRUCTURE....................................................................................................... 54 Note 5 FINANCIAL INDICATORS USED IN FINANCIAL COMMUNICATION............................................................ 56 Note 6 SEGMENT INFORMATION.................................................................................................................................... 61 Note 7 REVENUES.............................................................................................................................................................. 65 Note 8 OPERATING EXPENSES...................................................................................................................................... 69 Note 9 OTHER ITEMS OF NET INCOME/(LOSS) FROM OPERATING ACTIVITIES............................................... 71 Note 10 NET FINANCIAL INCOME/(LOSS) ....................................................................................................................... 74 Note 11 INCOME TAX EXPENSE........................................................................................................................................ 75 Note 12 EARNINGS PER SHARE ....................................................................................................................................... 79 Note 13 FIXED ASSETS........................................................................................................................................................ 80 Note 14 FINANCIAL INSTRUMENTS.................................................................................................................................. 94 Note 15 RISKS ARISING FROM FINANCIAL INSTRUMENTS.....................................................................................111 Note 16 EQUITY ...................................................................................................................................................................131 734 of 1021
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
3 Note 17 PROVISIONS .........................................................................................................................................................134 Note 18 POST-EMPLOYMENT BENEFITS AND OTHER LONG-TERM BENEFITS...............................................143 Note 19 SHARE-BASED PAYMENTS...............................................................................................................................152 Note 20 RELATED PARTY TRANSACTIONS.................................................................................................................153 Note 21 EXECUTIVE COMPENSATION ..........................................................................................................................155 Note 22 WORKING CAPITAL REQUIREMENTS, INVENTORIES, OTHER ASSETS AND OTHER LIABILITIES156 Note 23 LEGAL AND ANTI-TRUST PROCEEDINGS.....................................................................................................158 Note 24 SUBSEQUENT EVENTS......................................................................................................................................165 Note 25 FEES PAID TO THE STATUTORY AUDITORS AND TO MEMBERS OF THEIR NETWORKS ..............166 Note 26 INFORMATION REGARDING LUXEMBOURG AND DUTCH COMPANIES EXEMPTED FROM THE REQUIREMENTS TO PUBLISH ANNUAL FINANCIAL STATEMENTS.......................................................167 735 of 1021
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
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ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
5 01 MANAGEMENT REPORT
1 ENGIE 2023 RESULTS..............................................................................................................................................6 2 OTHER INCOME STATEMENT ITEMS............................................................................................................... 17 3 CHANGES IN NET FINANCIAL DEBT................................................................................................................. 19 4 OTHER ITEMS IN THE STATEMENT OF FINANCIAL POSITION.................................................................. 23 5 PARENT COMPANY FINANCIAL STATEMENTS............................................................................................. 24 737 of 1021
MANAGEMENT REPORT
1 ENGIE 2023 RESULTS
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
6 1 ENGIE 2023 RESULTS
ENGIE FY 2023 results
Another year of strong growth in results underpinned by successful execution of our strategy
Proposed dividend of €1.43 per share for 2023
Robust medium-term outlook 2024 – 2026
Business highlights
• High pace of growth in Renewables with 3.9 GW of
additional installed capacity in 2023 reaching a total of
41.4 GW
• Acceleration in battery storage with the acquisition of BRP in the United States and the commissioning of
Hazelwood in Australia
• Visibility reinforced on the contribution of Networks in France
• Continued progress in Net Zero 2045 trajectory with a 54% reduction vs. 2017 in GHG emissions from
energy production to 52Mt in 2023
Signature of the final agreement on Belgian nuclear,
thereby fundamentally de-risking the Group
Financial performance
• Guidance 2023 achieved with NRIgs of €5.4 billion
• EBIT excluding nuclear of €9.5 billion, an organic
increase of 18%, driven mainly by GEMS and
Renewables
• Cash Flow From Operations(1) sharply up by
€5 billion supported by improvement in working
capital
• Growth capexup 48% to €8.1 billion
• Solid balance sheet with economic net debt to
EBITDA at 3.1x
• Net financial debt at €29.5 billion, up €5.4 billion, economic net debt at €46.5 billion, up €7.7 billion
• 2024 NRIgs(2) expected in the range of €4.2 to
€4.8 billion
• Proposed dividend of €1.43 per share for 2023,
corresponding to a pay-out ratio of 65%
1.1 Key financial figures at December 31, 2023
In billions of euros Dec. 31, 2023 Dec. 31, 2022
% change
(reported
basis)
% change
(organic
basis)
Revenues 82.6 93.9 -12.0% -11.4%
EBITDA (excluding Nuclear) 13.7 12.2 +12.5% +12.7%
EBITDA 15.0 13.7 +9.5% +9.7%
EBIT (excluding Nuclear) 9.5 8.0 +18.2% +18.3%
Net recurring income of continuing activities, Group share 5.4 5.2 +2.8% +2.7% Net income, Group share 2.2 0.2
CAPEX (1) 10.6 7.9 +17.4%
Cash Flow From Operations (CFFO) 13.1 8.0 +63.1%
Net financial debt 29.5 -€5.4 billion versus Dec. 31, 2022 Economic net debt 46.5 +€7.7 billion versus Dec. 31, 2022 Net financial debt 3.1x +0.3X versus Dec. 31, 2022
(1) Net of DBSO sell down (Develop, Build, Share & Operate), US tax equity proceeds, including net debt acquired. (1) Cash Flow From Operations: Free Cash Flow before
maintenance Capex and nuclear phase-out expenses
(2) Net recurring income Group share.
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7 1.2 2024-2026 outlook and guidance
The objectives for the financial years ending December 31, 2024, 2025 and 2026 presented below are based on data, assumptions and estimates considered reasonable by the Group at the date of publication of this document.
These data and assumptions may change or be modified as a result of uncertainties relating to the financial, accounting, competitive, regulatory and tax environments, or other factors of which the Group is unaware at the date of registration of this document. Furthermore, the realization of forecasts depends on the success of the Group's strategy. Consequently, the Group neither undertakes nor gives any guarantee that the forecasts set out in this section will be achieved.
The objectives presented below and underlying assumptions have also been established in accordance with the provisions of Delegated Regulation (EU) No. 2019/980, a supplement to Regulation (EU) No. 2017/1129, and the ESMA recommendations on forecasts.
These objectives result from the budget and medium-term plan processes described in Note 13 to the consolidated financial statements; they have been established on a basis comparable to historical financial information and in accordance with the accounting policies applied to the Group's consolidated financial statements for the year ended December 31, 2023 described in the consolidated financial statements.
1.2.1. 2024-2026 outlook and guidance
ENGIE continues actively to roll out its Strategic Plan aimed at achieving carbon Net Zero by 2045.
Despite decrease in market prices in the last quarters and given the now embedded growth of GEMS contribution to our activities, ENGIE upgrades net recurring income Group share guidance for 2024 to a range of €4.2 to 4.8 billion compared to the previous range of €3.8 to 4.4 billion. EBIT excluding Nuclear is expected within an indicative range of €7.5 to
8.5 billion (compared to €7.2 to 8.2 billion previously announced). 2026: a pivotal year for ENGIE
By 2026, the Group anticipates growth in Renewables fuelled by investments, in Energy Solutions driven by additional capacity and improved margins as well as a higher contribution from Networks and GEMS with a normalized yearly EBIT upgraded from €1.0 billion to €1.5 billion, which allows to offset the impact of the decrease in commodity prices and spreads in Europe, occurred in the second half of last year, on activities exposed to market prices. Batteries activities are also expected to make an increasing contribution to the Group's results from 2024 onwards. Furthermore, as anticipated, ENGIE expects a decrease in Nuclear results following the shutdown of several power plants in Belgium by 2025 and the LTO of Doel 4 and Tihange 3 reactors.
Therefore, ENGIE outlook for 2024 – 2026 is:
In billions of euros 2024 2025 2026
EBIT excluding Nuclear (new) 7.5 - 8.5 7.9 - 8.9 8.2 - 9.2 EBIT excluding Nuclear (previous) 7.2 - 8.2 7.5 - 8.5 n/a NRIgs guidance (new) 4.2 - 4.8 3.9 - 4.5 3.7 - 4.3
NRIgs guidance (previous) 3.8 - 4.4 4.1 - 4.7 n/a
Price assumptions for the 2024-2026 guidance are based on forward prices in Europe as of 29 December 2023.
ENGIE is committed to a strong investment grade credit rating and continues to target a ratio below or equal to 4.0x economic net debt to EBITDA over the long-term.
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8 Main drivers for 2024-2026 EBIT evolution by activity:
2021 2023 Activity
Expectations for main EBIT
evolution drivers
vs.
2021 (1)
vs.
2023 (1) 2026
EBIT excluding
Nuclear
€5,2 billion
EBIT excluding
Nuclear
€9,5 billion
Renewables
Investments contribution, lower
prices ++ +
EBIT excluding
Nuclear indication
€8.2 billion
to
€9.2 billion
Networks
Regulated tariffs reflecting
inflation, cost and revenue
clawback from previous period in
France, new investments ++ ++
Energy
Solutions
Investments contribution,
continued improvement of
performance, negative one-offs in
2023 =+ +
FlexGen
Prices & volatility normalization,
lower thermal volumes partially
offset by acceleration in batteries =- -
Retail
Portfolio management and
optimization, high comparison
basis in 2023 =+ =-
GEMS
Normalization of prices and
volatility ++ - - - -
Nuclear
Plant shutdowns and LTO impact
from 2026 - -
Convention: each “+” sign amounts to c. €+500m, each “-” sign amounts to c. €-500m, “=+” sign amounts to a variation between 0 and +250, “=-” sign amounts to a variation between -250 to 0.
ENGIE forecasts an EBIT excluding nuclear between €8.2 and 9.2 billion in 2026 compared to €9.5 billion in 2023 (and €5.2 billion in 2021). Expected contribution from investments (+€1.6-2.0 billion) and performance (+€0.5-0.7 billion) should be offset by negative price effects of circa -€2.9-3.5 billion and other effects such as exchange rates, scope effects or climate.
The average annual growth rate of EBIT excluding nuclear between 2021 and 2026 is expected to reach 10% to 12%.
Capex
ENGIE confirms its €22-25 billion growth Capex target over 2023 to 2025 and expects to invest a similar yearly amount on average in 2026. Capital allocation is based on strict discipline respecting financial and ESG criteria.
Performance
ENGIE continues its efforts towards efficiency by significantly controlling its general and administrative expenses, improving the efficiency of support functions, and restructuring underperforming activities. The Group aims for a positive impact of these measures on EBIT amounting to circa €200 million p.a. over the period 2024-26.
Disposals
After successfully completing its previous disposal plan with €11 billion over the period 2021-22, the Group significantly reduced the amount of disposals in 2023 (€0.3 billion). ENGIE expects a limited portfolio turnover until 2026, with disposals estimated at less than €1 billion per year in average.
1.2.2. Assumptions
The assumptions used are as follows:
• Guidance and indications based on continuing operations; • No change in accounting policies;
• No major regulatory or macro-economic changes;
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9 • Inframarginal rent caps based on current legal texts; • Updated regulatory framework for 2024-2027 on French networks; • Full pass through of supply costs in French B2C retail tariffs; • Average temperature in France;
• Average hydro, wind, and solar productions;
• Average forex:
− €/USD: 1.11 for 2024, 1.13 for 2025 and 1.15 for 2026, − €/BRL: 5.34 over 2024-26;
• Belgian nuclear availability: c. 92% in 2024 and c. 94% in 2025, based on reactors availabilities as published on REMIT as of 01/01/2024, excluding LTO;
• Contingencies on Belgian operations of €0.2 billion in 2024 and €0.1 billion in 2025; • Market commodity prices as at 29 December 2023;
• Recurring net financial costs of €(2.5)-(2.8) billion over 2024-26; • Recurring effective tax rate: 25-27% over 2024-26.
1.3 Dividend policy reaffirmed and €1.43 per share proposal for 2023 The Board has reaffirmed the Group’s dividend policy with a payout ratio of 65-75% of net recurring income Group share, and a floor of €0.65 per share for the 2024 to 2026 period.
For 2023, the Board has proposed a payout ratio of 65%. This translates to a dividend of €1.43 per share, which will be proposed for shareholder approval at the Annual General Meeting on 30 April 2024.
1.4 Successful roll-out of the strategic plan
Renewables
ENGIE added 3.9 GW of renewable capacity in 2023, comprising 1.9 GW in Northern America, 0.8 GW in Europe, 0.7 GW in Latin America and 0.4 GW in the rest of the world. Total installed capacity of Renewables at ENGIE is now 41.4 GW. As of 31 December 2023, the Group reported 6.3 GW of capacity under construction from 60 projects. The Group signed more than 70 PPA contracts in 2023 for a total of 2.7 GW, of which 2.0 GW with a duration longer than five years, being the world leader in corporate PPAs.
In 2023, ENGIE strengthened its renewable energy platform in South Africa with the acquisition of BTE Renewables (340 MW in operation with a 3 GW pipeline) and the consolidation of Kathu, a 100 MW concentrated solar power plant.
The Group confirms its total installed capacity target of 50 GW by 2025 and 80 GW by 2030. This ambition is supported by a pipeline of 92 GW at the end of December 2023, up 12 GW compared to end-December 2022.
Networks - Renewable gas
The French Energy Regulatory Commission (CRE) has set the remuneration for gas transport, storage and distribution infrastructure for the period 2024-27. The CRE considers, for this regulatory period, a weighted average cost of capital of
4.10% for transport (compared to 4.25% previously), 4.60% for storage (compared to 4.75%) and 4.00% for distribution (compared to 4.10%). This decision reflects the regulator's desire to maintain the long-term sustainability of tariffs. These tariffs also allow for the recovery of a significant amount related to the regulatory period ending in 2024.
In Brazil, ENGIE Brasil Energia sold 15% of its stake in TAG to CDPQ. The main objective of this partial sale is to promote asset rotation and focus attention on the company's investment plan in renewables and transmission lines. Also in Brazil, ENGIE strengthened its electricity transmission activity by winning, at the beginning of 2023, a new 30-year concession for the construction and operation of 1,000 km of high-voltage lines in the states of Bahia, Minas Gerais and Espirito Santo.
Biomethane development in France continued its progress with an annual production capacity of up to 10.8 TWh connected to ENGIE networks, an increase of 2.6 TWh compared to end-2022. ENGIE enlarged its biomethane presence in Europe 741 of 1021
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10 with the acquisition of Ixora Energy Ltd, a leading biomethane producer based in the United Kingdom. The Group confirms its target of 10 TWh of biomethane production per year by 2030.
ENGIE has the ambition to develop green hydrogen production capacity of 4 GW by 2035.
FlexGen - Battery Energy Storage Systems (BESS)
In 2023, ENGIE accelerated its development in batteries with the commissioning of Hazelwood in Australia, its largest battery energy storage system in operation, and the acquisition of Broad Reach Power (BRP) in the United States.
ENGIE also obtained the construction permit for a 200 MW / 800 MWh battery energy storage system at the Vilvoorde site in Belgium, to be commissioned in 2025, with a 15-year capacity contract with Elia, the Belgian transmission network operator, from 2027.
At the end of December 2023, ENGIE had 1.3 GW of BESS in operation and 3.6 GW secured under development, mainly in the United States, Chile, Australia, Belgium and UK, in line with the objective to reach 10 GW of batteries installed by 2030.
Energy Solutions
Energy Solutions has achieved major wins in District Heating and Cooling (DHC). Backlog in French concessions stood at €21.3 billion in 2023, compared to €19.8 billion last year.
In line with ENGIE's objective of accelerating the transition to a carbon-neutral economy through environmentally friendly solutions, the Group was awarded several decarbonization contracts during the year as part of the on-site production activity.
The Group’s ambition is to produce 20 TWh of Green Distributed Heat, Cooling and Power by 2030 for its DHC and onsite production activities.
Disciplined capital allocation
In 2023, gross Capex amounted to €10.6 billion. Growth Capex came to €8.1 billion, of which 83% in Renewables, Energy Solutions and FlexGen, in line with ENGIE’s strategic roadmap.
Performance plan
Performance plan results contributed €178 million in 2023, with operational excellence across GBUs and improvement of loss-making entities partly offset by an increase in support function costs driven by a highly inflationary context. The Group reached €687 million in the cumulated performance plan between 2021 and 2023, above the €600 million target.
1.5 Belgian nuclear agreement
On December 13, 2023, ENGIE and the Belgian government signed the final agreements(1)for related to the 10-year extension of the Tihange 3 and Doel 4 nuclear reactors as well as all obligations related to nuclear waste. These transaction documents endorse the key principles of the framework agreement signed on July 21, 2023. It allows a balanced sharing of risks associated with the extended operation of the two nuclear units and eliminates uncertainties for the ENGIE Group related to the evolution of nuclear waste liabilities.
(1) Subject to the approval by the European Commission under state aid and the adoption of legislative amendments relating to the Belgian nuclear legal and regulatory framework.
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11 1.6 Update on European proposals for windfall taxes
In December 2023, the French government extended the inframarginal rent cap until 31 December 2024.
The Finance Bill for 2024 provides for a rent cap applicable over a period of twelve months, from 1 January 2024 until 31 December 2024. The cap ranges from €42/MWh to €183/MWh depending on the power production technology. The excess revenue is subject to a tax rate of 50%. ENGIE is mainly impacted through the drawing rights on two EDF nuclear power plants (Chooz B and Tricastin, 1.2 GW, 9 TWh of annual output at an availability rate of 85%) subject to a €94/MWh cap and the gas power plants (1.4 GW capacity) subject to a €42/MWh cap on the clean spark spread.
1.7 Progress on key ESG targets
In 2023, greenhouse gas (GHG) emissions from energy production amounted to 52 million tons, down 54% from 2017.
This represents 78% of the reduction target to 43 million tons to 2030 compared to 2017. In addition to the structural levers of decarbonisation, this better-than-expected performance is also the result of a lower utilisation rate of the combined cycle gas plants in Europe under the combined effect of mild temperatures and the normalisation of market conditions.
The share of renewables in ENGIE's total power generation capacity increased from 38% at the end of 2022 to 41% at the end of 2023, mainly thanks to the addition of 3.9 GW of renewable capacity during the year.
Concerning gender diversity target, ENGIE had 31% women in management positions at the end of 2023, another increase compared to the previous year. The Group continues to implement action plans to achieve the objective of managerial parity of 40% to 60% between women and men.
Finally, Moody's has assessed the Group's transition plan and given an overall rating of NZ-2, with an ambition aligned with a 1.5°C trajectory and a "solid" level on the implementation of objectives.
1.8 Health & Safety
In 2023, ENGIE completed a crucial turning point through the implementation of a global transformation plan, ENGIE One Safety, aimed at the long-term elimination of serious and fatal accidents. This plan strengthens our governance and oversight, as well as reinforces an ambitious engagement and communications program. Despite the roll-out of the transformation plan, six individuals lost their lives while working for or on behalf of the Group. Achieving the zero-fatality goal will be at the heart of priority in 2024. In addition, the Group continued to improve the prevention of lost-time accidents, as the frequency rate of these accidents fell from 2.0 at the end of 2022 to 1.8 at the end of 2023.
1.9 Full year 2023 financial review
1.9.3. Revenue
Revenue at €82.6 billion was down 12.0% on a gross basis and down 11.4% on an organic basis.
Contributive revenue, after elimination of intercompany operations, by activity:
In millions of euros Dec.31, 2023 Dec. 31, 2022
% change
(reported
basis)
% change
(organic
basis)
Renewables 5,512 6,216 -11.3% -13.0%
Networks 6,873 6,961 -1.3% +0.1%
Energy Solutions 11,033 11,441 -3.6% -2.8%
FlexGen 5,264 7,126 -26.1% -24.5%
Retail 16,443 16,810 -2.2% -1.6%
Others 37,322 45,277 -17.6% -17.0%
of which GEMS 37,221 45,137 -17.5% -16.9%
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12 TOTAL REVENUES (excluding Nuclear) 82,447 93,830 +12.1% -11.5% Nuclear 118 35 +237.6% +237.6%
TOTAL REVENUES 82,565 93,865 -12.0% -11.4%
Revenue for Renewables amounted to €5,512 million, -11.3% on a gross basis and -13.0% on an organic basis.
Organically, revenue decreased mainly in Europe notably in France due to lower spot power prices compared to last year.
Revenue for Networks amounted to €6,873 million, -1.3% on a gross basis and +0.1% on an organic basis. Gross decrease included positive foreign exchange effects mainly in Latin America and scope out effects in Argentina.
Organically, revenue increased driven by auctions of capacities for gas transport, favourable market for storage activities in Germany and in the UK and full commissioning of Novo Estado power transmission lines in Brazil partly offset by lower distributed volumes in French distribution.
Revenue for Energy Solutions amounted to €11,033 million, -3.6% on a gross basis and -2.8% on an organic basis. The gross decrease included scope out effect in France. Organically, decrease of commodity prices impacted negatively revenues mainly in France.
Revenue for FlexGen amounted to €5,264 million, -26.1% on a gross basis and -24.5% on an organic basis. Impact from foreign exchange amounts to €-98 million, mainly in Pakistan and Chile. The organic change is largely explained by Europe, mainly due to lower ancillaries and lower spreads in a normalizing market. In Latin America, revenue increased due to indexation of PPA contracts in Chile and higher generation and prices in Peru.
Revenue for Retail amounted to €16,443 million, -2.2% on a gross basis and -1.6% on an organic basis. Impact from foreign exchange amounts to €-93 million, mainly in Australia. Organically, the decrease was mainly driven by lower gas and power volumes due to sobriety and decrease of gas portfolio, partially offset by growth of power contracts and a higher average price of the portfolio.
Revenue for Others amounted to €37,332 million. The decrease compared to last year was mainly driven by GEMS, essentially impacted by a negative net impact of commodity prices and lower delivered volumes.
Nuclear reported almost no external revenue post-elimination of intercompany operations.
1.9.4. EBITDA
EBITDA (ex. Nuclear) at €13.7 billion, was up 12.5% on a gross basis and up 12.7% on an organic basis.
1.9.5. EBIT
EBIT (ex. Nuclear) at €9.5 billion was up 18.2% on a gross basis and up 18.3% on an organic basis. • Foreign exchange: a net effect of €-26 million mainly driven by the depreciation of the US dollar and the UK pound sterling partly offset by the appreciation of the Brazilian real and the Australian dollar. • Scope: net effect of €+31 million
• French temperatures: compared to the average, the temperature effect was a negative €182 million, generating a positive year-on-year variation of €7 million compared to FY 2022 across Networks, Retail and GEMS. 744 of 1021
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13 EBIT contribution by activity: growth mainly driven by GEMS, Renewables and Retail In millions of euros Dec.31, 2023 Dec. 31, 2022
% change
(reported
basis)
% change
(organic
basis)
o/w temp. effect
(France)
vs. 2021
Renewables 2,005 1,627 +23.2% +19.5%
Networks 2,265 2,371 -4.5% -4.5% 10
Energy Solutions 386 523 -26.2% -26.2%
FlexGen 1,513 1,768 -14.4% -11.8%
Retail 569 (6) - - 8
Others 2,741 1,736 +57.9% +57.7% 2
of which GEMS 3,551 2,618 +35.7% +35.6% 2
TOTAL EBIT (excluding Nuclear) 9,479 8,019 +18.2% +18.3% 20 Nuclear 605 1,026 -41.0% -41.0%
TOTAL EBIT 10,084 9,045 +11.5% +11.5% 20
Activity/geography matrix
In millions of euros France
Rest of
Europe
Latin
America
USA &
Canada
Middle East,
Asia & Africa Others Dec. 31, 2023
Renewables 574 282 925 216 34 (27) 2,005
Networks 1,415 64 800 (5) ‐ (9) 2,265
Energy Solutions 343 190 (1) (142) 24 (27) 386
FlexGen ‐ 891 202 35 419 (34) 1,513
Retail 380 145 ‐ ‐ 64 (20) 569
Others 32 1 1 (9) ‐ 2,716 2,741
Of which GEMS 32 ‐ ‐ ‐ ‐ 3,519 3,551
TOTAL EBIT (excluding Nuclear) 2,744 1,573 1,927 96 541 2,599 9,479 Nuclear ‐ 605 ‐ ‐ ‐ ‐ 605
TOTAL EBIT 2,744 2,178 1,927 96 541 2,599 10,084
In millions of euros France
Rest of
Europe
Latin
America
USA &
Canada
Middle East,
Asia & Africa Others Dec. 31, 2022
Renewables 368 318 796 172 9 (36) 1,627
Networks 1,700 24 658 (3) ‐ (8) 2,371
Energy Solutions 311 148 (5) 23 58 (11) 523
FlexGen ‐ 1,278 50 44 417 (22) 1,768
Retail (164) 115 6 ‐ 49 (12) (6)
Others (1) (16) ‐ (11) ‐ 1,763 1,736
Of which GEMS ‐ ‐ ‐ ‐ ‐ 2,618 2,618
TOTAL EBIT (excluding Nuclear) 2,215 1,867 1,506 226 532 1,674 8,019 Nuclear ‐ 1,026 ‐ ‐ ‐ ‐ 1,026
TOTAL EBIT 2,215 2,893 1,506 226 532 1,674 9,045
1.9.5.1. Renewables: strong growth mainly driven by contribution of new capacity commissioned as well as higher volumes and prices in Europe In millions of euros Dec.31, 2023 Dec. 31, 2022
% change
(reported
basis)
% change
(organic
basis)
EBIT 2,005 1,627 +23.2% +19.5%
Total CAPEX 4,130 3,333 +23.9%
CNR achieved prices (€/MWh) (1) 100 60 66.7%
DBSO Margins (EBIT level) 19 102 -81.3%
Operational KPIs
Capacity additions (GW at 100%) 3.9 3.8
Hydro volumes France (TWh at 100%) 14.6 12.8 1.8
(1) Before hydro tax on CNR.
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14 Renewables reported 19.5% organic EBIT growth, driven by the contribution of new capacity commissioned (€+167 million) mainly in the US, Europe and Latin America and by a positive volume effect (€+112 million) due to higher hydro volumes in France and Portugal. EBIT also benefitted from a positive price effect (€+75 million) with higher captured prices mainly for French hydro including the reversal of 2022 buybacks, partly offset by the increase in hydro taxes in France. These positive effects largely offset lower DBSO margins in 2023 (€-83 million).
1.9.5.2. Networks: lower distributed volumes and higher energy costs in France, growth in international activities
In millions of euros Dec.31, 2023 Dec. 31, 2022
% change
(reported
basis)
% change
(organic
basis)
EBITDA 4,151 4,212 -1.5% -1.3%
EBIT 2,265 2,371 -4.5% -4.5%
Total CAPEX 2,173 2,321 +6.4%
Operational KPIs
Normative temp. effect (EBIT - France) (129) (139)(1) 10 Smart meters (m) 11.3 10.9 0.4
(1) Considering ~8€/MWh vs ~7€/MWh used in FY2022 publication.
Networks EBIT was down 4.5% on an organic basis due to lower distributed volumes in France mainly related to energy sobriety as well as higher energy and staff costs driven by inflation. Part of this impact will be mitigated during the forthcoming regulatory period. These effects were partly offset by tariff increase in France, Germany and Romania, an additional contribution from capacity subscribed for gas transit between France and Germany as well as a favourable environment in storage activities mainly in the UK and Germany. Outside Europe, EBIT was up 22% due to full commissioning of Novo Estado power transmission lines in Brazil and good performance mainly from TAG.
1.9.5.3. Energy Solutions: impacted by one-offs, partly offset by better performance in other activities
In millions of euros Dec.31, 2023 Dec. 31, 2022
% change
(reported
basis)
% change
(organic
basis)
Revenues 11,033 11,441 -3.6% -2.8%
EBIT 386 523 -26.2% -26.2%
Total CAPEX 1,102 864 +27.5%
Operational KPIs
Distrib. Infra installed cap. (GW) 25.3 25 +0.4%
EBIT margin (excluding one-off) 5.2% 4.6% +63 pb
EBIT margin 3.5% 4.6% -107 pb
Backlog - French concessions (bn€) 21.3 19.8 1.5
Energy Solutions EBIT was down 26.2% on an organic basis. EBIT decreased mainly due to two one-offs, cost overruns in the construction of two cogeneration plants in the US (€150 million) and the recognition of a deferred tax liability on Tabreed (€38 million) following the introduction of a corporate income tax in the UAE. Excluding these one-offs, Energy Solutions EBIT was up 10% organically. For local energy networks and on-site energy production, this was driven by improved operational performance, higher contributions from cogeneration units in France and contribution from new commissioning. These elements were partly offset by negative impacts of strikes in France in the first half of 2023 and lower DBSO margins in US solar linked to a change in business model towards full consolidation. For energy performance management activities, EBIT benefitted from contract optimization and increased selectivity in business development. 746 of 1021
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15 1.9.5.4. FlexGen: market normalization in Europe partly offset by positive comparison impacts and improvement in Chile
In millions of euros Dec.31, 2023 Dec. 31, 2022
% change
(reported
basis)
% change
(organic
basis)
EBITDA 1,929 2,235 -13.7% -11.2%
EBIT 1,513 1,768 -14.4% -11.8%
Operational KPIs
Average captured CSS Europe (€/MWh) 37.0 28.0 +30.0%
Capacity (GW at 100%) 59.0 59.5 (0.5)
FlexGen EBIT was down 11.8% on an organic basis. This fall was mainly driven by price effects (€-377 million) on the back of lower utilization of the assets in Europe following market normalization, partly offset by improvement in Chile (reduction of short positions and lower sourcing prices). EBIT was also weighed by a lower contribution from ancillary services in Europe after very high levels of earnings in 2022. On the positive side, EBIT benefitted from two favourable comparison impacts, as the Group recognised an extraordinary tax in Italy in the first half of 2022 and was also impacted by the cost of unplanned outages on French gas assets last year.
1.9.5.5. Retail: strong performance due to higher margins and portfolio optimization In millions of euros Dec.31, 2023 Dec. 31, 2022
% change
(reported
basis)
% change
(organic
basis)
EBITDA 821 259
EBIT 569 (6)
Normative temp. effect (EBIT - France) (45) (53) 8
Retail EBIT amounted to €569 million in 2023 compared to €(6) million in 2022. Organically, the EBIT increase was mainly driven by price effects due to portfolio management optimization resulting in higher margins as well as timing effects in sourcing. These positive factors were partly offset by mild winter and customer sobriety leading to long positions sold at low prices in 2023 versus long positions sold at high prices in 2022.
1.9.5.6. Others: significant contribution from GEMS
GEMS EBIT amounted to €3,551 million, up €933 million year-on-year, driven by the H1 2023 effects:
• the negative impact related to Gazprom contracts considering the risk of physical gas disruption in • H1 2022, which did not repeat in 2023,
• the strong performance of energy management activities in Europe, still benefiting from good market conditions, albeit less favorable than in 2022,
• the gradual normalization of market conditions, leading to continuous reversal of market reserves, • the good performance of the B2B business, in a market environment that allows full valuation of the cost of risk, • the continued effect of deals signed in 2022 at good conditions which materialize at delivery date.
In the second half, GEMS’ contribution decreased significantly compared to last year, as expected, due to a very elevated basis of comparison, the reduction of volumes and margins since the summer, positive timing effects in the first half that reversed in the second half, as well as the contribution from high-margin transactions locked in during 2022 which materialize at delivery date that have been smoothed over time. Excluding timing effects and variations in technical reserves, GEMS’ operational performance in the second semester remains at a significantly higher level than in the years preceding the crisis.
747 of 1021
MANAGEMENT REPORT
1 ENGIE 2023 RESULTS
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
16 1.9.5.7. Nuclear: negatively impacted by shutdowns and higher taxes, partly offset by higher captured prices and increased availability
En millions d'+euros Dec.31, 2023 Dec. 31, 2022
% change
(reported
basis)
% change
(organic
basis)
EBITDA 1,285 1,510 -14.9% -14.9%
EBIT 605 1,026 -41.0% -41.0%
Total Capex 174 229 -24.0%
Operational KPIs
Output (BE + FR, @ share, TWh) 32.0 42.1 -24.0%
Availability (Belgium at 100%) +88.8% +83.6% +520 pb
Nuclear EBIT decreased 41.0% organically, driven by the phase-out of the reactors Doel 3 in September 2022 and Tihange 2 in February 2023 (€-538 million), the nuclear inframarginal tax and Belgian nuclear taxes (€-333 million) as well as higher D&A following the increase of the dismantling assets resulting from the 2022 CPN triennial provision review.
These negative effects were partly offset by a positive volume effect (€+425 million) mainly due to higher availability for Belgian assets at 88.8% and higher captured prices (€+363 million).
1.9.6. Comparable basis organic growth analysis
In millions of euros Dec.31, 2023 Dec. 31, 2022
% change
(reported/organic
basis)
Revenues 82,565 93,865 -12.0%
Scope effect (220) (399) ‐
Exchange rate effect ‐ (491) ‐
Comparable data 82,345 92,977 -11.4%
In millions of euros Dec.31, 2023 Dec. 31, 2022
% change
(reported/organic
basis)
EBITDA 15,017 13,713 +9.5%
Scope effect (96) (65) ‐
Exchange rate effect ‐ (43) ‐
Comparable data 14,922 13,606 +9.7%
In millions of euros Dec.31, 2023 Dec. 31, 2022
% change
(reported/organic
basis)
EBIT 10,084 9,045 +11.5%
Scope effect (76) (45) ‐
Exchange rate effect ‐ (26) ‐
Comparable data 10,008 8,974 +11.5%
The calculation of organic growth aims to present comparable data both in terms of the exchange rates used to convert the financial statements of foreign companies and in terms of contributing entities (consolidation method and contribution in terms of comparable number of months). Organic growth in percentage terms represents the ratio between the data for the current year (N) and the previous year (N-1) restated as follows:
• the N-1 data is corrected by removing the contributions of entities transferred during the N-1 period or prorata temporis for the number of months after the transfer in N;
• the N-1 data is converted at the exchange rate for the period N; the N data is corrected with the N acquisition data or prorata temporis for the number of months prior to the N-1 acquisition.
748 of 1021
MANAGEMENT REPORT
2 OTHER INCOME STATEMENT ITEMS
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
17 2 OTHER INCOME STATEMENT ITEMS
The reconciliation between EBIT and Net income/(loss) is presented below:
In millions of euros Dec. 31, 2023 Dec. 31, 2022
% change
(reported
basis)
EBIT 10,084 9,045 +11,5%
(+) Mark-to-Market on commodity contracts other than trading instruments 2,430 (3,661) (+) Non-recurring share in net income of equity method entities (22) (17) Current operating income including operating MtM and share in net income of equity method entities 12,493 5,367 +132.7%
Impairment losses (1,318) (2,774)
Restructuring costs (47) (230)
Changes in scope of consolidation (85) 91
Other non-recurring items (4,945) (1,328)
Income/(loss) from operating activities 6,098 1,127 +441.3% Net financial income/(loss) (2,163) (3,003)
Income tax benefit/(expense) (1,031) 83
NET INCOME/(LOSS) 2,903 390 +644.9%
Net recurring income/(loss) relating to continuing operations, Group share 5,366 5,223 Net recurring income/(loss) Group share per share 2.18 2.24 Net income/(loss) Group share 2,208 216
Non-controlling interests 695 173
The reconciliation between Net recurring income/(loss) Group share and Net income/(loss) Group share is presented below:
In millions of euros Dec. 31, 2023 Dec. 31, 2022
Net recurring income/(loss) relating to continuing operations, Group share 5,366 5,223 Impairment & Others (5,456) (1,494)
Restructuring costs (47) (230)
Changes in scope of consolidation (85) 91
Mark-to-Market on commodity contracts other than trading instruments 2,430 (3,661) Net recurring income/(loss) relating to discontinued operations, Group share ‐ 287 Net income/(loss) Group share 2,208 216
Income from operating activities amounted to €6,098 million, representing a strong increase compared to 2022, mainly due to the change in unrealized gains and losses on commodity financial instruments not qualified as hedges, lower impairment losses and EBIT growth, partly offset by the impact of the revision of nuclear provisions.
Income from operating activities was affected by:
• net impairment losses of €1,318 million (compared with €2,774 million in 2022), mainly relating to renewable energy production assets in North America and assets affected by the Group's exit from coal (see Note 9.1); • restructuring costs of €47 million (compared with €230 million in 2022) (see Note 9.2); • negative scope effects of €85 million (compared with a positive €91 million in 2022) (see Note 9.3); • other non-recurring items amounting to a negative €4,945 million (compared with a negative €1,328 million in 2022), mainly comprising the effects of the revision of nuclear provisions to take into account the agreement signed with the Belgian government on June 29, 2023, which became binding following the signature of supplements to the initial agreement on July 21, 2023 and the implementation of which was set out in the transaction documents signed on December 13, 2023 (see Note 9.4).
The net financial loss amounted to €2,163 million in 2023, compared with €3,003 million in 2022 (see Note 10), mainly due to the rise in the cost of debt.
Adjusted for non-recurring items, the net financial loss amounted to €1,975 million in 2023, compared with €1,819 million in 2022. This €156 million deterioration is due to the €96 million increase in other financial expenses (notably the increase in the unwinding adjustment) and the €60 million rise in the cost of net debt. 749 of 1021
MANAGEMENT REPORT
2 OTHER INCOME STATEMENT ITEMS
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
18 Income tax for 2023 amounted to a benefit of €1,031 million (compared with a benefit of €83 million in 2022).
Adjusted for these non-recurring items, the recurring effective tax rate was 27.1% at December 31, 2023 compared with
22.6% at December 31, 2022, mainly due to:
• the change in the tax situation in certain countries that only partially recognize, in 2023 and/or 2022, their deferred tax assets (notably Belgium, Italy, Luxembourg, Germany and the Netherlands) – approximately +8.3 points; • the unfavorable impact in 2022 of the non-deductibility of the one-off tax contribution, recognized as an operating expense, and the temporary solidarity contribution voted in Italy – approximately -3.3 points.
Net recurring income, Group share relating to continuing operations amounted to €5,366 million compared with €5,223 million in 2022. This increase was mainly driven by the growth in EBIT, partly offset by the increase in the tax expense.
Net income, Group share amounted to €2,208 million, up sharply compared to 2022, mainly due to the change in unrealized gains and losses on commodity financial instruments not qualified as hedges, partially offset by the impact of the revision of nuclear provisions.
Net income attributable to non-controlling interests amounted to €695 million, an improvement on the 2022 figure (up €521 million), notably in Renewables in the United States. 750 of 1021
MANAGEMENT REPORT
3 CHANGES IN NET FINANCIAL DEBT
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
19 3 CHANGES IN NET FINANCIAL DEBT
Net financial debt stood at €29.5 billion, up €5.4 billion compared to December 31, 2022.
This increase was mainly driven by:
• capital expenditure over the period of €10.6 billion; • dividends paid to ENGIE SA shareholders and to non-controlling interests of €4.1 billion; • Belgian nuclear phase-out funding and expenses(1) of €3.4 billion; • other elements of €0.7 billion.
These elements were partly offset by:
• Cash Flow From Operations of €13.1 billion;
• disposals of €0.3 billion.
Changes in net financial debt break down as follows:
In billions of euros
(1) Capital expenditure net of DBSO and tax equity proceeds. (2) Including scope effects relating to disposals and acquisitions. (1) Synatom funding previously reported in gross Capex and waste/dismantling expenses previously reported in CFFO. 751 of 1021
MANAGEMENT REPORT
3 CHANGES IN NET FINANCIAL DEBT
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
20 Economic net debt stood at €46.5 billion, up €7.7 billion compared to December 31, 2022, mostly due to the increase in Asset Retirement Obligation provisions (+€5.6 billion, mainly the increase of nuclear provisions following the agreement reached with the Belgian State) and higher financial net debt (+€5.4 billion), partly offset by the change in nuclear provision assets related to additional funding (-€3.4 billion).
Changes in economic net debt break down as follows:
In billions of euros
(1) Increase in nuclear provisions following the agreement signed with the Belgian government The net financial debt to EBITDA ratio stood at 2.0x, up 0.2x compared to December 31,2022.
The average cost of gross debt was 4.31%.
In millions of euros Dec 31, 2023 Dec 31, 2022
Net financial debt 29,493 24,054
EBITDA 15,017 13,713
NET DEBT/EBITDA RATIO 1.96 1.75
The economic net debt to EBITDA ratio stood at 3.1x, up 0.3x compared to December 31, 2022, and in line with the target ratio of below or equal to 4.0x.
In millions of euros Dec 31, 2023 Dec 31, 2022
Economic net debt 46,517 38,808
EBITDA 15,017 13,713
ECONOMIC NET DEBT/EBITDA RATIO 3.10 2.83
3.1 Cash flow from operations (CFFO)
Cash Flow From Operations (CFFO) amounted to €13.1 billion, up €5.1 billion compared to 2022. This increase was mainly supported by an improvement in change in Working Capital Requirements (€+2.8 billion). 752 of 1021
MANAGEMENT REPORT
3 CHANGES IN NET FINANCIAL DEBT
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
21 Working Capital Requirements were positive at €0.4 billion, with a positive year-on-year variation of €2.8 billion mainly driven by price effects due to gas withdrawal at higher prices (€+3.9 billion), unbilled energy volumes (€+3.5 billion), margin calls (€+1.3 billion) and the positive timing effect on tariff shields (€+0.9 billion). These positive effects were partly offset by the impact of reversal of market reserves at GEMS (€-2.2 billion) which is neutral on CFFO, net receivables (€-1.9 billion) and nuclear impacts (€-2.1 billion) of which mainly taxes.
3.2 Liquidity
Liquidity stood at €23.6 billion at December 3, 2023, including €17.0 billion of cash(1).
3.3 Capital expenditure (CAPEX)
Total Capex amounted to €10.6 billion, including growth CAPEX of €8.1 billion.
Capital expenditure (CAPEX) by activity
In billions of euros
Growth capital expenditure amounted to €8.1 billion, breaking down as follows by activity:
(1) Net of disposals under DBSO operations, excluding Corporat, and tax equity proceeds. (1) Cash and cash equivalents plus liquid debt instruments held for cash investment purposes minus bank overdrafts. 753 of 1021
MANAGEMENT REPORT
3 CHANGES IN NET FINANCIAL DEBT
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
22 The geography/activity matrix for growth capital expenditure is presented below:
In millions of euros France
Rest of
Europe
Latin
America
USA &
Canada
Middle East,
Asia & Africa Others Dec. 31, 2023
Renewables 323 481 1,103 994 1,059 7 3,966
Networks 501 163 174 ‐ ‐ ‐ 839
Energy Solutions 477 155 4 136 79 47 897
FlexGen ‐ 341 14 1,492 (8) 5 1,843
Retail 53 45 ‐ ‐ 8 54 160
Nuclear ‐ ‐ 19 ‐ ‐ ‐ 19
Others ‐ 8 ‐ 1 6 352 368
Of which GEMS ‐ ‐ ‐ ‐ ‐ 82 82
TOTAL GROWTH CAPEX 1,354 1,193 1,314 2,622 1,144 464 8,090 In millions of euros France
Rest of
Europe
Latin
America
USA &
Canada
Middle East,
Asia & Africa Others Dec. 31, 2022
Renewables 361 1,094 876 648 214 10 3,202
Networks 669 174 245 ‐ ‐ ‐ 1,087
Energy Solutions 354 122 19 66 75 58 694
FlexGen ‐ 181 9 34 (9) 6 220
Retail 62 42 ‐ ‐ 7 62 173
Nuclear ‐ ‐ ‐ ‐ ‐ ‐ ‐
Others ‐ 4 ‐ ‐ ‐ 103 108
Of which GEMS ‐ ‐ ‐ ‐ ‐ 63 63
TOTAL GROWTH CAPEX 1,445 1,617 1,148 748 287 240 5,484
3.4 Dividends and movements in treasury stock
Dividends paid and movements in treasury stock during the period amounted to €4.1 billion and mainly include ENGIE's dividend payment in April for the 2022 fiscal year for €3.4 billion, and dividends paid by various subsidiaries to their noncontrolling interests in an amount of €0.5 billion.
3.5 Net financial debt at December 31, 2023
Excluding amortized cost but including the impact of foreign currency derivatives, at December 31, 2023 a total of 65% of net financial debt was denominated in euros, 19% in US dollars and 10% in Brazilian real.
Including the impact of financial instruments, 89% of net debt was at fixed rates.
The average maturity of the Group’s net financial debt is 13.2 years.
At December 31, 2023, the Group had total undrawn confirmed credit lines of €12.2 billion.
3.6 Rating
On 23 November 2023, S&P reaffirmed ENGIE SA long-term issuer rating at BBB+ and short-term rating at A-2 with stable outlook.
On 13 July 2023, Moody’s confirmed ENGIE SA long-term issuer rating at Baa1 and short-term rating at P-2 with stable outlook.
On 18 July 2023, Fitch reaffirmed ENGIE SA long-term issuer rating at A- and short-term rating at F1 with stable outlook. 754 of 1021
MANAGEMENT REPORT
4 OTHER ITEMS IN THE STATEMENT OF FINANCIAL POSITION
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
23 4 OTHER ITEMS IN THE STATEMENT OF FINANCIAL
POSITION
In millions of euros Dec. 31, 2023 Dec. 31, 2022 Net change Non-current assets 119,023 131,521 (12,498)
Of which goodwill 12,864 12,854 10
Of which property, plant and equipment and intangible assets, net 66,399 62,853 3,547 Of which derivative instruments 12,764 33,134 (20,370)
Of which investments in equity method entities 9,213 9,279 (66) Current assets 75,617 103,969 (28,352)
Of which trade and other payables 20,092 31,310 (11,218) Of which derivative instruments 8,481 15,252 (6,772)
Of which assets classified as held for sale ‐ 428 (428) Total equity 35,724 39,285 (3,560)
Provisions 32,593 27,027 5,566
Borrowings 47,287 40,591 6,696
Derivative instruments 24,561 51,276 (26,715)
Other liabilities 54,475 77,311 (22,835)
Of which liabilities directly associated with assets classified as held for sale ‐ 371 (371) The carrying amount of property, plant and equipment and intangible assets was €66.4 billion, up €3.5 billion compared with December 31, 2022. This change is mainly due to capital expenditure over the period (positive €8.8 billion), changes in the scope of consolidation (positive €1.9 million), partially offset by depreciation (negative €4.9 billion) and impairment losses recognized over the period (negative €1.2 billion) (see Note 13).
Goodwill amounted to €12.9 billion, stable compared with December 31, 2022 (see Note 13).
Investments in equity method entities increased by €0.1 billion (see Note 4.2).
Total equity amounted to €35.7 billion, a decrease of €3.6 billion compared with December 31, 2022, This decrease stemmed mainly from dividends distributed (negative €3.9 billion), and other comprehensive income (negative €2.6 billion, including a negative €3.1 billion of cash flow hedges on commodities, a negative €0.6 billion of actuarial gains and losses and a positive €0.9 billion of deferred taxes) partially offset by net income for the period (positive €2.9 billion).
Provisions increased by €5.6 billion to €32.6 billion compared with December 31, 2022. This increase is mainly due to the effects of the revision of nuclear provisions to take into account the interim agreement signed with the Belgian government on June 29, 2023, which became binding following the signature of the supplements to the initial agreements on July 21, 2023 and the implementation of which was set out in the transaction documents signed on December 13, 2023 as well as the final opinion of the Commission for Nuclear Provisions (CNP) on July 7, 2023 (see Note 17).
The decrease in derivative instruments is mainly due to the extreme volatility in commodity prices over the period. 755 of 1021
MANAGEMENT REPORT
5 PARENT COMPANY FINANCIAL STATEMENTS
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
24 5 PARENT COMPANY FINANCIAL STATEMENTS
The figures provided below relate to the financial statements of ENGIE SA, prepared in accordance with French GAAP and applicable regulations.
Revenues for ENGIE SA in 2023 totaled €54,149 million, a decrease compared to 2022 (€68,500 million) on the gas market.
The company reported a net operating loss of €987 million in 2023, a sharp deterioration of €2,038 million compared with income of €1,051 million in 2022. The energy margin deteriorated by €1,042 million.
Net financial income amounted to €662 million, down €1,125 million compared to 2022, mainly due to lower dividends received.
Non-recurring items represented income of €578 million in 2023, mainly comprising changes in the value of equity interests (including Electrabel).
The income tax benefit amounted to €247 million, versus an income tax benefit of €321 million in 2022, including a tax consolidation benefit of €233 million.
Net income for the year came in at €500 million.
Shareholders’ equity amounted to €28,376 million compared with €31,118 million at the end of 2022. The €2,742 million decrease was mainly due to the 2022 net income of €500 million, and to the 2022 dividend payment of €3,449 million.
At December 31, 2023, borrowings and debt stood at €47,084 million, and cash and cash equivalents totaled €14,004 million (of which €7,828 million relating to subsidiaries’ current accounts).
Information relating to payment terms
Pursuant to Articles L.441-14 and D.441-6 of the French Commercial Code, companies whose annual financial statements are subject to a statutory audit must publish information regarding supplier and customer payment terms. The purpose is to demonstrate that there is no significant failure to comply with such terms.
Information relating to supplier and customer payment terms mentioned in Articles L.441-10 to L.441-16 of the French Commercial Code
Articles L441-10 to L441-16 : Invoices received,
unpaid and overdue at
the reporting date
Articles L441-10 to L441-16 : Invoices issued, unpaid and overdue at the reporting date
In millions of euros
0 day
(indicative)
1 to
30 days
31 to
60 days
61 to
90 days
91 days
or
more
Total
(1 day
or
more)
0 day
(indicative)
1 to 30
days
31 to
60 days
61 to
90 days
91 days
or
more
Total
(1 day or
more)
(A) By aging category
Number of invoices ‐ 69,321 ‐ 5,900,621
Aggregate invoice amount (incl.
VAT)
‐ 15.7 11.1 0.8 716.7 744.3 ‐ 29.9 26.8 51.5 1,130.4 1,238.6 Percentage of total amount of
purchases (incl. VAT) for the
period
‐ 0.02% 0.02% 0.00% 1.14% 1.18%
Percentage of total revenues
(incl. VAT) for the period
‐ 0.05% 0.04% 0.08% 1.77% 1.94%
(B) Invoices excluded from (A) relating to disputed or unrecognized receivables and payables Number of excluded invoices 501 682
Aggregate amount of excluded
invoices
(66.9) 1.8
(C) Standard payment terms used (contractual or legal terms - Article L. 441-6 or Article L. 443-1 of the French Commercial Code) Payment terms used to
calculate late payments
Contractual payment terms: 14 days
Legal payment terms: 30 days Legal payment terms: 30 days 756 of 1021
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
25 02 CONSOLIDATED
FINANCIAL STATEMENTS
INCOME STATEMENT.......................................................................................................................................................... 26 STATEMENT OF COMPREHENSIVE INCOME............................................................................................................... 27 STATEMENT OF FINANCIAL POSITION........................................................................................................................... 28 STATEMENT OF CHANGES IN EQUITY........................................................................................................................... 30 STATEMENT OF CASH FLOWS......................................................................................................................................... 32 757 of 1021
CONSOLIDATED FINANCIAL STATEMENTS
INCOME STATEMENT
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
26 INCOME STATEMENT
In millions of euros Notes Dec. 31, 2023 Dec. 31, 2022
REVENUES 6.2 & 7 82,565 93,865
Purchases and operating derivatives 8.1 (56,992) (74,535) Personnel costs 8.2 (8,149) (8,078)
Depreciation, amortization and provisions 8.3 (4,911) (5,187) Taxes 8.4 (2,627) (3,380)
Other operating income 1,541 1,624
Current operating income including operating MtM 11,427 4,309 Share in net income of equity method entities 6.2 1,066 1,059 Current operating income including operating MtM and share in net income of equity method entities 12,493 5,367
Impairment losses 9.1 (1,318) (2,774)
Restructuring costs 9.2 (47) (230)
Changes in scope of consolidation 9.3 (85) 91
Other non-recurring items 9.4 (4,945) (1,328)
NET INCOME/(LOSS) FROM OPERATING ACTIVITIES 6,098 1,127 Financial expenses (3,340) (3,700)
Financial income 1,177 697
NET FINANCIAL INCOME/(LOSS) 10 (2,163) (3,003)
Income tax benefit/(expense) 11 (1,031) 83
NET INCOME/(LOSS) RELATING TO CONTINUING OPERATIONS 2,903 (1,793) NET INCOME/(LOSS) RELATING TO DISCONTINUED OPERATIONS (1) ‐ 2,183 NET INCOME/(LOSS) 2,903 390
Net income/(loss) Group share 2,208 216
Of which Net income/(loss) relating to continuing operations, Group share 2,208 (1,965) Of which Net income/(loss) relating to discontinued operations, Group share ‐ 2,182 Non-controlling interests 695 173
Of which Non-controlling interests relating to continuing operations 695 172 Of which Non-controlling interests relating to discontinued operations ‐ 1 BASIC EARNINGS/(LOSS) PER SHARE (EUROS) 12 0.88 0.06
Of which Basic earnings/(loss) relating to continuing operations per share 0.88 (0.84) Of which Basic earnings/(loss) relating to discontinued operations per share ‐ 0.90 DILUTED EARNINGS/(LOSS) PER SHARE (EUROS) 12 0.87 0.06
Of which Diluted earnings/(loss) relating to continuing operations per share 0.87 (0.84) Of which Diluted earnings/(loss) relating to discontinued operations per share ‐ 0.90 (1) Net income from discontinued operations for 2022 corresponds to the share of income from Equans.
NB: The amounts shown in the tables are expressed in millions of euros. In certain cases, rounding may cause non-material discrepancies in the totals.
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CONSOLIDATED FINANCIAL STATEMENTS
STATEMENT OF COMPREHENSIVE INCOME
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
27 STATEMENT OF COMPREHENSIVE INCOME
In millions of euros Notes Dec. 31, 2023 Dec. 31, 2022
NET INCOME/(LOSS) 2,903 390
Debt instruments 14.1 325 (378)
Net investment hedges 15 148 (15)
Cash flow hedges (excl. commodity instruments) 15 (83) 938 Commodity cash flow hedges (1) 15 (3,162) (4,719)
Deferred tax on recyclable or recycled items 765 951
Share of equity method entities in recyclable items, net of tax 36 871 Translation adjustments (343) 848
Recyclable items relating to discontinued operations, net of tax ‐ (118) TOTAL RECYCLABLE ITEMS (2,315) (1,622)
Equity instruments 14.1 120 (685)
Actuarial gains and losses (580) 2,718
Deferred tax on non recyclable items 135 (613)
Share of equity method entities in actuarial gains and losses, net of tax 1 5 Non-recyclable items relating to discontinued operations, net of tax ‐ 48 TOTAL NON-RECYCLABLE ITEMS (324) 1,472
TOTAL RECYCLABLE ITEMS AND NON-RECYCLABLE ITEMS (2,639) (150) TOTAL COMPREHENSIVE INCOME/(LOSS) 264 240
Of which owners of the parent (717) (257)
Of which non-controlling interests 981 497
(1) The fall in commodity market prices during 2023 contributed to significant changes in the fair value of financial instruments, impacting other comprehensive income. In 2023, the hedging of electricity supply activities in France, Belgium and the Netherlands and sales resulting from the production of some of our assets in these same areas qualified as cash flow hedging instruments in accordance with IFRS 9. Unrealized gains and losses on the effective portion of the hedges are now recorded in Other comprehensive income, as are hedges of our gas supply activities in Europe that already qualified, and are recycled to operating income at the same time as the hedged transactions to which they relate.
NB: The amounts shown in the tables are expressed in millions of euros. In certain cases, rounding may cause non-material discrepancies in the totals.
759 of 1021
CONSOLIDATED FINANCIAL STATEMENTS
STATEMENT OF FINANCIAL POSITION
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
28 STATEMENT OF FINANCIAL POSITION
ASSETS
In millions of euros Notes Dec. 31, 2023 Dec. 31, 2022
Non-current assets
Goodwill 13.1 12,864 12,854
Intangible assets, net 13.2 8,449 7,364
Property, plant and equipment, net 13.3 57,950 55,488
Other financial assets 14 14,817 10,599
Derivative instruments 14 12,764 33,134
Assets from contracts with customers 7 1 9
Investments in equity method entities 3 9,213 9,279
Other non-current assets 22 990 766
Deferred tax assets 11 1,974 2,029
TOTAL NON-CURRENT ASSETS 119,023 131,521
Current assets
Other financial assets 14 2,170 2,394
Derivative instruments 14 8,481 15,252
Trade and other receivables, net 7 20,092 31,310
Assets from contracts with customers 7 9,530 12,575
Inventories 22 5,343 8,145
Other current assets 22 13,424 18,294
Cash and cash equivalents 14 16,578 15,570
Assets classified as held for sale 0 ‐ 428
TOTAL CURRENT ASSETS 75,617 103,969
TOTAL ASSETS 194,640 235,490
NB: The amounts shown in the tables are expressed in millions of euros. In certain cases, rounding may cause non-material discrepancies in the totals.
760 of 1021
CONSOLIDATED FINANCIAL STATEMENTS
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
29 EQUITY AND LIABILITIES
In millions of euros Notes Dec. 31, 2023 Dec. 31, 2022
Shareholders' equity 30,057 34,253
Non-controlling interests 2 5,667 5,032
TOTAL EQUITY 16 35,724 39,285
Non-current liabilities
Provisions 17 18,792 24,663
Long-term borrowings 14 37,920 28,083
Derivative instruments 14 16,755 39,417
Other financial liabilities 14 82 90
Liabilities from contracts with customers 7 93 121
Other non-current liabilities 22 3,614 3,646
Deferred tax liabilities 11 5,632 6,408
TOTAL NON-CURRENT LIABILITIES 82,889 102,427
Current liabilities
Provisions 17 13,801 2,365
Short-term borrowings 14 9,367 12,508
Derivative instruments 14 7,806 11,859
Trade and other payables 14 22,976 39,801
Liabilities from contracts with customers 7 3,960 3,292 Other current liabilities 22 18,118 23,583
Liabilities directly associated with assets classified as held for sale 0 ‐ 371 TOTAL CURRENT LIABILITIES 76,027 93,778
TOTAL EQUITY AND LIABILITIES 194,640 235,490
NB: The amounts shown in the tables are expressed in millions of euros. In certain cases, rounding may cause non-material discrepancies in the totals.
761 of 1021
CONSOLIDATED FINANCIAL STATEMENTS
STATEMENT OF CHANGES IN EQUITY
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
30 STATEMENT OF CHANGES IN EQUITY
In millions of euros
Share
capital
Additional
paid-in
capital
Consolidated
reserves
Deeplysubordinated
perpetual
notes
Changes
in fair
value
and
other
Translation
adjustmentsTreasury
stock
Shareholders'
equity
Noncontrolling
interests Total
EQUITY AT DECEMBER 31, 2021 2,435 26,058 5,238 3,767 1,711 (2,017) (199) 36,994 4,986 41,980 Net income/(loss) 216 216 173 390
Other comprehensive income/(loss) 1,311 (2,379) 595 (474) 324 (150)
TOTAL COMPREHENSIVE
INCOME/(LOSS) 1,527 (2,379) 595 (257) 497 240
Share-based payment ‐ 3 45 48 ‐ 48
Dividends paid in cash (1) (394) (1,689) (2,082) (482) (2,565) Purchase/disposal of treasury stock (43) 10 (33) ‐ (33) Operations on deeply-subordinated
perpetual notes (1) (77) (374) (451) (451)
Transactions between owners (1) (2) 154 154 56 210
Transactions with an impact on noncontrolling interests ‐ ‐ (41) (41) Share capital increases and decreases ‐ 19 19
Normative changes (3) (116) (116) (6) (121)
Other changes ‐ (5) ‐ (5) 3 (1)
EQUITY AT DECEMBER 31, 2022 2,435 25,667 5,036 3,393 (668) (1,422) (189) 34,253 5,032 39,285 (1) Transactions of the period are listed in Note 16 “Equity” to the consolidated financial statements for the year ended December 31, 2022.
(2) Mainly relates to the sale of part of the renewable assets portfolio in the United States (see Note 16.2.4 “Other transactions” to the consolidated financial statements for the year ended December 31, 2022). (3) SaaS arrangement (see Note 1.1.2 “Other text” to the consolidated financial statements for the year ended December 31, 2022).
NB: The amounts shown in the tables are expressed in millions of euros. In certain cases, rounding may cause non-material discrepancies in the totals.
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STATEMENT OF CHANGES IN EQUITY
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
31 In millions of euros
Share
capital
Additional
paid-in
capital
Consolidated
reserves
Deeplysubordinated
perpetual
notes
Changes
in fair
value
and
other
Translation
adjustmentsTreasury
stock
Shareholders'
equity
Noncontrolling
interests Total
EQUITY AT DECEMBER 31, 2022 2,435 25,667 5,036 3,393 (668) (1,422) (189) 34,253 5,032 39,285 Net income/(loss) 2,208 2,208 695 2,903
Other comprehensive income/(loss) (307) (2,348) (270) (2,925) 286 (2,639)
TOTAL COMPREHENSIVE
INCOME/(LOSS) 1,901 ‐ (2,348) (270) ‐ (717) 981 264
Share-based payment ‐ ‐ 53 53 ‐ 53
Dividends paid in cash (1) (1,752) (1,675) (3,427) (522) (3,949) Purchase/disposal of treasury stock (69) 12 (57) ‐ (57) Operations on deeply-subordinated
perpetual notes (80) ‐ (80) ‐ (80)
Transactions between owners (2) (99) (99) (68) (168)
Transactions with an impact on noncontrolling interests ‐ ‐ 40 40 Share capital increases and decreases ‐ 201 201
Normative change (5) (5) ‐ (5)
Other changes (3)
‐ 137 ‐ ‐ ‐ 137 4 140
EQUITY AT DECEMBER 31, 2023 2,435 23,916 5,198 3,393 (3,015) (1,693) (177) 30,057 5,667 35,724 (1) Transactions of the period are listed in Note 16 “Equity”. (2) Mainly concerns the acquisition of the minority interest held by Mitsui & Co, Ltd ("Mitsui") in International Power (Australia) Holdings Pty Limited (“IPAH”) (see Note 4 “Main changes in Group structure”). (3) Mainly concerns the resolution of the dispute with the French tax authorities on the withholding tax receivable assigned without recourse by the Group in 2005. This dispute is presented in Note 23 “Legal and anti-trust proceedings”.
NB: The amounts shown in the tables are expressed in millions of euros. In certain cases, rounding may cause non-material discrepancies in the totals.
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CONSOLIDATED FINANCIAL STATEMENTS
STATEMENT OF CASH FLOWS
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
32 STATEMENT OF CASH FLOWS
In millions of euros Notes
Dec. 31,
2023
Dec. 31,
2022
NET INCOME/(LOSS) 2,903 390
- Net income/(loss) relating to discontinued operations ‐ 2,183 NET INCOME/(LOSS) RELATING TO CONTINUING OPERATIONS 2,903 (1,793) - Share in net income/(loss) of equity method entities (1,066) (1,059) + Dividends received from equity method entities 1,031 713 - Net depreciation, amortization, impairment and provisions 11,020 8,057 - Impact of changes in scope of consolidation and other non-recurring items 136 74 - Mark-to-market on commodity contracts other than trading instruments (2,430) 3,661 - Other items with no cash impact (382) (157)
- Income tax expense 11 1,031 (83)
- Net financial income/(loss) 10 2,163 3,003
Cash generated from operations before income tax and working capital requirements 14,407 12,415 + Tax paid (1,687) (1,504)
Change in working capital requirements 22.1 397 (2,424) CASH FLOW FROM OPERATING ACTIVITIES RELATING TO CONTINUING OPERATIONS 13,117 8,488 CASH FLOW FROM OPERATING ACTIVITIES RELATING TO DISCONTINUED OPERATIONS ‐ 98 CASH FLOW FROM OPERATING ACTIVITIES 13,117 8,586
Acquisitions of property, plant and equipment and intangible assets 13.2 & 13.3 (7,328) (6,379) Acquisitions of controlling interests in entities, net of cash and cash equivalents acquired 4 & 14 (1,392) (289) Acquisitions of investments in equity method entities and joint operations 4 & 14 (237) (407) Acquisitions of equity and debt instruments 14 (1,675) 175 Disposals of property, plant and equipment, and intangible assets 13.2 & 13.3 122 173 Loss of controlling interests in entities, net of cash and cash equivalents sold 4 & 14 27 6,728 Disposals of investments in equity method entities and joint operations 4 & 14 131 1,461 Disposals of equity and debt instruments 14 (8) 268
Interest received on financial assets 118 (37)
Dividends received on equity instruments 9 18
Change in loans and receivables originated by the Group and other 5.6 (1,585) (2,877) CASH FLOW FROM (USED IN) INVESTING ACTIVITIES RELATING TO CONTINUING OPERATIONS (11,818) (1,167) CASH FLOW FROM (USED IN) INVESTING ACTIVITIES RELATING TO DISCONTINUED OPERATIONS ‐ (3,123) CASH FLOW FROM (USED IN) INVESTING ACTIVITIES (11,818) (4,290) Dividends paid (1) (4,067) (2,665)
Repayment of borrowings and debt (6,671) (10,972)
Change in financial assets held for investment and financing purposes 15 188 Interest paid (1,058) (822)
Interest received on cash and cash equivalents 569 194
Cash flow on derivatives qualifying as net investment hedges and compensation payments on derivatives and on early buyback of borrowings 134 (216)
Increase in borrowings 10,716 8,669
Increase/decrease in capital 200 (259)
Purchase and/or sale of treasury stock (57) (115)
CASH FLOW FROM (USED IN) FINANCING ACTIVITIES RELATING TO CONTINUING OPERATIONS (218) (5,997)
CASH FLOW FROM (USED IN) FINANCING ACTIVITIES RELATING TO DISCONTINUED
OPERATIONS
‐ 3,019
CASH FLOW FROM (USED IN) FINANCING ACTIVITIES (218) (2,979) Effects of changes in exchange rates and other relating to continuing operations (73) 356 Effects of changes in exchange rates and other relating to discontinued operations ‐ 7 Effects of changes in exchange rates and other (73) 363 TOTAL CASH FLOW FOR THE PERIOD 1,008 1,680
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 15,570 13,890 CASH AND CASH EQUIVALENTS AT END OF PERIOD 16,578 15,570 (1) The line “Dividends paid” includes the coupons paid to owners of deeply-subordinated perpetual notes (see Note 16 “Equity”).
NB: The amounts shown in the tables are expressed in millions of euros. In certain cases, rounding may cause non-material discrepancies in the totals.
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33 765 of 1021
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34 03 NOTES TO THE
CONSOLIDATED FINANCIAL
STATEMENTS
Note 1 ACCOUNTING FRAMEWORK AND BASIS FOR PREPARING THE CONSOLIDATED FINANCIAL STATEMENTS ......................................................................................................................................................... 35 Note 2 MAIN SUBSIDIARIES AT DECEMBER 31, 2023................................................................................................ 40 Note 3 INVESTMENTS IN EQUITY METHOD ENTITIES.............................................................................................. 46 Note 4 MAIN CHANGES IN GROUP STRUCTURE....................................................................................................... 54 Note 5 FINANCIAL INDICATORS USED IN FINANCIAL COMMUNICATION............................................................ 56 Note 6 SEGMENT INFORMATION.................................................................................................................................... 61 Note 7 REVENUES.............................................................................................................................................................. 65 Note 8 OPERATING EXPENSES...................................................................................................................................... 69 Note 9 OTHER ITEMS OF NET INCOME/(LOSS) FROM OPERATING ACTIVITIES............................................... 71 Note 10 NET FINANCIAL INCOME/(LOSS) ....................................................................................................................... 74 Note 11 INCOME TAX EXPENSE........................................................................................................................................ 75 Note 12 EARNINGS PER SHARE ....................................................................................................................................... 79 Note 13 FIXED ASSETS........................................................................................................................................................ 80 Note 14 FINANCIAL INSTRUMENTS.................................................................................................................................. 94 Note 15 RISKS ARISING FROM FINANCIAL INSTRUMENTS.....................................................................................111 Note 16 EQUITY ...................................................................................................................................................................131 Note 17 PROVISIONS .........................................................................................................................................................134 Note 18 POST-EMPLOYMENT BENEFITS AND OTHER LONG-TERM BENEFITS...............................................143 Note 19 SHARE-BASED PAYMENTS...............................................................................................................................152 Note 20 RELATED PARTY TRANSACTIONS.................................................................................................................153 Note 21 EXECUTIVE COMPENSATION ..........................................................................................................................155 Note 22 WORKING CAPITAL REQUIREMENTS, INVENTORIES, OTHER ASSETS AND OTHER LIABILITIES156 Note 23 LEGAL AND ANTI-TRUST PROCEEDINGS.....................................................................................................158 Note 24 SUBSEQUENT EVENTS......................................................................................................................................165 Note 25 FEES PAID TO THE STATUTORY AUDITORS AND TO MEMBERS OF THEIR NETWORKS ..............166 Note 26 INFORMATION REGARDING LUXEMBOURG AND DUTCH COMPANIES EXEMPTED FROM THE REQUIREMENTS TO PUBLISH ANNUAL FINANCIAL STATEMENTS.......................................................167 766 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 ACCOUNTING FRAMEWORK AND BASIS FOR PREPARING THE CONSOLIDATED FINANCIAL STATEMENTS ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
35 ENGIE SA, the parent company of the Group, is a French société anonyme with a Board of Directors that is subject to the provisions of Book II of the French Commercial Code (Code du commerce), as well as to all other provisions of French law applicable to French commercial companies. It was incorporated on November 20, 2004 for a period of 99 years.
It is governed by current and future laws and by regulations applicable to sociétés anonymes and its bylaws.
The Group is headquartered at 1 place Samuel de Champlain, 92400 Courbevoie (France).
ENGIE shares are listed on the Paris, Brussels and Luxembourg stock exchanges.
On February 21, 2024, the Group's Board of Directors approved and authorized for issue the consolidated financial statements of the Group for the year ended December 31, 2023.
NOTE 1 ACCOUNTING FRAMEWORK AND BASIS FOR
PREPARING THE CONSOLIDATED FINANCIAL
STATEMENTS
1.1 Accounting standards
Pursuant to European Regulation (EU) 2019/980 dated March 14, 2019, financial information concerning the assets, liabilities, financial position and profit and loss of ENGIE has been provided for the last two reporting periods (ended December 31, 2022 and 2023). This information was prepared in accordance with European Regulation (EC) 1606/2002 “on the application of international accounting standards” dated July 19, 2002. The Group's consolidated financial statements for the year ended December 31, 2023 have been prepared in accordance with IFRS Standards as published by the International Accounting Standards Board and endorsed by the European Union (1).
The accounting standards applied in the consolidated financial statements for the year ended December 31, 2023 are consistent with the policies used to prepare the consolidated financial statements for the year ended December 31, 2022, except for those described below.
1.1.1 IFRS Standards, amendments or IFRIC Interpretations applicable as from 2023 • IFRS 17 - Insurance Contracts (including amendments). • Amendments to IAS 1 – Presentation of Financial Statements and the Materiality Practice Statement: Disclosure of Accounting Policies.
• Amendments to IAS 8 – Accounting Policies, Changes in Accounting Estimates and Errors: Definition of Accounting Estimates.
• Amendments to IAS 12 – Income Taxes: Deferred Tax related to Assets and Liabilities arising from a Single Transaction.
• Amendments to IAS 12 – Income Taxes: International Tax Reform - Pillar 2 Model.
This standard and these amendments have no material impact on the Group's consolidated financial statements. (1) Available on the European Commission’s website:
http://eur-lex.europa.eu/legal-content/FR/TXT/?uri=CELEX:02002R1606-20080410 767 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 ACCOUNTING FRAMEWORK AND BASIS FOR PREPARING THE CONSOLIDATED FINANCIAL STATEMENTS ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
36 1.1.2 IFRS Standards, amendments or IFRIC Interpretations effective from 2024 and that the Group has elected not to early adopt
• Amendments to IAS 1 – Presentation of Financial Statements: Classification of Liabilities as Current or NonCurrent. • Amendments to IFRS 16 – Leases: Lease Liability in a Sale and Leaseback. • Amendments to IAS 7 – Statement of Cash Flows and IFRS 7 – Financial Instruments: Disclosures – Supplier Finance Arrangements (1).
• Amendments to IAS 21 – The Effects of Changes in Foreign Exchange Rates: Lack of Exchangeability (1).
The impact of these amendments is currently being assessed.
1.2 Measurement and presentation basis
1.2.1 Historical cost convention
The Group's consolidated financial statements are presented in euros and have been prepared using the historical cost convention, except for financial instruments, which are accounted for under the financial instrument categories defined by IFRS 9.
1.2.2 Chosen options
1.2.2.1 Reminder of IFRS 1 transition options
The Group used some of the options available under IFRS 1 for its transition to IFRS in 2005. The options that continue to have an impact on the consolidated financial statements are:
• translation adjustments: the Group elected to reclassify cumulative translation adjustments within consolidated equity at January 1, 2004;
• business combinations: the Group elected not to restate business combinations that took place prior to January 1, 2004 in accordance with IFRS 3.
1.2.2.2 Business combinations
Business combinations carried out prior to January 1, 2010 were accounted for in accordance with IFRS 3 prior to the revision. In accordance with IFRS 3 revised, these business combinations have not been restated.
Since January 1, 2010, the Group applies the purchase method as defined in IFRS 3 revised, which consists in recognizing the identifiable assets acquired and liabilities assumed at their fair values at the acquisition date, as well as any noncontrolling interests in the acquiree. Non-controlling interests are measured either at fair value or at the entity's proportionate interest in the net identifiable assets of the acquiree. The Group determines on a case-by-case basis which measurement option to be used to recognize non-controlling interests. (1) These standards and amendments have not yet been adopted by the European Union. 768 of 1021
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NOTE 1 ACCOUNTING FRAMEWORK AND BASIS FOR PREPARING THE CONSOLIDATED FINANCIAL STATEMENTS ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
37 1.2.2.3 Consolidated statement of cash flows
The consolidated statement of cash flows is prepared using the indirect method starting from net income. “Interest received on non-current financial assets” is classified within investing activities because it represents a return on investments. “Interest received on cash and cash equivalents” is shown as a component of financing activities because the interest can be used to reduce borrowing costs. This classification is consistent with the Group's internal organization, where debt and cash are managed centrally by the Group treasury department.
As impairment losses on current assets are considered to be definitive losses, changes in current assets are presented net of impairment.
Cash flows relating to the payment of income tax are presented on a separate line.
1.2.3 Foreign currency transactions
1.2.3.1 Translation of foreign currency transactions
Foreign currency transactions are recorded in the functional currency at the exchange rate prevailing on the date of the transaction.
Functional currency is the currency of the primary economic environment in which an entity operates, which in most cases corresponds to local currency. However, certain entities may have a functional currency different from the local currency when that other currency is used for an entity's main transactions and better reflects its economic environment.
At each reporting date:
• monetary assets and liabilities denominated in foreign currencies are translated at year-end exchange rates. The resulting translation gains and losses are recorded in the consolidated income statement for the year to which they relate;
• non-monetary assets and liabilities denominated in foreign currencies are recognized at the historical cost applicable at the date of the transaction.
1.2.3.2 Translation of the financial statements of subsidiaries with a functional currency other than the euro (the presentation currency)
The statements of financial position of these subsidiaries are translated into euros at the official year-end exchange rates.
Income statement and cash flow statement items are translated using the average exchange rate for the year. Any differences arising from the translation of the financial statements of these subsidiaries are recorded under “Translation adjustments” as other comprehensive income.
Goodwill and fair value adjustments arising on the acquisition of foreign entities are classified as assets and liabilities of those foreign entities and are therefore denominated in the functional currencies of the entities and translated at the yearend exchange rate.
1.3 Use of estimates and judgment
1.3.1 Estimates
The preparation of consolidated financial statements requires the use of estimates and assumptions to determine the value of assets and liabilities and contingent assets and liabilities at the reporting date, as well as income and expenses reported during the period.
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NOTE 1 ACCOUNTING FRAMEWORK AND BASIS FOR PREPARING THE CONSOLIDATED FINANCIAL STATEMENTS ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
38 Developments in the economic and financial environment, particularly relating to volatile commodities markets, and the war in Ukraine have prompted the Group to step up its risk oversight procedures, mainly in measuring financial instruments and assessing counterparty and liquidity risk. The estimates used by the Group, among other things, to test for impairment and to measure provisions, also take into account this environment and the market volatility.
Accounting estimates are made in a context that remains sensitive to energy market developments, therefore making it difficult to apprehend medium- and short-term economic prospects. Particular attention has been paid to the consequences of fluctuations in the price of gas and electricity.
Due to uncertainties inherent in the estimation process, the Group regularly revises its estimates in light of currently available information. Final outcomes could differ from those estimates.
The key estimates used in preparing the Group's consolidated financial statements relate mainly to:
• measurement of the recoverable amount of goodwill (see Note 13.1), other intangible assets (see Note 13.2) and property, plant and equipment (see Note 13.3);
• measurement of the fair value of financial assets and liabilities, and, in the current context, factoring in the uncertainty surrounding the key assumptions used, in particular updating the main valuation inputs of commodity derivatives, in particular the “bid ask” reserve, to reflect the volatility of commodity prices (see Notes 14 and 15); • assessment of expected credit losses, particularly in order to update probabilities of default and other inputs, mainly for calculating the CVA (Credit Valuation Adjustment) in a context of market price uncertainty and volatility (see Note 15);
• the measurement of provisions, in particular those relating to the treatment of nuclear waste under the agreement signed on June 29, 2023 with the Belgian government on the extension of the Tihange 3 and Doel 4 nuclear reactors and on all nuclear waste-related obligations, which became binding following the signature of supplements to the initial agreements on July 21, 2023. Transaction documents signed on December 13, 2023 specify the practical implementation of the first agreements of June and July. These estimates also concern provisions for dismantling facilities, disputes, and pensions and other employee benefits (see Notes 17 and 18); • measurement of un-metered revenues (energy in the meter), for which the valuation techniques have been impacted by changes in certain customers' consumption habits in a context of fluctuations in commodity prices (see Note 7);
• measurement of recognized tax loss carry-forwards, taking into account, where applicable, taxable income revisions and projections (see Note 11).
1.3.2 Judgment
As well as relying on estimates, Group management also makes judgments to define the appropriate accounting policies to apply to certain activities and transactions, particularly when the IFRS Standards and IFRIC Interpretations in force do not specifically deal with the related accounting issues.
In particular, the Group exercised its judgment in:
• assessing the nature of control (see Notes 2 and 3);
• identifying the performance obligations of sales contracts (see Note 7); • determining how revenues are recognized for distribution or transmission services invoiced to customers (see Note 7);
• recognizing support measures granted by certain governments, particularly in France and Romania (“tariff shield”), aimed at protecting both consumers and suppliers of gas and electricity against sharp fluctuations in commodity prices (see Note 7);
• identifying "own use contracts" as defined by IFRS 9 within non-financial purchase and sale contracts (electricity, gas, etc.) (see Note 14);
• identifying offsetting arrangements that meet the criteria set out in IAS 32 Financial Instruments: Presentation (see Note 14);
• determining whether arrangements are or contain a lease (see Note 13.3); • recognizing contributions in the energy sector in Europe (see Note 8). 770 of 1021
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NOTE 1 ACCOUNTING FRAMEWORK AND BASIS FOR PREPARING THE CONSOLIDATED FINANCIAL STATEMENTS ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
39 Entities for which judgment on the nature of control has been exercised are listed in Note 2 “Main subsidiaries at December 31, 2023” and Note 3 “Investments in equity method entities”.
1.3.3 Consideration of climate issues in the preparation of the Group's financial statements
In addition to the operational and financial issues and risks taken into account in determining future cash flows, the discount rate net of inflation and projected growth, the Group has also exercised its judgment to use assumptions reflecting climate change issues, in order to determine their potential impact on the consolidated financial statements. In particular, the Group checked whether there were any indications that non-financial assets might be impaired:
• the commitments made by France, Europe and various countries at international level, in particular with regard to long-term carbon neutrality, are taken into account (i) in assessing the value of the Group's assets, in particular through the long-term price scenarios used in impairment tests (see Note 13.4), and (ii) in assessing dismantling provisions, in particular by assessing the useful life of gas infrastructures in France based on the expected change in the energy mix (see Note 17);
• the commitments made specifically by ENGIE are also reflected in the assessment of the value of the Group's assets (see Note 13.4.1), in particular (i) the complete withdrawal from coal activities by 2027, which primarily concerns South America, depending on each asset's specific prospects (closure, conversion or disposal) and (ii) the gradual decarbonization of the Group's power generation activities to net zero by 2045 and, more broadly, the Group's investment strategy in favor of the energy transition by expanding its renewable energy fleet, substituting natural gas with renewable gas, thereby confirming a mixed gas/electricity scenario in the Group's long-term projections under the present regulation/remuneration methods for regulated assets (in France in particular), and developing low-carbon services offerings.
As a reminder, the management of climate and environmental risks and their challenges for the Group are presented in Chapter 2 “Risk factors” and Chapter 3 “Non-Financial Statement and CSR Information” of the Universal Registration Document.
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NOTE 2 MAIN SUBSIDIARIES AT DECEMBER 31, 2023
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
40 NOTE 2 MAIN SUBSIDIARIES AT DECEMBER 31, 2023
Accounting standards
Controlled entities (subsidiaries) are fully consolidated in accordance with IFRS 10 – Consolidated Financial Statements. An investor (the Group) controls an entity and therefore must consolidate it if all of the following three criteria are met:
• it has the ability to direct the relevant activities of the entity; • it has the rights and is exposed to variable returns from its involvement with the entity; • it has the ability to use its power over the entity to affect the investor’s return.
2.1 List of main subsidiaries at December 31, 2023
The following lists are made available by the Group to third parties, pursuant to Regulation No. 2016-09 of the French accounting standards authority (ANC) issued on December 2, 2016:
• list of companies included in consolidation;
• list of companies excluded from consolidation because their individual and cumulative incidence on the Group’s consolidated financial statements is not material. They correspond to entities deemed not significant as regards the Group’s main key figures (revenues, total equity, etc.) or entities that have ceased all activities and are undergoing liquidation/closure proceedings;
• list of main non-consolidated interests.
This information is available on the Group’s website (www.engie.com, Investors/Regulated information section).
Non-consolidated companies are classified as non-current financial assets (see Note 14.1.1.1) under “Equity instruments at fair value”.
The list of the main subsidiaries consolidated under the full consolidation method presented below was determined, as regards operating entities, based on their contribution to Group revenues, EBITDA, net income and net debt. The main equity-accounted investments (associates and joint ventures) are presented in Note 3 “Investments in equity method entities”.
Some entities such as ENGIE SA, ENGIE Énergie Services SA or Electrabel SA comprise both operating activities and headquarters functions which report to management teams of different reportable segments. In the following tables, these operating activities and headquarters functions are shown within their respective reportable segments under their initial company name followed by a (*) sign.
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NOTE 2 MAIN SUBSIDIARIES AT DECEMBER 31, 2023
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
41 Renewables
% interest
Company name Activity Country Dec. 31, 2023 Dec. 31, 2022 BTE Renewables Electricity distribution and generation South Africa 60.0 - Compagnie Nationale du Rhône Electricity distribution and generation France 50.0 50.0 ENGIE Energía Perú * Electricity distribution and generation Peru 61.8 61.8 ENGIE Green Electricity distribution and generation France 100.0 100.0 ENGIE Renouvelables Electricity distribution and generation France 100.0 100.0 ENGIE Romania *(1) Natural gas distribution, Energy sales Romania 51.0 51.0 ENGIE Solar Solar EPC France 100.0 100.0
Groupe ENGIE Brasil Energia * Electricity distribution and generation Brazil 68.7 68.7 Groupe ENGIE Energía Chile * Electricity distribution and generation Chile 60.0 60.0 Jupiter Equity Holding LLC Electricity distribution and generation United States 51.0 51.0 Mercury Equity Holding LLC Electricity distribution and generation United States 51.0 51.0 Saturn Equity Holding LLC Electricity distribution and generation United States 100.0 100.0 Kathu Solar Park (2) Electricity distribution and generation South Africa 57.7 48.5 (1) On February 20, 2024, ENGIE finalized the acquisition of an additional 12% stake in ENGIE Romania. (2) Following the acquisition of an additional stake in 2023, the Group now fully consolidates Kathu Solar Park (see Note 4.2).
Networks
% interest
Company name Activity Country Dec. 31, 2023 Dec. 31, 2022 Elengy Natural gas, LNG France 60.8 60.8
ENGIE Romania *(1) Natural gas distribution, Energy sales Romania 51.0 51.0 Fosmax LNG Natural gas, LNG France 60.8 60.8
GRDF Natural gas distribution France 100.0 100.0
ENGIE Brazil Energia Group * Electricity distribution and generation Brazil 68.7 68.7 ENGIE Energía Chile Group * Electricity distribution and generation Chile 60.0 60.0 GRTgaz Group (excluding Elengy) Natural gas transportation France, Germany 60.8 60.8 Storengy Deutschland GmbH Underground natural gas storage Germany 100.0 100.0 Storengy SAS Underground natural gas storage France 100.0 100.0 (1) On February 20, 2024, ENGIE finalized the acquisition of an additional 12% stake in ENGIE Romania.
Energy Solutions
% interest
Company name Activity Country Dec. 31, 2023 Dec. 31, 2022 Cofely Besix Systems, facilities and maintenance
services
UAE 100.0 100.0
CPCU Urban heating networks France 66.5 66.5
Energie SaarLorLux AG Energy services Germany 51.0 51.0 ENGIE Deutschland GmbH Energy services Germany 100.0 100.0 ENGIE Energie Services SA * Energy services, Networks France 100.0 100.0 ENGIE Servizi S.p.A Energy services Italy 100.0 100.0
Tractebel Engineering Engineering Belgium 100.0 100.0
FlexGen
% interest
Company name Activity Country Dec. 31, 2023 Dec. 31, 2022 Group Broad Reach Power Battery storage United States 100.0 ‐ Electrabel SA * Electricity generation, Energy sales Belgium 100.0 100.0 ENGIE Energía Perú * Electricity distribution and generation Peru 61.8 61.8 ENGIE Energie Nederland N.V. * Electricity generation, Energy sales Netherlands 100.0 100.0 ENGIE Italia S.p.A * Electricity generation, Energy sales Italy 100.0 100.0 ENGIE SA * Electricity generation, Energy sales France 100.0 100.0 ENGIE Thermique France Electricity generation France 100.0 100.0 First Hydro Holdings Company Electricity generation United Kingdom 75.0 75.0 ENGIE Energía Chile Group * Electricity distribution and generation Chile 60.0 60.0 Pelican Point Power Limited Electricity generation Australia 100.0 72.0 UCH Power Limited Electricity generation Pakistan 100.0 100.0 773 of 1021
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NOTE 2 MAIN SUBSIDIARIES AT DECEMBER 31, 2023
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
42 Retail
% interest
Company name Activity Country Dec. 31, 2023 Dec. 31, 2022 Electrabel SA * Electricity generation, Energy sales Belgium 100.0 100.0 ENGIE Italia S.p.A * Electricity generation, Energy sales Italy 100.0 100.0 ENGIE Romania *(1) Natural gas distribution, Energy sales Romania 51.0 51.0 ENGIE SA * Electricity generation, Energy sales France 100.0 100.0 Simply Energy Energy sales Australia 100.0 72.0
(1) On February 20, 2024, ENGIE finalized the acquisition of an additional 12% stake in ENGIE Romania.
Nuclear
% interest
Company name Activity Country Dec. 31, 2022 Dec. 31, 2022 Electrabel SA * Electricity generation, Energy sales Belgium 100.0 100.0 Synatom Managing provisions relating to power
plants and nuclear fuel
Belgium 100.0 100.0
Others
% interest
Company name Activity Country Dec. 31, 2023 Dec. 31, 2022 Cogac Holding France 100.0 100.0
Electrabel SA * Electricity generation, Energy sales Belgium 100.0 100.0 ENGIE CC Financial subsidiaries, Central
functions
Belgium 100.0 100.0
ENGIE Deutschland AG * Holding, Energy management trading Germany 100.0 100.0 ENGIE Energie Nederland Holding B.V. * Holding, Energy management trading Netherlands 100.0 100.0 ENGIE Energie Nederland N.V. Electricity generation, Energy sales Netherlands 100.0 100.0 ENGIE Energy Services International SA Holding Belgium 100.0 100.0 ENGIE Energie Services SA * Energy services, Networks France 100.0 100.0 ENGIE Energy Management * Energy management trading France, Belgium, Italy, United
Kingdom
100.0 100.0
ENGIE Finance SA Financial subsidiaries France 100.0 100.0 ENGIE Global Markets Energy management trading France, Belgium, Singapore
100.0 100.0
ENGIE Holding Inc. Holding - parent company United States 100.0 100.0 ENGIE Italia S.p.A * Holding, Energy management trading Italy 100.0 100.0 ENGIE North America Electricity distribution and generation, Natural gaz, LNG, Energy services
United States 100.0 100.0
ENGIE Resources Inc. Energy sales United States 100.0 100.0 ENGIE Romania *(1) Natural gas distribution, Energy sales Romania 51.0 51.0 ENGIE SA * Holding - parent company, Energy
management trading, energy sales
France 100.0 100.0
GDF International Holding France 100.0 100.0
Genfina Holding Belgium 100.0 100.0
ENGIE Energía Chile Group * Electricity distribution and generation Chile 60.0 60.0 International Power Limited Holding United Kingdom 100.0 100.0 (1) On February 20, 2024, ENGIE finalized the acquisition of an additional 12% stake in ENGIE Romania. 774 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 2 MAIN SUBSIDIARIES AT DECEMBER 31, 2023
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
43 2.2 Significant judgments exercised when assessing control The Group primarily considers the following information and criteria when determining whether it has control over an entity:
• governance arrangements: voting rights and whether the Group is represented in the governing bodies, majority rules and veto rights;
• the nature of substantive or protective rights granted to shareholders, relating to the entity’s relevant activities; • deadlock resolution mechanisms;
• whether the Group is exposed, or has rights, to variable returns from its involvement with the entity.
The Group exercised its judgment regarding the entities and sub-groups described below.
Entities in which the Group has the majority of the voting rights GRTgaz (France Infrastructures): 60.8%
The analysis of the shareholders' agreement concluded with Société d'Infrastructures Gazières, a subsidiary of Caisse des Dépôts et Consignations (CDC), which holds 38.6% of the share capital of GRTgaz, was completed by an assessment of the rights granted to the French Energy Regulatory Commission (Commission de Régulation de l’Énergie – CRE). As a regulated activity, GRTgaz has a dominant position on the gas transportation market in France. Accordingly, since the transposition of the Third European Directive of July 13, 2009 into French law (Code de l’énergie – Energy Code) on May 9, 2011, GRTgaz has been subject to independence rules as regards its directors and senior management team. The French Energy Code confers certain powers on the CRE in the context of its duties to control the proper functioning of the gas markets in France, including verifying the independence of the members of the Board of Directors and senior management and assessing the choice of investments. The Group considers that it exercises control over GRTgaz and its subsidiaries (including Elengy) based on the Group’s ability to appoint the majority of the members of the Board of Directors and take decisions about the relevant activities, especially in terms of the level of investment and planned financing.
Entities in which the Group does not have the majority of the voting rights For entities in which the Group does not have the majority of the voting rights, judgment is exercised with regard to the following items, in order to assess whether there is a situation of de facto control:
• dispersion of the shareholding structure: number of voting rights held by the Group relative to the number of rights held respectively by the other holders of voting rights and their dispersion; • voting patterns at shareholders' meetings: the percentages of voting rights exercised by the Group at shareholders' meetings in recent years;
• governance arrangements: representation in the governing body with strategic and operational decision-making power over the relevant activities;
• rules for appointing key management personnel;
• contractual relationships and material transactions.
The main fully consolidated entity in which the Group does not have the majority of the voting rights at December 31, 2022 is Compagnie Nationale du Rhône (49.98%).
Compagnie Nationale du Rhône (“CNR” – Renewables France): 49.98% The Group holds 49.98% of the share capital of CNR, with CDC holding 33.2%, and the balance of 16.82% being dispersed among around 200 local authorities. In view of the current provisions of the French “Murcef” law, under which a majority of CNR's share capital must remain under public ownership, the Group is unable to hold more than 50% of the share capital.
However, the Group considers that it exercises de facto control as it holds the majority of the voting rights exercised at shareholders’ meetings due to the widely dispersed shareholding structure and the absence of evidence of the minority shareholders acting in concert.
775 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 2 MAIN SUBSIDIARIES AT DECEMBER 31, 2023
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
44 2.3 Main subsidiaries with non-controlling interests The following table shows the subsidiaries with non-controlling interests that are deemed to be material, the respective contributions to equity and to net income at December 31, 2023 and December 31, 2022, as well as the dividends paid to non-controlling interests:
Company name Activity
Percentage interest
of non-controlling
interests
Net income/(loss)
of non-controlling
interests
Equity of
non-controlling
interests
Dividends paid to
non-controlling
interests
In millions of euros
Dec. 31,
2023
Dec. 31,
2022
Dec. 31,
2023
Dec. 31,
2022
Dec. 31,
2023
Dec. 31,
2022
Dec. 31,
2023
Dec. 31,
2022
GRTgaz Group (France
Infrastructures, France)
Regulated gas transportation
activities and management
of LNG terminals
39.2 39.2 158 190 1,611 1,614 194 168
ENGIE Energía Chile Group
(Latin America, Chile) (1)
Electricity distribution and
generation - thermal power
plants
40.0 40.0 (147) (158) 504 680 ‐ ‐
ENGIE Romania Group
(Rest of Europe, Romania)
(2)
Distribution of natural gas,
Energy sales
49.0 49.0 70 31 671 607 ‐ ‐
ENGIE Brasil Energia Group
(Latin America, Brazil) (1)
Electricity distribution and
generation
31.3 31.3 145 116 569 296 58 112
ENGIE Energía Perú (Latin
America, Peru) (1)
Electricity distribution and
generation - thermal and
hydroelectric power plants
38.2 38.2 5 21 412 433 12 12
Other subsidiaries with non-controlling interests (3) 464 (27) 1,900 1,401 258 190 TOTAL 695 173 5,667 5,032 522 482
(1) ENGIE Energia Chile, ENGIE Brasil Energia and ENGIE Energia Perú are listed in their respective countries. (2) On February 20, 2024, ENGIE finalized the acquisition of an additional 12% stake in ENGIE Romania. (3) The net income/(loss) of other non-controlling interests is mainly impacted by the net income of the operating MtMs for an amount of €386 million in 2023 and a net loss of €158 million in 2022. 776 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 2 MAIN SUBSIDIARIES AT DECEMBER 31, 2023
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
45 2.3.1 Condensed financial information on main subsidiaries with non-controlling interests
The condensed financial information concerning these subsidiaries presented in the table below is based on a 100% interest and is shown before intragroup eliminations.
GRTgaz Group ENGIE Energía Chile Group ENGIE Romania Group (1) In millions of euros Dec. 31, 2023 Dec. 31, 2022 Dec. 31, 2023 Dec. 31, 2022 Dec. 31, 2023 Dec. 31, 2022 Income statement
Revenues 2,623 2,535 1,732 1,648 2,111 2,819
Net income/(loss) 403 485 (367) (395) 142 63
Net income/(loss) Group share 245 295 (220) (237) 72 32 Other comprehensive income/(loss) – Group share 56 54 (43) 85 (7) (15) TOTAL COMPREHENSIVE INCOME/(LOSS) –
GROUP SHARE
301 349 (264) (152) 65 17
Statement of financial position
Current assets 1,189 1,319 1,170 1,108 796 1,091
Non-current assets 9,780 9,961 3,058 3,210 1,062 975
Current liabilities (1,325) (1,360) (655) (540) (398) (753) Non-current liabilities (5,532) (5,803) (2,325) (2,091) (102) (86) TOTAL EQUITY 4,112 4,116 1,247 1,688 1,358 1,227
TOTAL EQUITY OF NON-CONTROLLING
INTERESTS
1,611 1,614 504 680 671 607
Statement of cash flows
Cash flow from operating activities 1,090 1,117 482 (320) 412 (365) Cash flow from (used in) investing activities (486) (450) (424) (384) (148) (121) Cash flow from (used in) financing activities (616) (663) 86 635 (254) 317 TOTAL CASH FLOW FOR THE PERIOD (2) (13) 4 144 (68) 11 (169) (1) On February 20, 2024, ENGIE finalized the acquisition of an additional 12% stake in ENGIE Romania. (2) Excluding effects of changes in exchange rates and other.
ENGIE Brasil Energia Group ENGIE Energía Perú
In millions of euros Dec. 31, 2023 Dec. 31, 2022 Dec. 31, 2023 Dec. 31, 2022 Income statement
Revenues 1,979 2,164 704 525
Net income/(loss) 434 370 12 56
Net income/(loss) Group share 288 254 8 34
Other comprehensive income/(loss) – Group share (73) 72 (24) 51 TOTAL COMPREHENSIVE INCOME/(LOSS) – GROUP SHARE 216 326 (17) 85 Statement of financial position
Current assets 1,691 1,322 543 384
Non-current assets 5,571 4,731 1,778 1,923
Current liabilities (1,081) (1,019) (372) (257)
Non-current liabilities (4,875) (4,213) (870) (915)
TOTAL EQUITY 1,306 822 1,079 1,135
TOTAL EQUITY OF NON-CONTROLLING INTERESTS 569 296 412 433 Statement of cash flows
Cash flow from operating activities 1,309 1,027 162 62
Cash flow from (used in) investing activities (711) (685) (94) (186) Cash flow from (used in) financing activities (39) (1,010) (72) 17 TOTAL CASH FLOW FOR THE PERIOD (1) 559 (668) (4) (107)
(1) Excluding effects of changes in exchange rates and other. 777 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 3 INVESTMENTS IN EQUITY METHOD ENTITIES
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
46 NOTE 3 INVESTMENTS IN EQUITY METHOD ENTITIES
Accounting standards
The Group accounts for its investments in associates and joint ventures using the equity method. Under IFRS 11 – Joint Arrangements, a joint venture is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the arrangement. An associate is an entity over which the Group has significant influence.
The respective contributions of associates and joint ventures in the statement of financial position, the income statement and the statement of comprehensive income at December 31, 2023 and December 31, 2022 are as follows:
In millions of euros Dec. 31, 2023 Dec. 31, 2022
Statement of financial position
Investments in associates 4,259 4,187
Investments in joint ventures 4,954 5,092
INVESTMENTS IN EQUITY METHOD ENTITIES 9,213 9,279
Income statement
Share in net income/(loss) of associates 486 400
Share in net income/(loss) of joint ventures 580 659
SHARE IN NET INCOME/(LOSS) OF EQUITY METHOD ENTITIES 1,066 1,059 Statement of comprehensive income
Share of associates in "Other comprehensive income/(loss)" 11 510 Share of joint ventures in "Other comprehensive income/(loss)" 26 366 SHARE OF EQUITY METHOD ENTITIES IN "OTHER COMPREHENSIVE INCOME/(LOSS)" 37 876 Significant judgments
The Group primarily considers the following information and criteria in determining whether it has joint control or significant influence over an entity:
• governance arrangements: whether the Group is represented in the governing bodies, majority rules and veto rights;
• the nature of substantive or protective rights granted to shareholders, relating to the entity’s relevant activities.
This can be difficult to determine in the case of “project management” or “one-asset” entities, as certain decisions concerning the relevant activities are made upon the creation of the joint arrangement and remain valid throughout the project. Accordingly, the analysis of rights relates to the relevant residual activities of the entity (those that significantly affect the variable returns of the entity); • deadlock resolution mechanisms;
• whether the Group is exposed, or has rights, to variable returns from its involvement with the entity.
This can also involve analyzing the Group’s contractual relations with the entity, in particular the conditions in which these contracts are entered into, their duration as well as the management of conflicts of interest that may arise when the entity’s governing body casts votes.
778 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 3 INVESTMENTS IN EQUITY METHOD ENTITIES
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
47 The Group exercised its judgment regarding the following entities and sub-groups:
Project management entities in the Middle East and in Africa The significant judgments made in determining the consolidation method to be applied to these project management entities related to the risks and rewards relating to contracts between ENGIE and the entity concerned, as well as an analysis of the residual relevant activities over which the entity retains control after its creation. The Group considers that it exercises significant influence or joint control over these entities, since the decisions taken throughout the term of the project about the relevant activities such as refinancing, or the renewal or amendment of significant contracts (sales, purchases, operating and maintenance services) require, depending on the case, the unanimous consent of two or more parties sharing control.
Joint ventures in which the Group holds an interest of more than 50% Tihama (60%)
ENGIE holds a 60% stake in the Tihama cogeneration plant in Saudi Arabia and its partner Saudi Oger holds 40%.
The Group considers that it has joint control over Tihama since decisions about its relevant activities, including for example the approval of the budget and amendments to major contracts, etc., require the unanimous consent of the parties sharing control.
Transportadora Associada de Gás S.A. (“TAG” - Latin America): 65.0% holding interest representing a net interest in TAG of 54.8% (1)
The Group exercises joint control over TAG since decisions about its relevant activities, including, for example, the preparation of the budget and medium-term plan, investments, operations and maintenance, etc., are taken by a majority vote requiring the agreement of ENGIE and Caisse de dépôt et placement du Québec (CDPQ).
Joint control – difference between joint ventures and joint operations Classifying a joint arrangement requires the Group to use its judgment to determine whether the entity in question is a joint venture or a joint operation. IFRS 11 requires an analysis of “other facts and circumstances” when determining the classification of jointly controlled entities.
The IFRS Interpretations Committee (IFRS IC) (November 2014) decided that for an entity to be classified as a joint operation, other facts and circumstances must give rise to direct enforceable rights to the assets, and obligations for the liabilities, of the joint arrangement.
In view of this position and its application to our analyses, the Group has no material joint operations at December 31, 2023.
3.1 Investments in associates
3.1.1 Contribution of material associates and of associates that do not have a material impact on the Group’s financial statements taken individually The table below shows the contribution of each material associate along with the aggregate contribution of associates deemed not material taken individually, in the consolidated statement of financial position, income statement, statement of comprehensive income, and the “Dividends received from equity method entities” line of the statement of cash flows. (1) In January 2024, the Group completed the sale of a 15% stake in TAG to CDPQ (current partner). On completion of this transaction the Group no longer holds any potential voting rights. The Group's holding in TAG amounts to 50%, resulting in a net interest of
44.5% (the impact of this partial disposal on net financial debt 2024 amounts to €0.5 billion). 779 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 3 INVESTMENTS IN EQUITY METHOD ENTITIES
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
48 The Group used qualitative and quantitative criteria to determine material associates. These criteria include the contribution to the consolidated line items “Share in net income/(loss) of associates” and “Investments in associates”, the total assets of associates in Group share, and associates carrying major projects in the study or construction phase for which the related investment commitments are material.
Company name Activity Capacity
Consolidation
percentage of
investments in
associates
Carrying amount
of investments in
associates
Share in net
income/(loss) of
associates
Other
comprehensive
income/(loss) of
associates
Dividends
received from
associates
In millions of euros
Dec. 31,
2023
Dec. 31,
2022
Dec. 31,
2023
Dec. 31,
2022
Dec. 31,
2023
Dec. 31,
2022
Dec. 31,
2023
Dec. 31,
2022
Dec. 31,
2023
Dec. 31,
2022
Project
management
entities in the
Middle East
(Middle-East, Asia
& Africa, Saudi
Arabia, Bahrain,
Qatar, United
Arab Emirates,
Oman, Kuwait) (1)
Gas-fired
power plants
and seawater
desalination
facilities ‐ ‐ 1,346 1,378 176 181 24 411 143 145
Movhera
Hydro power
plant
1 688
MW 40.00 40.00 556 521 31 (13) 11 41 8 ‐
Energia
Sustentável do
Brasil (Brazil)
Hydro power
plant
3 750
MW 40.00 40.00 596 567 10 (3) ‐ ‐ ‐ ‐
GASAG
(Germany)
Gas and heat
networks 31.57 31.58 255 279 26 26 (36) (62) 15 17
Eolia Renovables
Wind power
plant 943 MW 40.00 40.00 343 359 14 33 (3) 2 28 ‐
Other investments in associates that are not
material taken individually 1,163 1,082 227 176 15 118 123 109 INVESTMENTS IN ASSOCIATES 4,259 4,187 486 400 11 510 316 271 (1) Investments in associates operating gas-fired power plants and seawater desalination facilities in the Arabian Peninsula have been grouped together under “Project management entities in the Middle East”. This mainly includes around 40 associates operating thermal power plants with a total installed capacity of 26,388 MW (at 100%).
These associates have fairly similar business models and joint arrangements: the project management entities selected as a result of a competitive bidding process develop, build and operate power generation plants and seawater desalination facilities. The entire output of these facilities is sold to government-owned companies under power and water purchase agreements, over periods generally spanning 20 to 30 years.
In accordance with their contractual arrangements, the corresponding plants are recognized in accordance with IFRIC 12, IFRS 16 or IAS 16 as property, plant and equipment or as financial receivables. The shareholding structure of these entities systematically includes a government-owned company based in the same country as the project management entity. The Group’s percentage interest and percentage voting rights in each of these entities varies between 20% and 50%.
The share in net income/(loss) of associates includes a net non-recurring income of €18 million in 2023 (compared to a net non-recurring loss of €18 million in 2022), mainly including changes in the fair value of derivative instruments, impairment losses and disposal gains and losses, net of tax (see Note 5.3 “Net recurring income Group share (NriGs)”). 780 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 3 INVESTMENTS IN EQUITY METHOD ENTITIES
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
49 3.1.2 Financial information regarding material associates The tables below provide condensed financial information for the Group's main associates. The amounts shown have been determined in accordance with IFRS, before the elimination of intragroup transactions and after (i) adjustments made in line with Group accounting policies and (ii) fair value measurements of the assets and liabilities of the associate performed at the acquisition date at the level of ENGIE, as required by IAS 28. All amounts are presented based on a 100% interest with the exception of “Total equity attributable to ENGIE”.
In millions of
euros Revenues
Net
income/
(loss)
Other
comprehensive
income/
(loss)
Total
comprehensive
income/
(loss)
Current
assets
Noncurrent
assets
Current
liabilities
Noncurrent
liabilities
Total
equity
Consolidation % of
Group
Total equity
attributable
to ENGIE
AT DECEMBER 31, 2023
Project
management
entities in the
Middle East 4,886 714 88 802 2,635 18,229 2,856 12,785 5,223 ‐ 1,346 Energia
Sustentável do
Brasil 625 24 ‐ 24 286 3,276 2,077 (5) 1,489 40.00 596
Movhera 434 78 28 106 249 2,055 85 829 1,390 40.00 556
GASAG 2,283 84 (112) (28) 1,640 2,058 2,643 247 809 31.57 255 Eolia
Renovables 177 36 (7) 29 138 2,165 226 1,219 858 40.00 343 AT DECEMBER 31, 2022
Project
management
entities in the
Middle East 5,067 764 1,695 2,459 2,824 19,711 3,343 13,781 5,411 ‐ 1,378 Energia
Sustentável do
Brasil 581 (7) ‐ (7) 239 3,275 2,098 ‐ 1,416 40.00 567
Movhera 384 (33) 103 70 147 2,124 699 269 1,303 40.00 521 GASAG 1,606 82 (196) (114) 1,491 2,140 2,462 284 885 31,57 279 Eolia
Renovables 216 82 4 86 297 2,097 340 1,155 900 40.00 359
3.1.3 Transactions between the Group and its associates The data below set out the impact of transactions with associates on the Group's 2023 consolidated financial statements.
In millions of euros
Purchases
of goods
and
services
Sales of
goods and
services
Net
financial
income
(excluding
dividends)
Trade and
other
receivables
Loans and
receivables
at
amortized
cost
Trade and
other
payables
Borrowings
and debt
Project management entities in the Middle East ‐ 200 10 28 147 ‐ ‐ Contassur (1)
‐ ‐ ‐ 242 2 ‐ ‐
Energia Sustentável do Brasil 133 ‐ ‐ ‐ ‐ 14 ‐
Movhera ‐ 42 11 7 119 1 3
Other 116 30 ‐ 34 126 47 (36)
AT DECEMBER 31, 2023 248 271 22 311 395 62 (33)
(1) Contassur is a life insurance company accounted for using the equity method. Contassur offers insurance contracts, chiefly with pension funds that cover post-employment benefit obligations for Group employees and also employees of other companies mainly engaged in regulated activities in the electricity and gas sector in Belgium. Insurance contracts entered into by Contassur represent reimbursement rights recorded within “Other assets” in the statement of financial position. These reimbursement rights totaled €242 million at December 31, 2023 (€208 million at December 31, 2022). 781 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 3 INVESTMENTS IN EQUITY METHOD ENTITIES
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
50 3.2 Investments in joint ventures
3.2.1 Contribution of joint ventures to the Group
The table below shows the contribution of each material joint venture along with the aggregate contribution of joint ventures deemed not material taken individually to the consolidated statement of financial position, income statement, statement of comprehensive income, and the “Dividends received from equity method entities” line of the statement of cash flows.
The Group used qualitative and quantitative criteria to determine material joint ventures. These criteria include the contribution to the line items “Share in net income/(loss) of joint ventures” and “Investments in joint ventures”, the Group’s share in the total assets of joint ventures, and joint ventures conducting major projects in the study or construction phase for which the related investment commitments are material.
Company name Activity Capacity
Consolidation
percentage of
investments in
joint ventures
Carrying amount
of investments in
joint ventures
Share in net
income/(loss) of
joint ventures
Other
comprehensive
income/(loss) of
joint ventures
Dividends
received from
joint ventures
In millions of euros
Dec. 31,
2023
Dec. 31,
2022
Dec. 31,
2023
Dec. 31,
2022
Dec. 31,
2023
Dec. 31,
2022
Dec. 31,
2023
Dec. 31,
2022
Dec. 31,
2023
Dec. 31,
2022
Transportadora
Associada de
Gás S.A. (TAG)
(Brazil) (1)
Gas
transmission
network 65.00 65.00 1,059 1,129 368 267 29 153 387 184
National Central
Cooling
Company
"Tabreed"
(Middle-East,
Asia & Africa,
Abu Dhabi)
District
cooling
networks 40.00 40.00 872 874 34 53 35 ‐ 39 18
EcoÉlectrica
(Puerto Rico)
Combinedcycle gasfired power
plant and
LNG
terminal 534 MW 50.00 50.00 293 314 52 42 ‐ ‐ 61 60
Portfolio of power
generation assets
in Portugal
Electricity
generation 2,396 MW 50.00 50.00 218 240 34 33 (2) 15 40 61 WSW Energie
und Wasser AG
(Germany)
Electricity
distribution
and
generation 33.10 33.10 197 249 (33) 19 ‐ 1 19 11
Iowa University
partnership
(United States)
Energy
services 39.10 39.10 222 229 6 6 (1) 2 4 1
Ocean Winds
Electricity
generation 1,462 MW 50.00 50.00 415 431 6 80 (47) 124 ‐ ‐ Georgetown
University
partnership
(United States)
Energy
services 50.00 50.00 200 203 7 6 ‐ 3 ‐ ‐
Tihama Power
Generation Co
(Saudi Arabia)
Electricity
generation 1,544 MW 60.00 60.00 91 94 24 21 (2) 5 21 29 Ohio State
Energy Partners
(United States)
Energy
services 50.00 50.00 50 82 (25) 4 9 8 17 16
Megal GmbH
(Germany)
Gas
transmission
network 49.00 49.00 55 61 ‐ 2 ‐ ‐ 6 9
Transmisora
Eléctrica del
Norte (Chile) (2)
Electricity
transmission
line 50.00 50.00 114 116 3 5 (3) 19 ‐ ‐
Other investments in joint ventures that are
not material taken individually 1,169 1,071 104 120 7 37 121 53 INVESTMENTS IN JOINT VENTURES 4,954 5,092 580 659 26 366 715 442 (1) The Group’s interest in Transportadora Associada de Gás S.A. (TAG) is 54.83%. In January 2024, the Group completed the sale of a 15% stake in TAG to CDPQ (current partner). On completion of this transaction, the Group’s holding stands at 50%, resulting in a net interest of
44.5% (the impact of this partial disposal on net financial debt in 2024 amounts to €0.5 billion). (2) The Group’s interest inTransmisora Eléctrica del Norte is 30%. 782 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 3 INVESTMENTS IN EQUITY METHOD ENTITIES
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
51 The share in net income/(loss) of joint ventures includes a non-recurring loss of €39 million in 2023 (non-recurring gain of €1 million in 2022), resulting chiefly from changes in the fair value of derivatives, impairment losses and disposal gains and losses, net of tax (see Note 5.3 “Net recurring income Group share (NriGs)”).
3.2.2 Financial information regarding material joint ventures The amounts shown have been determined in accordance with IFRS before the elimination of intragroup items and after (i) adjustments made in line with Group accounting policies and (ii) fair value measurements of the assets and liabilities of the joint venture performed at the date of acquisition at the level of ENGIE, as required by IAS 28. All amounts are presented based on a 100% interest with the exception of “Total equity attributable to ENGIE” in the statement of financial position.
3.2.2.1 Information on the income statement and statement of comprehensive income In millions of euros Revenues
Depreciation
and
amortization
of intangible
assets and
property,
plant and
equipment
Net financial
income/(loss)
Income tax
benefit/(expense)
Net
income/(loss)
Other
comprehensive
income/(loss)
Total
comprehensive
income/(loss)
AT DECEMBER 31, 2023
Transportadora Associada de Gás
S.A. (TAG) 1,672 (234) (308) (295) 566 45 610
National Central Cooling
Company "Tabreed" ‐ (8) (5) 39 84 89 173
EcoÉlectrica 185 (31) 2 (6) 104 ‐ 104
Portfolio of power generation
assets in Portugal 456 (48) (19) (28) 97 (7) 90
WSW Energie und Wasser AG 2,338 (19) (4) 8 (118) ‐ (118) Iowa University partnership 89 ‐ (21) ‐ 15 5 20
Ocean Winds 39 (7) 124 (5) 13 (94) (81)
Georgetown University
partnership
81 (2) (21) (1) 13 5 18
Tihama Power Generation Co 114 (5) (8) (6) 40 (4) 36
Ohio State Energy Partners 188 (1) (66) ‐ (50) 15 (35)
Megal GmbH 122 (70) (4) 2 ‐ ‐ ‐
Transmisora Eléctrica del Norte 71 ‐ (32) (5) 9 (4) 4
AT DECEMBER 31, 2022
Transportadora Associada de Gás
S.A. (TAG) 1,549 (292) (386) (215) 411 235 647
National Central Cooling
Company "Tabreed" 167 ‐ (35) ‐ 133 ‐ 133
EcoÉlectrica 166 (32) 1 (4) 85 ‐ 85
Portfolio of power generation
assets in Portugal 512 (50) (14) (27) 74 48 122
WSW Energie und Wasser AG 1,213 (14) ‐ (28) 50 3 53
Iowa University partnership 87 ‐ (21) ‐ 16 6 22
Ocean Winds 40 (9) (23) (1) 160 247 407
Georgetown University
partnership
60 (1) (22) ‐ 12 5 17
Tihama Power Generation Co 119 (6) (9) (6) 35 9 45
Ohio State Energy Partners 180 (1) (65) (2) 7 15 22
Megal GmbH 122 (67) (4) 1 5 ‐ 5
Transmisora Eléctrica del Norte 70 ‐ (27) (7) 13 19 32
783 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 3 INVESTMENTS IN EQUITY METHOD ENTITIES
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
52 3.2.2.2 Information on the statement of financial position In millions of euros
Cash and
cash
equivalents
Other
current
assets
Noncurrent
assets
Short-term
borrowings
Other
current
liabilities
Long-term
borrowings
Other
noncurrent
liabilities
Total
equity
Consolidation
% of Group
Total
equity
attributable
to ENGIE
AT DECEMBER 31,
2023 Transportadora
Associada de Gás
S.A. (TAG) 269 479 6,119 569 299 2,672 1,699 1,629 65.00 1,059 National Central Cooling
Company "Tabreed" 450 254 3,713 ‐ 233 1,737 94 2,352 40.00 872 EcoÉlectrica 4 76 543 3 17 ‐ 17 587 50.00 293
Portfolio of power
generation assets in
Portugal 285 403 550 101 236 372 51 479 50.00 218
WSW Energie und
Wasser AG
68 422 878 211 277 222 96 562 33.10 197
Iowa University
partnership
1 17 1,146 4 7 586 ‐ 568 39.10 222
Ocean Winds 313 ‐ 3,786 1,670 514 773 314 830 50.00 415 Georgetown University
partnership
‐ 6 964 ‐ ‐ 569 2 399 50.00 200
Tihama Power
Generation Co
54 62 206 72 42 46 11 152 60.00 91
Ohio State Energy
Partners
12 71 1,452 ‐ 64 1,353 19 99 50.00 50
Megal GmbH 48 15 644 170 39 341 46 112 49.00 55
Transmisora Eléctrica
del Norte 75 12 625 36 7 585 ‐ 83 50.00 42
AT DECEMBER 31,
2022 Transportadora
Associada de Gás S.A.
(TAG) 124 367 6,216 668 71 2,771 1,460 1,737 65.00 1,129 National Central Cooling
Company "Tabreed" 402 150 2,631 ‐ 194 805 ‐ 2,184 40.00 874 EcoÉlectrica 6 79 580 3 15 ‐ 18 629 50.00 314
Portfolio of power
generation assets in
Portugal 247 514 733 99 278 500 60 557 50.00 240
WSW Energie und
Wasser AG
82 518 950 263 260 147 150 731 33.10 249
Iowa University
partnership
2 17 1,162 7 7 581 ‐ 586 39.10 229
Ocean Winds 337 ‐ 2,425 1,149 189 137 424 863 50.00 431 Georgetown University
partnership
5 3 954 ‐ ‐ 555 3 404 50.00 203
Tihama Power
Generation Co
49 145 221 78 51 119 11 156 60.00 94
Ohio State Energy
Partners
14 65 1,441 ‐ 10 1,331 17 162 50.00 82
Megal GmbH 18 14 696 ‐ 44 511 49 125 49.00 61
Transmisora Eléctrica
del Norte 41 34 770 35 3 574 ‐ 233 50.00 116
784 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 3 INVESTMENTS IN EQUITY METHOD ENTITIES
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
53 3.2.3 Transactions between the Group and its joint ventures The data below set out the impact of transactions with joint ventures on the Group’s 2023 consolidated financial statements.
In millions of euros
Purchases
of goods
and
services
Sales of
goods and
services
Net
financial
income
(excluding
dividends)
Trade and
other
receivables
Loans and
receivables
at
amortized
cost
Trade and
other
payables
Borrowings
and debt
EcoÉlectrica ‐ ‐ ‐ ‐ ‐ ‐ 22
WSW Energie und Wasser AG (3) 17 ‐ 3 ‐ ‐ ‐
Megal GmbH 65 ‐ ‐ ‐ ‐ 6 ‐
Futures Energies Investissements Holding 69 25 11 4 182 8 ‐ Ocean Winds ‐ ‐ 28 3 535 ‐ ‐
Other 96 140 10 55 141 11 7
AT DECEMBER 31, 2023 226 182 48 65 857 27 29
3.3 Other information on investments accounted for using the equity method
3.3.1 Unrecognized share of losses of associates and joint ventures Cumulative unrecognized losses of associates (corresponding to the cumulative amount of losses exceeding the carrying amount of investments in the associates concerned) including other comprehensive income/(loss), amounted to €37 million in 2023 (versus €6 million in 2022).
These unrecognized losses correspond to the negative fair value of derivative instruments designated as interest rate and commodity hedges (“Other comprehensive income/(loss)”) contracted by associates in the Middle-East, Africa and Asia in connection with the financing of construction projects for power generation plants.
3.3.2 Commitments and guarantees given by the Group in respect of equity method entities
At December 31, 2023, the main commitments and guarantees given by the Group in respect of equity method entities concern:
• Energia Sustentável do Brasil (“Jirau”), for an aggregate amount of BRL 4,008 million (€742 million). At December 31, 2023, the loans granted by Banco Nacional de Desenvolvimento Econômico e Social, the Brazilian Development Bank, to Energia Sustentável do Brasil amounted to BRL 10,021 million (€1,855 million). Each partner stands as guarantor for this debt to the extent of its ownership interest in the consortium; • TAG, mainly for bank guarantees for an amount of €143 million; • The project management entities for an aggregate amount of €1,695 million. Commitments and guarantees given by the Group in respect of these project management entities chiefly correspond to:
− equity contribution commitments for projects in the construction phase for an amount of € 1,088 million, − letters of credit to guarantee debt service reserve accounts for an aggregate amount of €167 million.
The project financing set up in certain entities can require those entities to maintain a certain level of cash within the company (usually enough to service its debt for six months). This is particularly the case when the financing is without recourse. However, this level of cash may be replaced by letters of credit, − collateral given to lenders in the form of pledged shares in the project management entities, for an aggregate amount of €270 million,
− performance bonds and other guarantees for an amount of €135 million. 785 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 4 MAIN CHANGES IN GROUP STRUCTURE
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
54 NOTE 4 MAIN CHANGES IN GROUP STRUCTURE
Accounting standards
In accordance with IFRS 5 – Non-Current Assets Held for Sale and Discontinued Operations, assets or groups of assets held for sale are presented separately on the face of the statement of financial position and are measured and accounted for at the lower of their carrying amount and fair value less costs to sell.
An asset is classified as “held for sale” when its sale is highly probable within twelve months from the date of classification, when it is available for immediate sale under its present condition and when management is committed to a plan to sell the asset and an active program to locate a buyer and complete the plan has been initiated. To assess whether a sale is highly probable, the Group takes into consideration among other things indications of interest and offers received from potential buyers as well as specific execution risks attached to certain transactions.
If an asset classified as “held for sale” no longer meets the above conditions it will be reclassified in accordance with the standard.
Furthermore, assets or groups of assets are presented as discontinued operations in the Group’s consolidated financial statements when they are classified as “held for sale” and represent a separate major line of business under IFRS 5.
4.1 Disposals carried out in 2023
The table below shows the impact of the main disposals and sale agreements of 2023 on the Group’s net financial debt, excluding partial disposals with respect to DBSO (1) activities:
In millions of euros Disposal price
Reduction in net
debt
Disposal of a thermal plant - Brazil 75 ‐
Other disposals that are not material taken individually 192 246 TOTAL 267 246
On May 31, 2023, ENGIE finalized the sale of its entire stake in the Pampa Sul thermal power plant to Grafito Fundo de Investimento em Participações Infraestrutura and Perfin Space X Fundo de Investimento em Participações em Infraestrutura.
Given the classification of this investment within “Assets held for sale” in 2022 and the deferral to 2025 of the payment of the contractual sale price, this transaction has no material impact on the Group’s net financial debt at December 31, 2023.
The disposal loss before tax amounted to €47 million in 2023.
No Group assets are classified within “Assets held for sale” at December 31, 2023. (1) Develop, Build, Share and Operate, a model used in renewable energies based on continuous rotation of capital employed. 786 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 4 MAIN CHANGES IN GROUP STRUCTURE
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
55 4.2 Acquisitions carried out in 2023
In total, acquisitions carried out in 2023 (including financial investments in entities accounted for under the equity method) had an impact of €3,348 million on net financial debt. The main acquisitions carried out in 2023 are as follows:
• in October 2023, ENGIE finalized the acquisition of 100% of Broad Reach Power, a Houston-based company specialized in battery storage, from private equity funds EnCap and Apollo. The transaction involves 350 MW of operating assets, 880 MW of under-construction assets with a commissioning expected before the end of 2024,
1.7 GW of advanced stage projects and a significant pipeline of early stage projects. The projects are located in Texas, California and the central states of the United States. This investment is fully consolidated. This transaction had an impact of €1.4 billion on the Group’s net financial debt (of which €0.1 billion in January 2024).
The Group carried out a preliminary purchase price allocation, which will be finalized in the first half of 2024; • in September 2023, ENGIE purchased an additional stake in Kathu Solar Park (RF) Proprietary Trading from Lereko Metier REIPPP Fund Trust, increasing its holding from 48.5% to 57.725%. Following this transaction, Kathu Solar Park (RF) Proprietary Trading is now fully consolidated by ENGIE (previously accounted for under the equity method). This transaction had an impact of approximately €0.6 billion on the Group’s net financial debt, taking into account the consolidation of external debt;
• in December 2023, ENGIE and Meridiam purchased from ACTIS the full scope of BTE Renewables, a developer, owner and operator of renewable assets on the African continent, with an operating presence in South Africa and Kenya. The deal also included a carve-out of the Kenyan assets by ENGIE to Meridiam at closing. Following this transaction, BTE Renewables (South-African assets) has been fully consolidated by ENGIE. This transaction had an impact of approximately €0.4 billion on the Group’s net financial debt; • in December 2023, ENGIE finalized the acquisition of the minority stake (28%) held by Mitsui & Co, Ltd ("Mitsui") in International Power (Australia) Holdings Pty Limited ("IPAH"), a fully consolidated company in which the Group had a 72% stake. On completion of the transaction, the Group holds 100% of IPAH. The impact of this transaction on the Group's net financial debt amounted to around 0.2 billion euros; • in September 2023, ENGIE also purchased the biomethane producer Ixora Energy Ltd. This investment is fully consolidated. This transaction had an impact of approximately €0.1 billion on the Group’s net financial debt. 787 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 5 FINANCIAL INDICATORS USED IN FINANCIAL COMMUNICATION ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
56 NOTE 5 FINANCIAL INDICATORS USED IN FINANCIAL
COMMUNICATION
The purpose of this note is to present the main non-GAAP financial indicators used by the Group as well as their reconciliation with the indicators of the IFRS consolidated financial statements.
5.1 EBITDA
The reconciliation between EBITDA and current operating income including operating MtM and share in net income of equity method entities is as follows:
In millions of euros Dec. 31, 2023 Dec. 31, 2022
Current operating income including operating MtM and share in net income of equity method entities 12,493 5,367 Mark-to-market on commodity contracts other than trading instruments (2,430) 3,661 Net depreciation and amortization/Other 4,886 4,576
Share-based payments (IFRS 2) 47 92
Non-recurring share in net income of equity method entities 22 17 EBITDA 15,017 13,713
Nuclear 1,285 1,510
EBITDA excluding Nuclear 13,732 12,204
5.2 EBIT
The reconciliation between EBIT and current operating income including operating MtM and share in net income of equity method entities is as follows:
In millions of euros Dec. 31, 2023 Dec. 31, 2022
Current operating income including operating MtM and share in net income of equity method entities 12,493 5,367 Mark-to-market on commodity contracts other than trading instruments (2,430) 3,661 Non-recurring share in net income of equity method entities 22 17 EBIT 10,084 9,045
Nuclear 605 1,026
EBIT excluding Nuclear 9,479 8,019
788 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 5 FINANCIAL INDICATORS USED IN FINANCIAL COMMUNICATION ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
57 5.3 Net recurring income Group share (NriGs)
Net recurring income Group share is a financial indicator used by the Group in its financial reporting to present net income Group share adjusted for unusual, abnormal or non-recurring items.
The reconciliation of net income/(loss) with net recurring income Group share is as follows:
In millions of euros Notes Dec. 31, 2023 Dec. 31, 2022
NET INCOME/(LOSS) GROUP SHARE 2,208 216
NET INCOME/(LOSS) RELATING TO DISCONTINUED OPERATIONS, GROUP SHARE ‐ 2,182 NET INCOME/(LOSS) RELATING TO CONTINUING OPERATIONS, GROUP SHARE 2,208 (1,965) Net income attributable to non-controlling interests relating to continuing operations 695 172 NET INCOME/(LOSS) RELATING TO CONTINUING OPERATIONS 2,903 (1,793) Reconciliation items between "Current operating income including operating MtM and share in net income of equity method entities" and "Net income/(loss) from operating activities" 6,395 4,241
Impairment losses 9.1 1,318 2,774
Restructuring costs 9.2 47 230
Changes in scope of consolidation 9.3 85 (91)
Other non-recurring items 9.4 4,945 1,328
Other adjusted items (3,092) 3,389
Mark-to-market on commodity contracts other than trading instruments 8 (2,430) 3,661 Ineffective portion of derivatives qualified as fair value hedges 10 ‐ (7) Gains/(losses) on debt restructuring and early unwinding of derivative financial instruments 10 (8) (46) Change in fair value of derivatives not qualified as hedges and ineffective portion of derivatives qualified as cash flow hedges 10 13 (16)
Non-recurring income/(loss) from debt instruments and equity instruments 10 183 1,254 Other adjusted tax impacts (872) (1,474)
Non-recurring income/(loss) included in share in net income of equity method entities 22 17 NET RECURRING INCOME/(LOSS) RELATING TO CONTINUING OPERATIONS 6,206 5,836 Net recurring income/(loss) attributable to non-controlling interests 839 614
NET RECURRING INCOME/(LOSS) RELATING TO CONTINUING OPERATIONS, GROUP SHARE 5,366 5,223
Net recurring income/(loss) relating to discontinued operations, Group share ‐ 287 NET RECURRING INCOME/(LOSS) GROUP SHARE 5,366 5,510
789 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 5 FINANCIAL INDICATORS USED IN FINANCIAL COMMUNICATION ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
58 5.4 Industrial capital employed
The reconciliation of industrial capital employed with items in the statement of financial position is as follows:
In millions of euros Dec. 31, 2023 Dec. 31, 2022
(+) Property, plant and equipment and intangible assets, net 66,399 62,853 (+) Goodwill 12,864 12,854
(-) Goodwill Gaz de France - SUEZ and International Power (1) (7,229) (7,241) (+) IFRS 16 and IFRIC 12 receivables 3,348 2,521
(+) Investments in equity method entities 9,213 9,279
(-) Goodwill arising on the International Power combination (1) (39) (40) (+) Financial assets covering nuclear provisions (2) 9,984 6,626 (+) Initial Margins (2) 1,276 1,741
(+) Trade and other receivables, net 20,092 31,310
(-) Margin calls (1) (3) (3,207) (5,405)
(+) Inventories 5,343 8,145
(+) Assets from contracts with customers 9,531 12,584
(+) Other current and non-current assets 14,414 19,060
(+) Deferred tax (3,658) (4,379)
(+) Cancellation of deferred tax on other recyclable items (1) (3) (745) (14) (-) Provisions (32,593) (27,027)
(+) Actuarial gains and losses in shareholders' equity (net of deferred tax) (1) 1,500 1,058 (-) Trade and other payables (22,976) (39,801)
(+) Margin calls (1) (3) 3,269 6,351
(-) Liabilities from contracts with customers (4,053) (3,412) (-) Other current and non-current liabilities (21,777) (27,279) INDUSTRIAL CAPITAL EMPLOYED 60,957 59,782
(1) For the purpose of calculating industrial capital employed, the amounts recorded in respect of these items have been adjusted from those appearing in the statement of financial position. (2) The Group changed the definition of industrial capital employed from January 1, 2023 to include financial assets hedging nuclear provisions and Initial Margins required by certain market activities. (3) Margin calls included in “Trade and other receivables, net” and “Trade and other payables” correspond to advances received or paid as part of collateralization agreements set up by the Group to manage counterparty risk on commodity transactions.
5.5 Cash flow from operations (CFFO)
The reconciliation of cash flow from operations (CFFO) with items in the statement of cash flows is as follows:
In millions of euros Dec. 31, 2023 Dec. 31, 2022
Cash generated from operations before income tax and working capital requirements 14,407 12,415 Tax paid (1,687) (1,504)
Change in working capital requirements 397 (2,424)
Interest received on financial assets 118 (37)
Dividends received on equity investments 9 18
Interest paid (1,058) (822)
Interest received on cash and cash equivalents 569 194
Nuclear - expenditure on power plant dismantling and reprocessing, fuel storage 321 163 Change in financial assets held for investment or financing purposes 15 188 (+) Change in financial assets held for investment or financing purposes recorded in the statement of financial position and other (15) (176)
CASH FLOW FROM OPERATIONS (CFFO) 13,075 8,016
790 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 5 FINANCIAL INDICATORS USED IN FINANCIAL COMMUNICATION ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
59 5.6 Capital expenditure (CAPEX) and growth CAPEX
The reconciliation of capital expenditure (CAPEX) with items in the statement of cash flows is as follows:
In millions of euros Dec. 31, 2023 Dec. 31, 2022
Acquisitions of property, plant and equipment and intangible assets 7,328 6,379 Acquisitions of controlling interests in entities, net of cash and cash equivalents acquired 1,392 289 (+) Cash and cash equivalents acquired 204 14
Acquisitions of investments in equity method entities and joint operations 237 407 Acquisitions of equity and debt instruments 1,675 (175) Change in loans and receivables originated by the Group and other 1,585 2,877 (+) Other ‐ (10)
(-) Disposal impacts relating to DBSO (1) activities (62) (472) (-) Financial investments Synatom / Disposal of financial assets Synatom (3,082) (1,822) (+) Change in scope - Acquisitions 1,338 371
TOTAL CAPITAL EXPENDITURE (CAPEX) 10,614 7,858
(-) Maintenance CAPEX (2,524) (2,373)
TOTAL GROWTH CAPEX 8,090 5,485
(1) Develop, Build, Share & Operate; including Tax equity financing received (See Note 22 “Working capital requirements, inventories, other assets and other liabilities”).
5.7 Net financial debt
The reconciliation of net financial debt with items in the statement of financial position is as follows:
In millions of euros Notes Dec. 31, 2023 Dec. 31, 2022
(+) Long-term borrowings 14.2 & 14.3 37,920 28,083
(+) Short-term borrowings 14.2 & 14.3 9,367 12,508
(+) Derivative instruments - carried in liabilities 14.4 24,561 51,276 (-) Derivative instruments hedging commodities and other items (23,973) (50,542) (-) Other financial assets 14.1 (16,987) (12,992)
(+) Loans and receivables at amortized cost not included in net financial debt 8,891 6,720 (+) Equity instruments at fair value 2,124 1,495
(+) Debt instruments at fair value not included in net financial debt 4,558 3,394 (-) Cash and cash equivalents 14.1 (16,578) (15,570)
(-) Derivative instruments - carried in assets 14.4 (21,245) (48,386) (+) Derivative instruments hedging commodities and other items 20,854 48,067 NET FINANCIAL DEBT 29,493 24,054
791 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 5 FINANCIAL INDICATORS USED IN FINANCIAL COMMUNICATION ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
60 5.8 Economic net debt
Economic net debt is as follows:
In millions of euros Notes Dec. 31, 2023 Dec. 31, 2022
NET FINANCIAL DEBT 14.3 29,493 24,054
Provisions for back-end of the nuclear fuel cycle and dismantling of nuclear facilities 17 23,887 19,017 Other nuclear liabilities (1) 17 816 ‐
Provisions for dismantling of non-nuclear facilities 17 1,384 1,330 Post-employment benefits - Pensions 18 957 452
(-) Infrastructures regulated companies 253 272
Post-employment benefits - Reimbursement rights 18 (242) (208) Post-employment benefits - Other benefits 18 3,962 3,704 (-) Infrastructures regulated companies (2,578) (2,392) Deferred tax assets for pensions and related obligations 11 (1,013) (812) (-) Infrastructures regulated companies 541 490
Plan assets relating to nuclear provisions, inventories of uranium and receivables of Electrabel towards EDF (1) 17 & 22
(10,944) (7,098)
ECONOMIC NET DEBT 46,517 38,808
(1) Following the agreements with the Belgian government on the extension of the Tihange 3 and Doel 4 nuclear reactors and on all obligations related to nuclear waste, economic net debt now includes all existing nuclear liabilities, including payables and receivables previously recognized under working capital. The impact on the indicator at December 31, 2022 would have been an increase in economic net debt of around € 556 million.
792 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 6 SEGMENT INFORMATION
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
61 NOTE 6 SEGMENT INFORMATION
6.1 Operating segment and reportable segment
ENGIE is organized around:
• four Global Business Units (GBUs) representing the Group’s four strategic activities: Renewables GBU, Networks GBU, Energy Solutions GBU, and FlexGen & Retail GBU;
• two operating entities: Nuclear and Global Energy Management & Sales (“GEMS”); • an Other group mainly comprising the Corporate functions and certain Holdings.
The reportable segments are identical to the operating segments and correspond to the activities of the GBUs. • Renewables: comprises all centralized renewable energy generation activities, including financing, construction, operation and maintenance of renewable energy facilities, using various energy sources such as hydroelectric, onshore wind, photovoltaic solar, offshore wind, and battery storage combined with a renewable asset. The energy produced is fed into the grid and sold either on the open or regulated market or to third parties through electricity sale agreements.
• Networks: comprises the Group’s electricity and gas infrastructure activities and projects. These activities include the management and development of (i) gas and electricity transportation networks and natural gas distribution networks in and outside of Europe, (ii) underground natural gas storage in Europe, and (iii) regasification infrastructure in France and Chile. Apart from the historical infrastructure management activities, its asset portfolio also contributes to energy decarbonization and network greening (gradual integration of green gas, hydrogenbased projects, etc.). • Energy Solutions: encompasses the construction and management of decentralized energy networks to produce energy (heating and cooling networks, distributed power generation plants, distributed solar power parks, lowcarbon mobility, low-carbon cities and public lighting, etc.) and related services (energy efficiency, technical maintenance, sustainable development consulting).
• FlexGen: includes activities to compensate for the intermittent nature of renewable energy by providing upstream flexibility (flexible thermal generation and electricity, pumping or battery storage) and downstream flexibility (shaving or shifting consumption for BtoC customers). They also provide solutions for decarbonizing industry with low-carbon hydrogen. The GBU plays a key role in the energy transition. It also includes the financing, construction and operation of desalination plants, whether or not coupled with power generation plants. • Retail: encompasses all the Group’s activities relating to the sale of gas and electricity to end customers, whether professional or individual. It also includes all the Group’s activities in services for residential clients. • Nuclear: encompasses all of the Group’s nuclear activities, with seven reactors in Belgium (four in Doel and three in Tihange) among which five in operation and drawing rights in France. • Others: encompasses the activities of GEMS as well as Corporate and holding companies. The GEMS operating entity is responsible, at the global level, for the supply of energy and the management of risk and optimization of assets on the markets. It sells energy to companies and offers energy management services and solutions to support the decarbonization of the Group and its customers. 793 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 6 SEGMENT INFORMATION
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
62 6.2 Key indicators by reportable segment
REVENUES
Dec. 31, 2023 Dec. 31, 2022 (1)
In millions of euros
External
revenues
Intra-Group
Revenues Total
External
revenues
Intra-Group
Revenues Total
Renewables 5,512 172 5,684 6,216 136 6,352
Networks 6,873 1,032 7,905 6,961 961 7,922
Energy Solutions 11,033 381 11,414 11,441 262 11,703
FlexGen 5,264 2,508 7,772 7,126 1,144 8,271
Retail 16,443 367 16,810 16,810 534 17,344
Nuclear 118 2,325 2,444 35 2,653 2,688
Others 37,322 6,808 44,129 45,277 2,007 47,283
Of which GEMS (2) 37,221 6,776 43,997 45,137 1,979 47,115 Elimination of internal transactions ‐ (13,593) (13,593) ‐ (7,697) (7,697) TOTAL REVENUES 82,565 ‐ 82,565 93,865 ‐ 93,865
(1) Certain internal reclassifications, which have no impact on the total, have been made between the business lines at January 1, 2023.
The main internal reclassifications concern the transfer of EV Box from Energy Solutions to Others. (2) Of which a negative price effect of around €6.3 billion compared to 2022.
EBITDA
In millions of euros Dec. 31, 2023 Dec. 31, 2022 (1)
Renewables 2,665 2,202
Networks 4,151 4,212
Energy Solutions 868 985
FlexGen 1,929 2,235
Retail 821 259
Others 3,297 2,310
Of which GEMS 3,829 2,837
TOTAL EBITDA excluding Nuclear 13,732 12,204
Nuclear 1,285 1,510
TOTAL EBITDA 15,017 13,713
(1) Certain internal reclassifications, which have no impact on the total, have been made between the business lines at January 1, 2023.
The main internal reclassifications concern the transfer of EV Box from Energy Solutions to Others.
EBIT
In millions of euros Dec. 31, 2023 Dec. 31, 2022 (1)
Renewables 2,005 1,627
Networks 2,265 2,371
Energy Solutions 386 523
FlexGen 1,513 1,768
Retail 569 (6)
Others 2,741 1,736
Of which GEMS 3,551 2,618
TOTAL EBIT excluding Nuclear 9,479 8,019
Nuclear 605 1,026
TOTAL EBIT 10,084 9,045
(1) Certain internal reclassifications, which have no impact on the total, have been made between the business lines at January 1, 2023.
The main internal reclassifications concern the transfer of EV Box from Energy Solutions to Others. 794 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 6 SEGMENT INFORMATION
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
63 SHARE IN NET INCOME/(LOSS) OF EQUITY METHOD ENTITIES In millions of euros Dec. 31, 2023 Dec. 31, 2022
Renewables 203 217
Networks 446 323
Energy Solutions 22 118
FlexGen 355 397
Retail ‐ ‐
Nuclear ‐ ‐
Others 40 4
Of which GEMS 32 (1)
TOTAL SHARE IN NET INCOME/(LOSS) OF EQUITY METHOD ENTITIES 1,066 1,059 Associates and joint ventures accounted for €486 million and €580 million respectively in the share of net income of equity method entities at December 31, 2023 (compared to €400 million and €659 million at December 31, 2022).
INDUSTRIAL CAPITAL EMPLOYED
In millions of euros Dec. 31, 2023 Dec. 31, 2022
Renewables 20,001 16,588
Networks 25,198 25,221
Energy Solutions 7,593 7,575
FlexGen 9,289 8,091
Retail 390 1,023
Nuclear (11,210) (9,855)
Others 9,696 11,139
Of which GEMS 6,596 9,060
TOTAL INDUSTRIAL CAPITAL EMPLOYED 60,957 59,782
CAPITAL EXPENDITURE
In millions of euros Dec. 31, 2023 31 déc. 2022 (1)
Renewables 4,130 3,333
Networks 2,173 2,322
Energy Solutions 1,102 864
FlexGen 2,135 481
Retail 247 270
Nuclear 174 229
Others 652 360
Of which GEMS 182 149
TOTAL CAPEX 10,614 7,858
(1) Certain internal reclassifications, which have no impact on the total, have been made between the business lines at January 1, 2023.
The main internal reclassifications concern the transfer of EV Box from Energy Solutions to Others.
GROWTH CAPEX
In millions of euros Dec. 31, 2023 Dec. 31, 2022 (1)
Renewables 3,966 3,202
Networks 839 1,087
Energy Solutions 897 694
FlexGen 1,843 220
Retail 160 173
Nuclear 19 1
Others 368 108
Of which GEMS 82 63
TOTAL GROWTH CAPEX 8,091 5,485
(1) Certain internal reclassifications, which have no impact on the total, have been made between the business lines at January 1, 2023. The main internal reclassifications concern the transfer of EV Box from Energy Solutions to Others. 795 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 6 SEGMENT INFORMATION
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
64 6.3 Key indicators by geographic area
The amounts set out below are analyzed by:
• destination of products and services sold for revenues; • geographic location of consolidated companies for industrial capital employed.
Revenues Industrial capital employed
In millions of euros Dec. 31, 2023 Dec. 31, 2022 Dec. 31, 2023 Dec. 31, 2022 France 36,676 34,248 32,802 33,912
Belgium 8,408 12,705 (9,259) (7,575)
Other EU countries 18,303 22,687 9,713 9,261
Other European countries 4,480 4,202 1,991 1,610
North America 5,329 6,133 8,989 7,264
Asia, Middle East & Oceania 4,366 8,875 3,830 3,667
South America 4,715 4,778 11,212 11,095
Africa 289 237 1,679 548
TOTAL 82,565 93,865 60,957 59,782
Due to the variety of its businesses and their geographical location, the Group operates in a very diverse range of situations and for a variety of customer types (industry, local authorities and individual customers). Accordingly, no external customer represents individually 10% or more of the Group’s consolidated revenues. 796 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 7 REVENUES
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
65 NOTE 7 REVENUES
7.1 Revenues
Accounting standards
Revenues from contracts with customers concern revenues from contracts that fall within the scope of IFRS 15 – Revenue from Contracts with Customers. Revenues are recognized when the customer obtains control of goods or services promised in the contract, for the amount of consideration to which an entity expects to be entitled in exchange for said promised goods or services.
A contractual analysis of the Group’s sale contracts has led to the application of the following revenue recognition principles:
• Gas, electricity and other energies
Revenues from sales of gas, electricity and other energies are recognized upon delivery of the power to the retail, business or industrial customer.
Power deliveries are monitored in real time or on a deferred basis for those customers whose energy consumption is metered during the accounting period, in which case the portion of not yet metered revenues “in the meter” is estimated on the closing date.
• Gas, electrical and other energy infrastructures
Revenues derived by gas and electricity infrastructure operators upon providing transportation or distribution or storage capacities, are recognized on a straight-line basis over the contract term.
In the countries where the Group acts as an energy provider (supplier) without being in charge of its distribution or transportation, mainly in France and Belgium, an analysis of the energy sales contracts and of the related regulatory framework is carried out to determine whether the distribution or transportation services invoiced to the customers have to be excluded from the revenues recognized under IFRS 15.
Judgment may be exercised by the Group for this analysis in order to determine whether the energy provider acts as an agent or a principal for the gas or electricity distribution or transportation services re-invoiced to the customers. The main criteria used by the Group to exercise its judgment and conclude, in certain countries, that the energy provider acts as an agent of the infrastructure operator are as follows: who is primarily responsible for fulfillment of the distribution or transportation services? Does the energy provider have the ability to commit to capacity reservation contracts towards the infrastructure operator? To what extent does the energy provider have discretion in establishing the price for the distribution or transportation services? • Constructions, installations, Operations and Maintenance (O&M) Construction and installation contracts mainly concern assets built on the premises of customers such as cogeneration units, heaters or other energy-efficiency assets. The related revenues are usually recognized according to the percentage of completion on the basis of the costs incurred where the contracts fall within the scope of IFRS 15.
O&M contracts generally require the Group to perform services ensuring the availability of power generating facilities. These services are performed over time and the related revenues are recognized according to the percentage of completion on the basis of the costs incurred.
If it is not possible to conclude from the contractual analysis that the contract falls within the scope of IFRS 15, the revenues are accounted for as non-IFRS 15 revenues.
Revenues from other contracts, corresponding to revenues from operations that do not fall within the scope of IFRS 15, presented in the “Others” column include trading, lease and concession income, as well as any financial component of operating services, and the effects of the tariff shield mechanisms 797 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 7 REVENUES
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
66 The table below shows a breakdown of revenues by type:
In millions of euros Sales of gas
Sales of
electricity
and other
energies
Sales of
services
linked to
infrastructures
Constructions,
installations,
and O&M Others Dec. 31, 2023
Renewables ‐ 5,010 106 261 135 5,512
Networks 138 5 6,068 434 228 6,873
Energy Solutions 268 4,163 88 6,434 80 11,033
FlexGen 92 4,332 274 400 166 5,264
Retail 7,631 6,229 82 1,003 1,497 16,443
Nuclear ‐ 4 7 28 79 118
Others 13,943 19,619 246 142 3,372 37,322
Of which GEMS 13,943 19,619 241 46 3,372 37,221
TOTAL REVENUES 22,072 39,362 6,872 8,703 5,557 82,565
The significant change in natural gas and electricity prices has led some governments to introduce a “tariff shield” for natural gas and electricity, particularly in France and Romania.
The measures having the most significant impact on the Group's consolidated financial statements are those introduced by the French government for natural gas and electricity. The Finance Act for 2023 (Law no. 2022-1726 of December 30, 2022) extended and modified the tariff shield arrangements for gas (until June 30, 2023) and electricity (until January 31, 2024). The loss of revenue borne by ENGIE constitutes an expense attributable to public service obligations, and is subject to State-guaranteed compensation calculated in accordance with the application procedures published by the French Energy Regulatory Commission (Commission de Régulation de l'Énergie).
These effects are mainly included in the “Others” column (“Revenues excluding IFRS 15”) of the “Retail” business.
In millions of euros Sales of gas
Sales of
electricity
and other
energies
Sales of
services
linked to
infrastructures
Constructions,
installations,
and O&M Others Dec. 31, 2022
Renewables ‐ 5,797 88 242 89 6,216
Networks 232 1 6,021 478 230 6,961
Energy Solutions 246 4,713 96 6,424 73 11,552
FlexGen 22 4,522 1,601 396 588 7,129
Retail 7,793 5,372 153 958 2,534 16,810
Nuclear ‐ 5 8 24 (3) 35
Others 21,405 19,595 170 70 3,923 45,163
Of which GEMS 21,405 19,595 170 45 3,923 45,137
TOTAL REVENUES 29,697 40,004 8,135 8,593 7,435 93,865
.
798 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 7 REVENUES
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
67 7.2 Trade and other receivables, assets and liabilities from contracts with customers
Accounting standards
On initial recognition, trade and other receivables are recorded at their transaction price as defined in IFRS 15.
A contract asset is an entity’s right to consideration in exchange for goods or services that have been transferred to a customer but for which payment is not yet due or is contingent on the satisfaction of a specific condition stipulated in the contract. When an amount becomes due, it is transferred to receivables.
A receivable is recorded when the entity has an unconditional right to consideration. A right to consideration is unconditional if only the passage of time is required before payment of that consideration.
A contract liability is an entity’s obligation to transfer goods or services to a customer for which the entity has already received consideration from the customer. The liability is derecognized upon recognition of the corresponding revenue.
Trade and other receivables and assets from contracts with customers are tested for impairment in accordance with the provisions of IFRS 9 on expected credit losses.
The impairment model for financial assets is based on the expected credit loss model. To calculate expected losses, the Group uses a matrix for trade receivables and assets from contracts with customers, for which the change in credit risk is monitored on a portfolio basis. The change in credit risk of for large customers and other large counterparties is monitored on an individual basis.
See Note 15 “Risks arising from financial instruments” for the Group’s assessment of counterparty risk.
7.2.1 Trade and other receivables and assets from contracts with customers In millions of euros Dec. 31, 2023 Dec. 31, 2022
Trade and other receivables, net 20,092 31,310
Of which IFRS 15 8,083 7,587
Of which non-IFRS15 12,009 23,723
Assets from contracts with customers 9,531 12,584
Accrued income and unbilled revenues 6,989 9,513
Energy in the meter (1) 2,542 3,071
(1) Net of advance payments.
In 2023, the most significant assets from contracts mainly concerned GEMS (€3,766 million), Energy Solutions (€2,516 million) and Retail (€1,922 million).
Dec. 31, 2023 Dec. 31, 2022
In millions of euros Gross
Allowances
and
expected
credit
losses Net Gross
Allowances
and
expected
credit
losses Net
Trade and other receivables, net 22,160 (2,068) 20,092 33,282 (1,973) 31,310 Assets from contracts with customers 9,558 (27) 9,531 12,632 (48) 12,584 TOTAL 31,718 (2,095) 29,623 45,914 (2,020) 43,894
799 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 7 REVENUES
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
68 Gas and electricity in the meter
For customers whose energy consumption is metered during the accounting period, the gas supplied but not yet metered at the reporting date is estimated based on historical data, consumption statistics and estimated selling prices.
For sales on networks used by a large number of grid operators, the Group is allocated a certain volume of energy transiting through the networks by the grid managers. As the final allocations are sometimes only known several months down the line, revenue figures cannot be determined with absolute certainty. However, the Group has developed measuring and modeling tools allowing it to estimate revenues with a reasonable degree of accuracy and subsequently ensure that risks of error associated with estimating quantities sold and the related revenues can be considered as immaterial.
In France and Belgium, un-metered revenues (“gas in the meter”) are calculated using a direct method taking into account customers’ estimated consumption based on the last invoice or metering not yet billed. These estimates are in line with the volume of energy allocated by the grid managers over the same period. The average price is used to measure “gas in the meter” and takes account of the category of customer and the age of the delivered unbilled “gas in the meter”. The portion of unbilled revenues at the reporting date varies according to the assumptions about volume and average price. “Electricity in the meter” is also determined using a direct allocation method similar to that used for gas, but taking into account specific factors related to electricity consumption. It is also measured on a customer-by-customer basis or by customer type.
Realized but not yet metered revenues (“un-metered revenues”) mainly related to France and Belgium for an amount of €5,279 million at December 31, 2023 (€5,883 million at December 31, 2022).
7.2.2 Liabilities from contracts with customers
Dec. 31, 2023 Dec. 31, 2022
In millions of euros Non-current Current Total Non-current Current Total Liabilities from contracts with customers 93 3,960 4,053 121 3,292 3,412 Advances and downpayments received 23 2,998 3,020 53 2,201 2,253 Deferred revenues 71 963 1,033 68 1,091 1,159
In 2023, the Global Business Units reporting the greatest amounts of liabilities from contracts with customers were Retail (€1,563 million) and Energy Solutions (€1,638 million).
7.3 Revenues relating to performance obligations not yet satisfied Revenues relating to performance obligations only partially satisfied at December 31, 2023 amounted to €867 million. They mainly concern Energy Solutions (€849 million) which handle a large number of construction, installation, and maintenance contracts under which revenues are recognized over time. 800 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 8 OPERATING EXPENSES
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
69 NOTE 8 OPERATING EXPENSES
Accounting standards
Operating expenses include:
• purchases and operating derivatives including:
− the purchase of commodities and associated costs (infrastructure, transport, storage, etc.), − the realized impact, as well as the change in fair value (MtM), of commodity transactions, with or without physical delivery, that fall within the scope of IFRS 9 – Financial Instruments and that do not qualify as trading or hedging. These contracts are set up as part of economic hedges of operating transactions in the energy sector;
• purchases of services and other items such as subcontracting and interim expenses, lease expenses (shortterm lease contracts, leases with a low underlying asset value or leases with variable expenses), concession expenses, etc.;
• personnel costs;
• depreciation, amortization, and provisions; and
• taxes.
8.1 Purchases and operating derivatives
In millions of euros Dec 31, 2023 Dec 31, 2022
Purchases and other income and expenses on operating derivatives other than trading (1) (49,650) (67,676) Service and other purchases (2) (7,342) (6,860)
PURCHASES AND OPERATING DERIVATIVES (56,992) (74,535)
(1) Of which net income of €2,430 million in 2023 relating to MtM on commodity contracts other than trading (compared to a net expense of €3,661 million in 2022), notably on certain economic gas and electricity hedging positions not documented as cash flow hedges. (2) Of which €75 million in lease expenses not included in the IFRS 16 lease liability (compared to €56 million in lease expenses in 2022).
The decrease in purchases and operating derivatives is mainly due to changes in commodity prices over the period.
8.2 Personnel costs
In millions of euros Notes Dec 31, 2023 Dec 31, 2022
Short-term benefits (7,688) (7,623)
Share-based payments 19 (47) (104)
Costs related to defined benefit plans 18.3.4 (322) (261) Costs related to defined contribution plans 18.4 (92) (91) PERSONNEL COSTS (8,149) (8,078)
801 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 8 OPERATING EXPENSES
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
70 8.3 Depreciation, amortization and provisions
In millions of euros Notes Dec 31, 2023 Dec 31, 2022
Depreciation and amortization 13 (4,886) (4,576)
Net change in write-downs of inventories, trade receivables and other assets (203) (768) Net change in provisions 17 178 157
DEPRECIATION, AMORTIZATION AND PROVISIONS (4,911) (5,187) At December 31, 2023, depreciation and amortization mainly break down as €1,124 million for intangible assets and €3,762 million for property, plant and equipment.
8.4 Taxes
In millions of euros Dec 31, 2023 Dec 31, 2022
TAXES (2,627) (3,380)
Taxes at December 31, 2023 include the Belgian nuclear tax and the inframarginal rent caps from electricity generation for a total of €969 million, including €329 million for the nuclear tax (compared with approximately €1,348 million and €917 million respectively at December 31, 2022). In addition, in 2022, the Group recognized an expense of €308 million corresponding to the exceptional tax on the energy sector introduced by the Italian authorities (the temporary Italian solidarity contribution was recognized in income tax and amounted to €132 million). 802 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 9 OTHER ITEMS OF NET INCOME/(LOSS) FROM OPERATING ACTIVITIES ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
71 NOTE 9 OTHER ITEMS OF NET INCOME/(LOSS) FROM
OPERATING ACTIVITIES
Accounting standards
Other items of Net income/(loss) from operating activities include:
• “Impairment losses”: this line includes impairment losses on goodwill, other intangible assets, property, plant and equipment and investments in entities consolidated using the equity method; • “Restructuring costs”: this line concerns costs corresponding to a restructuring program planned and controlled by management that materially changes either the scope of a business undertaken by the entity, or the manner in which that business is conducted, based on the criteria set out in IAS 37; • “Changes in the scope of consolidation”. This line includes:
− direct costs related to acquisitions of controlling interests, − in a business combination achieved in stages, remeasurement at fair value at the acquisition date of the previously held interest,
− subsequent changes in the fair value of contingent consideration, − gains or losses from disposals of investments which result in a change of consolidation method, as well as any impact from the remeasurement of retained interests with the exception of gains and losses arising from transactions realized in the framework of “Develop, Build, Share & Operate” (DBSO) or “Develop, Share, Build & Operate” (DSBO) business models. As they are part of the recurring rotation of the Group’s capital employed, these transactions are recognized in current operating income subject to certain criteria being met (notably their recurrence).
• “Other non-recurring items”: this line includes other elements of an unusual, abnormal or infrequent nature.
9.1 Impairment losses
In millions of euros Notes Dec. 31, 2023 Dec. 31, 2022
Impairment losses:
Goodwill 13.1 (94) ‐
Property, plant and equipment and other intangible assets 13.2 & 13.3 (1,587) (2,306) Investments in equity method entities and related provisions (72) (536) TOTAL IMPAIRMENT LOSSES (1,753) (2,841)
Reversal of impairment losses:
Property, plant and equipment and other intangible assets 435 67 TOTAL REVERSALS OF IMPAIRMENT LOSSES 435 67
TOTAL (1,318) (2,774)
9.1.1 Impairment losses recognized in 2023
Net impairment losses recognized at December 31, 2023 amounted to €1,318 million and relate notably to:
• renewable energy production assets in North America (€714 million), due to very specific operational difficulties linked to turbine performance on a wind asset, and the fall in long-term market prices affecting certain projects exposed to the SPP market in particular. It should be noted that for these projects, the fall in market prices had a positive impact on the fair value of VPPA (Virtual Power Purchase Agreement) contracts of around €+0.3 billion, 803 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 9 OTHER ITEMS OF NET INCOME/(LOSS) FROM OPERATING ACTIVITIES ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
72 with these mark-to-market changes, over the period covered by these contracts, recognized in operating expenses (see Note 8.1 “Operating expenses”);
• coal-fired generation assets in South America, for which the Group has decided to accelerate decommissioning from end 2025, in line with the Group's decarbonization plan (€515 million); • other production or support assets for less significant amounts taken individually.
In addition, following the review procedure initiated by the Commission for Nuclear Provisions (CNP) in September 2022, the industrial scenario and all the technical and financial assumptions were approved on July 7, 2023. This resulted in a €646 million decrease in the dismantling asset provision (see Note 17 “Provisions”), against a reduction in dismantling assets. Given the impairment losses recognized on some of these assets at the end of the last year, an impairment reversal of €400 million was recorded in 2023.
These impairment losses mainly concern property, plant and equipment and intangible assets. Considering the effects of deferred taxes and the portion of impairment losses attributable to non-controlling interests, the impact of the impairment losses on net income Group share amounted to €642 million.
With the exception of the effects of decisions to dispose of non-strategic assets, no impairment losses were recognized on non-financial assets as a result of measures to prevent or mitigate climate risks or to achieve the 2045 net zero-carbon objective.
Impairment tests are carried out in accordance with the procedures described in Note 13.4.
9.1.2 Impairment losses recognized in 2022
Net impairment losses recognized at December 31, 2022 amounted to €2,774 million and related mainly to:
• the effects of the triennial revision of nuclear provisions on assets to be recognized against nuclear power plant dismantling provisions;
• the effects of the ongoing program to exit coal activities; • the consequences of negotiations initiated or finalized during the year in connection with the renegotiation of PPA contracts or the disposal of non-strategic assets.
9.2 Restructuring costs
In 2023, restructuring costs totaled € 47 million (versus €230 million in 2022). Restructuring costs in both years mainly included costs related to staff reduction plans and measures to adapt to the economic situation in 2023 and 2022, as well as the shutdown or sale of operations, the closure or restructuring of certain facilities as well as other miscellaneous restructuring costs.
9.3 Changes in scope of consolidation
At December 31, 2023, the impact of changes in the scope of consolidation was a negative €85 million and mainly comprised the disposal of a coal-fired generation unit in Brazil (a negative €47 million).
At December 31, 2022, the impact of changes in the scope of consolidation was a positive €91 million and mainly comprised:
• a positive impact of €280 million relating to the disposal of shares held in Gaztransport et Technigaz (GTT) for a total representing approximately 24.6% of its share capital. This result includes the effects of the almost full conversion of the exchangeable bond issued by the Group in June 2021; • a positive impact of €111 million relating to the disposal of geothermal assets in Indonesia; • a negative impact of €127 million relating to the disposal of the Energy Solutions activities in Africa and France; 804 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 9 OTHER ITEMS OF NET INCOME/(LOSS) FROM OPERATING ACTIVITIES ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
73 • a negative impact of €110 million relating to the purchase of shares in renewable assets in India with refinancing obligations carried out in 2023;
• a negative impact of €63 million relating to miscellaneous disposals that are not individually significant.
9.4 Other non-recurring items
Other non-recurring items amounted to a negative €4,945 million at December 31, 2023 and include the €-4,750 million impact of the revision of nuclear provisions to take account of the agreement reached with the Belgian government on June 29, 2023, which became binding following the signature of the supplements to the initial agreements on July 21, 2023 and whose implementation was specified in the transaction documents signed on December 13, 2023 (see Note 17 “Provisions”). This amount includes the additional provisions set aside under the agreement (€-5.1 billion), diminished by the effects of recognizing the receivable relating to Electrabel's partners' share in certain power plants (€0.4 billion).
Other non-recurring items also include the impact of the revision of the dismantling provision of the Hazelwood site in Australia for around €90 million.
Other non-recurring items at December 31, 2022 totaled a negative €1,328 million and mainly comprised:
• a negative impact of €979 million related to the triennial review of provisions for the management of the back-end nuclear cycle;
• a negative impact of €205 million related to provisions set up to cover clean-up obligations in France; • a negative impact of €161 million related to the write-off of intangible assets and property, plant and equipment, mainly in France.
805 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 10 NET FINANCIAL INCOME/(LOSS)
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
74 NOTE 10 NET FINANCIAL INCOME/(LOSS)
In millions of euros Expense Income
Dec. 31,
2023 Expense Income
Dec. 31,
2022
Interest expense on gross debt and hedges (1,708) - (1,708) (1,104) - (1,104) Cost of lease liabilities (105) ‐ (105) (73) ‐ (73)
Foreign exchange gains/losses on borrowings and hedges (10) ‐ (10) (28) ‐ (28) Ineffective portion of derivatives qualified as fair value hedges ‐ ‐ ‐ ‐ 7 7 Gains and losses on cash and cash equivalents and liquid debt instruments held for cash investment purposes - 596 596 - 197 197 Capitalized borrowing costs 268 - 268 109 - 109
Cost of net debt (1,557) 596 (961) (1,097) 205 (893)
Cash payments made on the unwinding of swaps ‐ - ‐ (9) - (9) Reversal of the negative fair value of these early unwound derivative financial instruments ‐ ‐ ‐ ‐ ‐ ‐
Gains/(losses) on debt restructuring transactions ‐ 8 8 ‐ 55 55 Gains/(losses) on debt restructuring and early unwinding of derivative financial instruments ‐ 8 8 (9) 55 46
Net interest expense on post-employment benefits and other long-term benefits (161) ‐ (161) (92) ‐ (92)
Unwinding of discounting adjustments to other long-term provisions (772) ‐ (772) (617) ‐ (617) Change in fair value of derivatives not qualified as hedges and ineffective portion of derivatives qualified as cash flow hedges (15) ‐ (15) (5) ‐ (5) Income/(loss) from debt instruments and equity instruments (238) ‐ (239) (1,295) 36 (1,258) Interest income on loans and receivables at amortized cost ‐ 106 106 ‐ 69 69 Other (596) 467 (130) (585) 332 (253)
Other financial income and expenses (1,783) 573 (1,210) (2,594) 438 (2,156) NET FINANCIAL INCOME/(LOSS) (3,340) 1,177 (2,163) (3,700) 697 (3,003) In 2023, the average cost of debt after hedging came out at 4.31% compared to 2.73% at December 31, 2022.
Net income/(loss) from debt and equity instruments amounted to a loss of €239 million and mainly included the loss on bonds and money market funds held by Synatom for €-149 million (see Note 17.2.4 “Financial assets set aside to cover the future costs of dismantling nuclear facilities and managing radioactive fissile material”). 806 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 11 INCOME TAX EXPENSE
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
75 NOTE 11 INCOME TAX EXPENSE
Accounting standards
The Group calculates taxes in accordance with prevailing tax legislation in the countries where income is taxable.
In accordance with IAS 12, deferred taxes are recognized according to the liability method on temporary differences between the carrying amounts of assets and liabilities in the consolidated financial statements and their tax bases, using tax rates that have been enacted or substantively enacted by the reporting date. However, under the provisions of IAS 12, no deferred tax is recognized for temporary differences arising from goodwill for which impairment losses are not deductible for tax purposes, or from the initial recognition of an asset or liability in a transaction which (i) is not a business combination and (ii) at the time of the transaction, affects neither accounting income nor taxable income. In addition, deferred tax assets are only recognized to the extent that it is probable that taxable income will be available against which the deductible temporary differences can be utilized.
A deferred tax liability is recognized for all taxable temporary differences associated with investments in subsidiaries, associates, joint ventures and branches, except if the Group is able to control the timing of the reversal of the temporary difference and it is probable that the temporary difference will not reverse in the foreseeable future.
Net balances of deferred taxes are calculated based on the tax position of each company or on the total income of companies included within the relevant consolidated tax group, and are presented in assets or liabilities for their net amount per tax entity.
Deferred taxes are reviewed at each reporting date to take into account factors including the impact of changes in tax laws and the prospects of recovering deferred tax assets arising from deductible temporary differences.
Deferred tax assets and liabilities are not discounted.
Tax effects relating to coupon payments on deeply-subordinated perpetual notes are recognized in profit or loss.
11.1 Actual income tax expense recognized in the income statement
11.1.1 Breakdown of actual income tax expense recognized in the income statement The income tax expense recognized in the income statement for 2023 amounted to €1,031 million (€83 million income tax benefit in 2022). It breaks down as follows:
In millions of euros Dec. 31, 2023 Dec. 31, 2022
Current income taxes (833) (1,762)
Deferred taxes (198) 1,845
TOTAL INCOME TAX BENEFIT/(EXPENSE) RECOGNIZED IN INCOME (1,031) 83 807 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 11 INCOME TAX EXPENSE
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
76 11.1.2 Reconciliation of theoretical income tax expense with actual income tax expense A reconciliation of theoretical income tax expense with the Group’s actual income tax expense is presented below:
In millions of euros Dec. 31, 2023 Dec. 31, 2022
Net income/(loss) 2,903 390
Share in net income of equity method entities 993 523
Net income/(loss) from discontinued operations ‐ 2,183
Income tax expense (1,031) 83
Income/(loss) before income tax of consolidated companies (A) 2,941 (2,400) Of which French companies 1,532 (2,130)
Of which companies outside France 1,409 (270)
Statutory income tax rate of the parent company (B) 25.8% 25.8% THEORETICAL INCOME TAX BENEFIT/(EXPENSE) (C) = (A) X (B) (759) 620 Reconciling items between theoretical and actual income tax expense Difference between statutory tax rate applicable to the parent and statutory tax rate in force in jurisdictions in France and abroad (14) (8)
Permanent differences (1) (120) (313)
Income taxed at a reduced rate or tax-exempt (2) (22) 427 Additional tax expense (3) (60) (327)
Effect of unrecognized deferred tax assets on tax loss carry-forwards and other tax-deductible temporary differences (4) (430) (940)
Recognition or utilization of tax income on previously unrecognized tax loss carry-forwards and other tax-deductible temporary differences (5) 93 643
Impact of changes in tax rates (6) 8 (37)
Tax credits and other tax reductions (7) 360 20
Other (8) (86) (1)
INCOME TAX BENEFIT/(EXPENSE) RECOGNIZED IN INCOME (1,031) 83 (1) Mainly includes disallowable impairment losses on goodwill, disallowed operating expenses and the deduction of interest expenses arising from hybrid debt.
(2) Mainly includes capital gains on disposals of securities exempt from tax or taxed at a reduced rate in some tax jurisdictions, the impact of the specific tax regimes used by some entities, disallowable impairment losses and capital losses on securities, and the impact of untaxed income from remeasuring previously-held (or retained) equity interests in connection with acquisitions and changes in consolidation methods.
(3) Mainly includes tax on dividends resulting from the parent company tax regime, withholding tax on dividends and interest levied in several tax jurisdictions, allocations to provisions for income tax, and regional and flat-rate corporate taxes. In 2022, this line also included the temporary Italian solidarity contribution (€132 million). (4) Includes (i) the cancellation of the net deferred tax asset position for some tax entities in the absence of sufficient profit being forecast and (ii) the impact of disallowable impairment losses on fixed assets. (5) Includes the impact of the recognition of net deferred tax asset positions for some tax entities. (6) Mainly includes the impact of tax rate changes on deferred tax balances in the United Kingdom for 2023 and for 2022. (7) Mainly includes reversals of provisions for tax litigation in Luxembourg, tax credits in France and in Singapore and other tax reductions.
(8) Mainly includes the correction of previous tax charges.
With regard to the future implementation of the OECD Pillar 2 rules, the Group does not have significant operations in countries where a minimum tax may be due, and therefore does not expect from this reform any material impacts on its income tax expense.
808 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 11 INCOME TAX EXPENSE
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
77 11.1.3 Analysis of the deferred tax income/(expense) recognized in the income statement, by type of temporary difference
Impact in the income statement
In millions of euros Dec. 31, 2023 Dec. 31, 2022
Deferred tax assets:
Tax loss carry-forwards and tax credits (103) 1,051
Pension and related obligations (3) (1)
Non-deductible provisions 976 55
Difference between the carrying amount of PP&E and intangible assets and their tax bases (84) 454 Measurement of assets and liabilities at fair value (IAS 32/IFRS 9) (2,373) (1,260) Other 265 (135)
TOTAL (1,322) 164
Deferred tax liabilities:
Difference between the carrying amount of PP&E and intangible assets and their tax bases 61 (545) Measurement of assets and liabilities at fair value (IAS 32/IFRS 9) 1,326 1,781 Other (263) 398
TOTAL 1,124 1,634
DEFERRED TAX INCOME/(EXPENSE) (198) 1,798
Of which continuing activities (198) 1,845
11.2 Deferred tax income/(expense) recognized in “Other comprehensive income”
Net deferred tax income/(expense) recognized in “Other comprehensive income” is broken down by component as follows:
In millions of euros Dec. 31, 2023 Dec. 31, 2022
Equity and debt instruments (6) 33
Actuarial gains and losses 141 (646)
Net investment hedges (41) 11
Cash flow hedges on other items 802 943
Cash flow hedges on net debt 4 (3)
TOTAL EXCLUDING SHARE OF EQUITY METHOD ENTITIES AND DISCONTINUED OPERATIONS 900 338 Share of equity method entities (28) (132)
Discontinued operations ‐ (21)
TOTAL 872 185
11.3 Deferred taxes presented in the statement of financial position
11.3.1 Change in deferred taxes
Changes in deferred taxes recognized in the statement of financial position, after netting deferred tax assets and liabilities by tax entity, break down as follows:
In millions of euros Assets Liabilities Net position
AT DECEMBER 31, 2022 2,029 (6,408) (4,379)
Impact on net income for the year (1,322) 1,124 (198)
Impact on other comprehensive income items 1,559 (665) 894 Impact of changes in scope of consolidation 215 (214) ‐ Impact of translation adjustments (13) 5 (8)
Transfers to assets and liabilities classified as held for sale (4) 4 ‐ Other (210) 243 33
Impact of netting by tax entity (279) 279 ‐
AT DECEMBER 31, 2023 1,974 (5,632) (3,658)
809 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 11 INCOME TAX EXPENSE
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
78 11.3.2 Analysis of the net deferred tax position recognized in the statement of financial position (before netting deferred tax assets and liabilities by tax entity), by type of temporary difference
Accounting standards
Measurement of recognized tax loss carry-forwards
Deferred tax assets are recognized on tax loss carry-forwards when it is probable that taxable profit will be available against which the tax loss carry-forwards can be utilized. The probability that taxable profit will be available against which the unused tax losses can be utilized, is based on taxable temporary differences relating to the same taxation authority and the same taxable entity and estimates of future taxable profits. These estimates and utilizations of tax loss carry-forwards were prepared on the basis of profit and loss forecasts over a six-year tax projection period as included in the medium-term business plan approved by Management, subject to exceptions justified by a particular context and, if necessary, on the basis of additional forecasts.
Statement of financial position at
In millions of euros Dec. 31, 2023 Dec. 31, 2022
Deferred tax assets:
Tax loss carry-forwards and tax credits 2,121 2,202
Pension obligations 1,013 812
Non-deductible provisions 1,485 518
Difference between the carrying amount of PP&E and intangible assets and their tax bases 1,659 1,830 Measurement of assets and liabilities at fair value (IAS 32/IFRS 9) 7,649 8,346 Other 626 620
TOTAL 14,553 14,328
Deferred tax liabilities:
Difference between the carrying amount of PP&E and intangible assets and their tax bases (9,893) (9,873) Measurement of assets and liabilities at fair value (IAS 32/IFRS 9) (7,419) (8,141) Other (897) (693)
TOTAL (18,210) (18,707)
NET DEFERRED TAX ASSETS/(LIABILITIES) (3,658) (4,378)
In accordance with the amendment to IAS 12, no deferred tax is recognized in respect of the future implementation of the OECD Pillar 2 rules.
11.4 Unrecognized deferred taxes
At December 31, 2023, the tax effect of tax losses and tax credits eligible for carry-forward but not utilized and not recognized in the statement of financial position amounted to €4,563 million (€4,165 million at December 31, 2022). Most of these unrecognized tax losses relate to companies based in countries which allow losses to be carried forward indefinitely (mainly Belgium, the Netherlands, Australia, and the United States). These tax losses carried forward did not give rise to the full or partial recognition of a deferred tax asset due to the absence of sufficient profit forecasts in the medium term.
The tax effect of other tax-deductible temporary differences not recorded in the statement of financial position was €1,778 million at end-December 2023 versus €1,590 million at end-December 2022. 810 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 12 EARNINGS PER SHARE
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
79 NOTE 12 EARNINGS PER SHARE
Accounting standards
Basic earnings per share is calculated by dividing net income Group share for the year by the weighted average number of ordinary shares outstanding during the year. The average number of ordinary shares outstanding during the year is the number of ordinary shares outstanding at the beginning of the year, adjusted by the number of ordinary shares bought back or issued during the year.
For the diluted earnings per share calculation, the weighted average number of shares and basic earnings per share are adjusted to take into account the impact of the conversion or exercise of any dilutive potential ordinary shares (options, warrants and convertible bonds, etc.).
In compliance with IAS 33 – Earnings per Share, earnings per share and diluted earnings per share are based on net income/(loss) Group share after deduction of payments to bearers of deeply-subordinated perpetual notes (see Note 16.2.1 “Issuance of deeply-subordinated perpetual notes”).
The Group’s dilutive instruments included in the calculation of diluted earnings per share include bonus shares and performance shares granted in the form of ENGIE securities.
Dec. 31, 2023 Dec. 31, 2022
Numerator (in millions of euros)
Net income/(loss) Group share 2,208 216
Of which Net income/(loss) relating to continuing operations, Group share 2,208 (1,965) Interest from deeply-subordinated perpetual notes (80) (77) Net income/(loss)used to calculate earnings per share 2,129 140 Of which Net income/(loss) relating to continuing operations, Group share, used to calculate earnings per share 2,129 (2,042)
Net recurring income/(loss) Group share 5,366 5,510
Of which Net recurring income/(loss) relating to continuing operations, Group share 5,366 5,223 Interest from deeply-subordinated perpetual notes (80) (77) Net recurring income/(loss)used to calculate earnings per share 5,287 5,433 Of which Net recurring income/(loss) relating to continuing operations, Group share, used to calculate earnings per share 5,287 5,146
Denominator (in millions of shares)
Average number of outstanding shares 2,422 2,420
Impact of dilutive instruments:
Bonus share plans reserved for employees 11 ‐
Diluted average number of outstanding shares 2,433 2,420 Earnings per share (in euros)
Basic earnings/(loss) per share 0.88 0.06
Of which Basic earnings/(loss) Group share relating to continuing operations per share 0.88 (0.84) Diluted earnings/(loss) per share 0.87 0.06
Of which Diluted earnings/(loss) Group share relating to continuing operations per share 0.88 (0.84) Basic recurring earnings/(loss) per share 2.18 2.24
Of which Basic recurring earnings/(loss) Group share relating to continuing operations per share 2.18 2.13 Diluted recurring earnings/(loss) per share (1) 2.17 2.23 Of which Diluted recurring earnings/(loss) Group share relating to continuing operations per share (1) 2.17 2.12 (1) In 2022, the calculation of the denominator included 11 million potential ENGIE shares that had a dilutive effect on the NRIgs and NRIgs relating to continuing operations per share. This effect was not taken into account in the calculation of the NIgs and the NIgs relating to continuing operations per share due to the antidilutive effect on the latter. 811 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 13 FIXED ASSETS
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
80 NOTE 13 FIXED ASSETS
13.1 Goodwill
Accounting standards
Upon a business combination, goodwill is measured as the difference between:
• on the one hand the sum of:
− the consideration transferred;
− the amount of non-controlling interests in the acquiree, and − in a business combination achieved in stages, the acquisition-date fair value of the previously held equity interest in the acquiree;
• on the other hand the net fair value of the identifiable assets acquired and liabilities assumed. The key assumptions and estimates used to determine the fair value of assets acquired and liabilities assumed include the market outlook for the measurement of future cash flows as well as applicable discount rates. These assumptions reflect management’s best estimates at the acquisition date.
The amount of goodwill recognized at the acquisition date cannot be adjusted after the end of the 12-month measurement period.
Goodwill relating to interests in associates is included in the carrying amount of the investment consolidated under the equity method entities.
13.1.1 Movements in the carrying amount of goodwill
In millions of euros Net amount
AT DECEMBER 31, 2022 12,855
Impairment losses (95)
Changes in scope of consolidation and Other 134
Translation adjustments (29)
AT DECEMBER 31, 2023 12,864
13.1.2 Information on goodwill
For the purposes of impairment testing, goodwill is allocated to operating segments, which represent the lowest level at which it is monitored for internal management purposes.
The table below shows the amount of goodwill at December 31, 2023:
In millions of euros Dec. 31, 2023
Networks 5,366
Renewables 2,185
Retail 1,838
Energy Solutions 1,209
FlexGen 1,123
Nuclear 797
Other 346
TOTAL 12,864
812 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 13 FIXED ASSETS
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
81 13.2 Intangible assets
Accounting standards
Initial measurement
Intangible assets are carried at cost less any accumulated amortization and any accumulated impairment losses.
Amortization
Intangible assets are amortized on the basis of the expected pattern of consumption of the estimated future economic benefits embodied in the asset. Amortization is calculated mainly on a straight-line basis over the following useful lives:
Useful life
Main depreciation periods (years) Minimum Maximum
Concession rights 10 30
Customer portfolio 3 20
Other intangible assets 1 50
Intangible assets with an indefinite useful life are not amortized but are tested for impairment annually.
Intangible rights arising on concession contracts
IFRIC 12 – Service Concession Arrangements deals with the treatment to be applied by the concession operator in respect of certain concession arrangements.
For a concession arrangement to fall within the scope of IFRIC 12, usage of the infrastructure must be controlled by the concession grantor. This requirement is satisfied when the following two conditions are met:
• the grantor controls or regulates what services the operator must provide with the infrastructure, to whom it must provide them, and at what price; and
• the grantor controls any residual interest in the infrastructure at the end of the term of the arrangement, for example it retains the right to take back the infrastructure at the end of the concession.
The intangible asset model according to paragraph 17 of IFRIC 12 applies if the operator receives a right (a license) to charge the users, or the grantor, depending on the use made of the public service. There is no unconditional right to receive cash, as the amounts depend on the extent to which the public uses the service.
Concession infrastructures that do not meet the requirements of IFRIC 12 are presented as property, plant and equipment. This is the case of gas distribution infrastructures in France. The related assets are recognized in accordance with IAS 16, given that GRDF operates its network under long-term concession arrangements, most of which are mandatorily renewed upon expiration pursuant to French law No. 46-628 of April 8, 1946.
Research and development costs
Research costs are expensed as incurred.
Development costs are capitalized when the asset recognition criteria set out in IAS 38 are met. Capitalized development costs are amortized over the useful life of the intangible asset. 813 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 13 FIXED ASSETS
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
82 13.2.1 Movements in intangible assets
In millions of euros
Intangible rights
arising on
concession
contracts
Capacity
entitlements Others Total
GROSS AMOUNT
AT DECEMBER 31, 2022 3,630 3,282 13,498 20,410
Acquisitions 269 ‐ 1,143 1,412
Disposals (43) ‐ (271) (315)
Translation adjustments 5 ‐ (52) (46)
Changes in scope of consolidation ‐ ‐ 965 965
Transfer to "Assets classified as held for sale and discontinued operations" ‐ ‐ ‐ ‐ Other 44 11 (59) (4)
AT DECEMBER 31, 2023 3,906 3,293 15,223 22,422
ACCUMULATED AMORTIZATION AND IMPAIRMENT
AT DECEMBER 31, 2022 (1,706) (2,208) (9,131) (13,046)
Amortization (151) (106) (867) (1,124)
Impairment (8) ‐ (42) (51)
Disposals 37 ‐ 180 217
Translation adjustments (1) ‐ 22 21
Changes in scope of consolidation ‐ ‐ (19) (19)
Other (9) ‐ 37 29
AT DECEMBER 31, 2023 (1,838) (2,314) (9,821) (13,973)
CARRYING AMOUNT
AT DECEMBER 31, 2022 1,924 1,074 4,366 7,364
AT DECEMBER 31, 2023 2,067 979 5,403 8,449
In 2023, the net increase in “Intangible assets” was mainly attributable to:
• investments during the period (€1,412 million) relating mainly to intangible assets in progress (€863 million) notably capitalized costs in connection with the renewable business in the United States (€207 million), as information technology projects (€141 million) mainly at corporate ENGIE group level in France, and as investments in the extension and maintenance of transmission and distribution networks (€215 million) mainly in France, and relating to concession contracts in the business of Energy Solutions in France (€269 million); • a net positive impact of changes in the scope of consolidation of €946 million, relating mainly to preliminary purchase price allocation carried out for the acquisition of Broad Reach Power, a US-based company specializing in battery storage (€760 million) and to the acquisition of the group BTE Renewables, a renewable energy producer with wind and solar PV projects in South Africa (€134 million) (see Note 4 “Main changes in the Group structure”); partially offset by:
• amortization (negative €1,124 million);
• impairment losses (negative €51 million).
13.2.2 Capacity entitlements
The Group has acquired capacity entitlements from power stations operated by third parties. These power station capacity rights were acquired in connection with transactions or within the scope of the Group's involvement in financing the construction of certain power stations. In consideration, the Group received the right to purchase a share of the production over the useful life of the underlying assets. These rights are amortized over the useful life of the underlying right, not exceeding 50 years. The Group currently holds rights in the Chooz B and Tricastin power plants in France and in the virtual power plant (VPP) in Italy (2028 maturity).
814 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 13 FIXED ASSETS
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
83 13.2.3 Other
At December 31, 2023, this caption mainly relates to software and licenses for €1,436 million, as well as intangible assets in progress for €1,576 million and intangible assets (client portfolio) acquired for €2,097 million as a result of business combinations and capitalized acquisition costs for customer contracts.
13.2.4 Information regarding research and development costs Research and development activities primarily relate to various studies regarding technological innovation, improvements in plant efficiency, safety, environmental protection, service quality, and the use of energy resources. Research and development priorities are focused on climate change adaptation and mitigation, including renewable energy systems (photovoltaic solar, onshore and offshore wind), the production and use of green gases (hydrogen, biomethane) or the development of decentralized energy infrastructure (district heating and cooling, decentralized solar energy, low carbon cities and mobility).
Capitalized development costs, related to projects in the development phase that meet the criteria for recognition as an intangible asset as defined in IAS 38, totaled €21 million in 2023.
13.3 Property, plant and equipment
Accounting standards
Initial recognition and subsequent measurement
Items of property, plant and equipment are recognized at historical cost less any accumulated depreciation and any accumulated impairment losses.
The carrying amount of these items is not revalued as the Group has elected not to apply the allowed alternative method, which consists of regularly revaluing one or more categories of property, plant and equipment.
Investment subsidies are deducted from the gross value of the assets concerned.
In accordance with IAS 16, the initial cost of the item of property, plant and equipment includes an initial estimate of the costs of dismantling and removing the item and restoring the site on which it is located, when the entity has a present, legal or constructive obligation to dismantle the item or restore the site. A corresponding provision for this obligation is recorded for the amount of the asset component.
Borrowing costs that are directly attributable to the construction of the qualifying asset are capitalized as part of the cost of that asset.
Leases
In accordance with IFRS 16, the Group recognizes a right-of-use asset and a corresponding lease liability with respect to contracts considered as a lease in which the Group acts as lessee, except for leases with a term of 12 months or less (“short-term leases”), and leases for which the underlying asset is of a low value (“low-value asset”). Payments associated with these leases are recognized on a straight-line basis as expenses in profit and loss. The lease contracts in the Group mainly concern real estate, vehicles, LNG vessels, an hydroelectric concession contract and other equipment.
The right-of-use asset is initially measured at cost, which comprises the initial amount of the lease liability adjusted for any lease payments made at or before the commencement date, plus any initial direct costs incurred and an estimate of costs to dismantle and remove the underlying asset or to restore the underlying asset or the site on which it is located, less any lease incentives received.
815 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 13 FIXED ASSETS
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
84 The lease liability is initially measured at the present value of the remaining lease payments, discounted using the lessee’s incremental borrowing rate. This rate is calculated based on the Group’s incremental borrowing rate adjusted in accordance with IFRS 16, taking into account (i) the economic environment of the subsidiaries, and in particular their credit risk, (ii) the currency in which the contract is concluded and (iii) the duration of the contract at inception (or the remaining duration for contracts existing upon the initial application of IFRS 16). The methodology applied to determine the incremental borrowing rate reflects the profile of the lease payments (duration method).
The lease term is assessed, including whether a renewal option is reasonably certain to be exercised or a termination option is reasonably certain not to be exercised, on a case-by-case basis. The lease term is reassessed if a significant event or a significant change in circumstances that is within the control of the lessee occurs and may affect the assessment made. In determining the enforceable period of a lease, the Group applies a broad interpretation of the term penalty and takes into consideration not only contractual penalties arising from termination, but also ancillary costs that could arise in case of an early termination of the lease.
Cushion gas
“Cushion” gas stored in underground storage facilities is essential for ensuring that reservoirs can be operated effectively, and is therefore inseparable from these reservoirs. Unlike “working” gas which is included in inventories (see Note 22.2 “Inventories”), cushion gas is reported in other property, plant and equipment.
Depreciation
In accordance with the components approach, each significant component of an item of property, plant and equipment with a different useful life from that of the main asset to which it relates is depreciated separately over its own useful life.
Property, plant and equipment is depreciated mainly using the straight-line method over the following useful lives:
Useful life
Main depreciation periods (years) Minimum Maximum
Plant and equipment
⚫ Storage - Production - Transport - Distribution 5 60(*) ⚫ Installation – Maintenance 3 10
⚫ Hydraulic plant and equipment 20 65
Solar and wind farms 25 30
Other property, plant and equipment 2 33
(*) Excluding cushion gas.
The range of useful lives is due to the diversity of the assets in each category. The minimum periods relate to smaller equipment and furniture, while the maximum periods concern network infrastructures and storage facilities.
Fixtures and fittings relating to hydro plants operated by the Group are depreciated over the shorter of the contract term and the useful life of the assets, taking into account the renewal of the concession period if such renewal is considered to be reasonably certain.
The right-of-use asset related to leases is depreciated using the straight-line method from the commencement date to the end of the lease term, unless the lease transfers ownership of the underlying asset to the Group by the end of the lease term. In that case the right-of-use asset is depreciated over the useful life of the underlying asset, which is determined on the same basis as that used for property, plant and equipment mentioned above. 816 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 13 FIXED ASSETS
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
85 13.3.1 Movements in property, plant and equipment
In millions of euros Land Buildings
Plant and
equipment Vehicles
Dismantling
costs
Assets in
progress
Right
of use Other Total
GROSS AMOUNT
AT DECEMBER 31, 2022 649 2,762 96,016 304 6,038 5,649 5,094 1,319 117,831 Acquisitions/Increases 10 12 711 32 ‐ 5,921 700 38 7,425 Disposals (2) (18) (821) (20) (8) (23) (280) (166) (1,338) Translation adjustments (3) (12) (290) (1) (13) (86) (72) (13) (490) Changes in scope of consolidation 3 ‐ 971 2 2 186 8 2 1,176 Transfer to "Assets classified as held for sale
and discontinued operations" ‐ ‐ (2) ‐ ‐ ‐ ‐ ‐ (3)
Other 16 20 4,715 11 (624) (4,930) 3 18 (771)
AT DECEMBER 31, 2023 673 2,765 101,300 328 5,395 6,716 5,454 1,198 123,829
ACCUMULATED DEPRECIATION AND IMPAIRMENT
AT DECEMBER 31, 2022 (153) (1,772) (52,709) (226) (4,155) (724) (1,710) (895) (62,343) Depreciation (4) (69) (2,727) (28) (364) ‐ (489) (82) (3,762) Impairment ‐ (1) (1,474) ‐ 403 (50) (10) (1) (1,133)
Disposals ‐ 18 763 18 4 6 299 165 1,272
Translation adjustments ‐ 5 161 1 7 4 20 7 204
Changes in scope of consolidation ‐ ‐ (172) (2) ‐ ‐ 2 (1) (173) Transfer to "Assets classified as held for sale
and discontinued operations" ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
Other (1) 26 (148) (3) (362) 535 (5) 14 56
AT DECEMBER 31, 2023 (158) (1,793) (56,306) (239) (4,467) (229) (1,893) (794) (65,879)
CARRYING AMOUNT
AT DECEMBER 31, 2022 497 991 43,307 78 1,883 4,925 3,384 424 55,488 AT DECEMBER 31, 2023 516 971 44,993 90 928 6,487 3,561 404 57,950 In 2023, the net increase in “Property, plant and equipment” essentially takes into account:
• maintenance and development investments for a total amount of €6,724 million mainly related to the construction and the development of wind and solar farms primarily in France, the United States, Latin America and Poland (€3,450 million), as well as to the extension of the transportation and distribution networks in France, Romania and Latin America (€1,765 million), to FlexGen operating segment assets (€868 million) and to Energy Solutions operating activities (€437 million);
• a net positive impact of changes in the scope of consolidation of €1,003 million, relating mainly to the acquisition of Broad Reach Power, a US-based company specialized in battery storage (€531 million), the acquisition of BTE Renewables, one of Africa's leading renewable energy companies based in South Africa (€311 million) and the acquisition of Ixora in the UK (€22 million) in the Networks operating segment; offset by:
• depreciation for a total amount of €3,762 million;
• a €646 million decrease in dismantling assets following the adoption of the industrial scenario and of all the technical and financial assumptions which were approved by the Commission for Nuclear Provisions (CNP) on July 7, 2023 at the end of the review procedure initiated in September 2022. This decrease was partially offset by a €403 million reversal of impairment on some of these assets (see Note 13.4 “Impairment testing of goodwill, intangible assets and property, plant and equipment”);
• negative foreign exchange effects of €286 million, mainly resulting from the depreciation of the US dollar (negative €445 million), partially offset by the appreciation the Brazilian real (positive €88 million), the Mexican peso (positive €47 million) and the pound sterling (positive €33 million) against euro.
13.3.2 Pledged and mortgaged assets
Items of property, plant and equipment pledged by the Group to guarantee borrowings and debt amounted to €1,625 million at December 31, 2023 compared to €1,120 million at December 31, 2022. 817 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 13 FIXED ASSETS
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
86 The net increase primarily relates to the renewable assets pledged in Brazil for €392 million.
13.3.3 Contractual commitments to purchase property, plant and equipment In the ordinary course of their operations, some Group companies have entered into commitments to purchase, and the related third parties to deliver plant and equipment. These commitments relate mainly to orders for equipment and material related to the construction of energy production units and to service agreements.
Contractual investment commitments made by the Group to purchase property, plant and equipment totaled €2,859 million at December 31, 2023 compared to €3,548 million at December 31, 2022.
The net reduction in contractual commitments relates mainly to renewable assets in the United States for €585 million.
13.3.4 Other information
Borrowing costs included in the cost of property, plant and equipment amounted to €268 million at December 31, 2023 compared to €109 million at December 31, 2022.
13.4 Impairment testing of goodwill, intangible assets and property, plant and equipment
Accounting standards
Risk of impairment
Goodwill
Goodwill is not amortized but is tested for impairment each year in accordance with IAS 36, or more frequently where an indication of impairment is identified. All goodwill is tested for impairment based on data at the end of June, supplemented by a review of events in the second half.
Impairment tests are carried out at the level of cash-generating units (CGUs) or groups of CGUs, which constitute groups of assets which generate cash flows that are largely independent from cash flows generated by other CGUs.
Goodwill is impaired if the net carrying amount of the CGU (or group of CGUs) to which the goodwill is allocated is greater than the recoverable amount of that CGU.
Impairment losses in relation to goodwill cannot be reversed and are shown as “Impairment losses” in the income statement.
Intangible assets and property, plant and equipment
In accordance with IAS 36, impairment tests are carried out on items of property, plant and equipment and intangible assets where there is an indication that the assets may be impaired. Such indications may be based on events or changes in the market environment, or on internal sources of information. Intangible assets that are not amortized are tested for impairment annually.
Property, plant and equipment and intangible assets with finite useful lives are only tested for impairment when there is an indication that they may be impaired. This is generally the result of significant changes in the environment in which the assets are operated or when economic performance is lower than expected.
Items of property, plant and equipment and intangible assets are tested for impairment at the level of the cash-generating unit (CGU), as appropriate and determined in accordance with IAS 36. If the recoverable amount of an asset is lower than its carrying amount, the carrying amount is written down to the recoverable amount by recording an impairment 818 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 13 FIXED ASSETS
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
87 loss. Upon recognition of an impairment loss, the depreciable amount and possibly the useful life of the asset concerned is revised.
Impairment losses recorded in relation to property, plant and equipment or intangible assets may be subsequently reversed if the recoverable amount of the asset increases to exceed the carrying amount. The increased carrying amount of an item of property, plant or equipment following the reversal of an impairment loss may not exceed the carrying amount that would have been determined (net of depreciation/amortization) had no impairment loss been recognized in prior periods.
Indicators of impairment
The main indicators of impairment used by the Group are:
• using external sources of information
− a decline in an asset’s value over the period that is significantly more than would be expected from the passage of time or normal use;
− significant adverse changes that have taken place over the period, or will take place in the near future, in the technological market, economic or legal environment in which the entity operates or in the market to which an asset is dedicated;
− an increase over the period in market interest rates or other market rates of return on investments if such increase is likely to affect the discount rate used in calculating an asset’s value in use and decrease its recoverable amount materially;
− the carrying amount of the net assets of the entity exceeds its market capitalization; • using internal sources of information
− evidence of obsolescence or physical damage to an asset; − significant changes in the extent to which, or manner in which, an asset is used or is expected to be used, that have taken place in the period or soon thereafter and that will adversely affect it. These changes include the asset becoming idle, plans to dispose of an asset sooner than expected, reassessing its useful life as finite rather than indefinite or plans to restructure the operations to which the asset belongs; − internal reports that indicate that the economic performance of an asset is, or will be, worse than expected.
Measurement of recoverable amount
For operating entities which the Group intends to hold on a long-term and going concern basis, the recoverable amount of a CGU corresponds to the higher of its fair value less costs to sell and its value in use. Value in use is primarily determined based on the present value of future operating cash flows including a terminal value. Standard valuation techniques are used based on the following main economic assumptions:
• market perspectives and developments in the regulatory framework; • discount rates based on the specific characteristics of the operating entities concerned; • terminal values in line with available market data specific to the operating segments concerned and growth rates associated with these terminal values, not exceeding the inflation rate.
Discount rates are determined on a post-tax basis and applied to post-tax cash flows. The recoverable amounts calculated on the basis of these discount rates are the same as the amounts obtained by applying the pre-tax discount rates to cash flows estimated on a pre-tax basis, as required by IAS 36.
For operating entities which the Group has decided to sell, the related recoverable amount of the assets concerned is based on market value less disposal costs. Where negotiations are ongoing, this value is determined based on the best estimate of their outcome as of the reporting date.
819 of 1021
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 13 FIXED ASSETS
ENGIE - 2023CONSOLIDATED FINANCIAL STATEMENTS
88 13.4.1 General assumptions
The impairment tests were performed in the context of a highly volatile economic environment, as described in Note 1.3 “Use of estimates and judgments”.
In most cases, the recoverable amounts are determined by reference to a value in use that is calculated using cash flow projections drawn up on the basis of the 2024 budget and the 2025-2026 medium-term business plan, as approved by the Executive Committee and the Board of Directors, and on the basis of extrapolated cash flows beyond that time frame.
Cash flow projections are determined on the basis of macroeconomic assumptions (inflation, exchange rates and growth rates), and price forecasts resulting from the Group's reference scenario for 2027-2050 as revised and validated by the Executive Committee in July 2023. The forecasts and projections included in the reference scenario were determined on the basis of the following inputs:
• forward market prices over the liquidity period for fuel (coal, oil and gas), CO2 and electricity on each in a context of highly volatile energy prices;
• beyond this period, medium- and long-term energy prices were determined by the Group based on macroeconomic assumptions and fundamental supply and demand equilibrium models, the results of which are regularly compared against forecasts prepared by external energy sector specialists. Long-term projections for CO2 prices are in line with the 2030 emissions reduction target of 55% and the 2050 climate neutrality objectives set by the European Commission as part of the "European Green Deal" presented in December 2019 and July 2021. Among the external scenarios, the Group's scenario is similar to that of the International Energy Agency, with its APS (Announced Pledges Scenario) model, and that of ADEME (“green technology”); • more specifically, medium- and long-term electricity prices were determined by the Group using electricity demand forecasting models, medium- and long-term forecasts of fuel and CO2 prices, and expected trends in installed capacity and in the technology mix of the production assets within each power generation system. ENGIE has opted for a balanced mix, integrating renewable gas and carbon dioxide capture and storage in order to guarantee an energy system with the best levels of efficiency and resilience. This trajectory has been included in the Group's report as part of the “Task Force on Climate Related Financial Disclosures” (TCFD) initiative. The risk factors arising from climate and environmental issues are also detailed in the Group's Universal Registration Document.
Finally, as part of the Group's efforts to take climate issues into account (see Note 1.3.3 “Consideration of climate issues in the preparation of the Group's financial statements”), the Group has taken into account, in the valuation of non-financial assets, its commitment to completely withdraw from coal activities by 2027 (see Note 13.4.5).
13.4.2 Renewables
At December 31, 2023, goodwill amounted to €2,185 million, intangible assets to €1,756 million and property, plant and equipment to €17,124 million. Renewables comprises all centralized renewable energy generation activities, including financing, construction, operation and maintenance of renewable energy facilities, using various energy sources such as hydropower, onshore wind, photovoltaic solar, biomass, offshore wind, and battery storage linked to a renewable asset.
The energy produced is fed into the grid and sold either on the open or regulated market or to third parties through electricity sale agreements.
The main assumptions and key estimates relate primarily to discount rates, assumptions as to the renewal of the hydropower concession agreements and changes in electricity prices beyond the liquidity period.
The value in use of the Compagnie Nationale du Rhône and SHEM was calculated based on assumptions including the extension or renewal through a tender process for the concession agreements.
The cash flows for the periods covered by the renewal of the concession agreements are based on a number of assumptions relating to the economic and regulatory conditions for operating these assets (royalty rates, required level of investment, etc.) during this period.
820 of 1021
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89 In 2023, the discount rates applied to these activities ranged between 5.3% and 10.3%. In 2022, they ranged between
4.5% and 10.2%.
Results of the impairment tests
At December 31, 2023, no impairment losses were recognized on goodwill in consideration of the recoverable amount of the cash generating unit to which it belongs.
However, impairment losses on property, plant and equipment totaling €784 million were nevertheless recognized over the year, notably on renewable energy production assets in North America (€714 million), due to very specific operational difficulties linked to turbine performance on a wind power asset, and the fall in long-term market prices affecting certain projects exposed to the SPP market in particular. It should be noted that for these projects, the fall in market prices had a positive impact on the fair value of VPPA (Virtual Power Purchase Agreement) contracts of around €+0.3 billion, with these mark-to-market changes, on the period covered by these contacts, recognized in operating expenses (see Note 8.1 “Operating expenses”).
Sensitivity analyses
The sensitivity of the hydropower generation business in France and the renewable power generation business in North America to changes in electricity prices and changes in discount rates (impact on the recoverable amount) is shown in the table below:
31 déc. 2023
Electricity prices Discount rates
In billion of euros +10€/MWh -10€/MWh +50 bp -50bp
Hydropower generation in France 0.2 (0.4) (0.2) 0.2
Renewables assets in North America 0.4 (0.4) (0.1) 0.1
Non-linear increase or decrease due to the method of calculation of the hydro tax.
An increase of 50 basis points in the discount rates and a decrease of €10/MWh in the electricity price have a negative impact on the recoverable amount. However, the recoverable amount of goodwill would remain above the carrying amount.
13.4.3 Networks
Networks comprises the Group's electricity and gas infrastructure activities and projects. These activities include the management and development of (i) gas and electricity transportation networks and natural gas distribution networks in and outside of Europe, (ii) underground natural gas storage in Europe, and (iii) regasification infrastructure in France and Chile.
Apart from the historical infrastructure management activities, its asset portfolio also contributes to the challenges of the energy transition and network greening (biomethane, hydrogen, etc.).
At December 31, 2023, goodwill amounted to €5,366 million, intangible assets to €1,090 million and property, plant and equipment to €29,975 million. Regulated infrastructure assets in France amounted to €928 million for intangible assets and €27,220 million for property, plant and equipment.
The valuation of activities in France is mainly based on cash flow projections determined on the basis of tariffs negotiated with the French energy regulator (CRE) and terminal values corresponding to the expected value of the Regulated Asset Base (RAB). The RAB is the value assigned by the CRE to the assets operated by distributors. It is the sum of the future pre-tax cash flows, discounted at the pre-tax rate of return guaranteed by the regulator.
In respect of the valuation of activities in France, the energy mix scenario for 2050, adopted by the Group and detailed in Note 17.3.1 “Dismantling obligations arising on non-nuclear plant and equipment”, will not lead to any significant change in the RAB. Given the vital role of gas, a reliable energy source able to supplement renewable energy sources that are intermittent by nature, non-controllable and difficult to store, the Group is planning to maintain or convert its gas network infrastructures to allow for the transportation of green gases (biomethane, hydrogen, etc.), which will progressively replace 821 of 1021
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90 natural gas. This strategic role will be further strengthened by the new opportunities offered in terms of CO2 storage and transportation.
To achieve this, the Group plans to maintain its current level of investment. This approach is largely supported by a rapidly developing regulatory framework supporting the rise in the use of hydrogen and biomethane in the European Union, which will result in concrete European targets. This legal framework should be in place within the next two years.
France's political and social strategy concerning the energy transition aims to achieve carbon neutrality by 2050. The priorities of the French climate and energy policy are being updated with France's future roadmap Stratégie Française sur l’Énergie et le Climat (SFEC), in particular with the document published on November 22, 2023 by the Ministry of Ecological Transition ahead of the consultation that was launched in December 2023. In addition, the scenario adopted by the Group is largely supported by the main conclusions of the CRE report of April 2023 on the future of gas infrastructures, as well as those of the public consultation on “decarbonizing the building industry” held during the 2023 summer, which highlighted the difficulties associated with a potential ban on the installation of new gas boilers in existing homes.
In 2023, the discount rates applied to all these activities ranged between 4.9% and 9.4%. In 2022, they ranged between
4.7% and 8.5%.
Results of the impairment tests
At December 31, 2023, no impairment losses were recognized on goodwill in consideration of the recoverable amount of the cash generating unit to which it belongs.
However, impairment losses totaling €82 million were recognized during the year on certain biomethane production assets.
Sensitivity analysis
Given the regulated nature of the Networks business in France, as well as the progressive transition from natural gas to green gas, a reasonable change in any of the valuation inputs (discount rate, inflation rate and rate of return on assets) would not result in any impairment losses. A very substantial change in the regulatory framework and political orientations could have a significant impact on the valuation of gas infrastructure assets in France. In this respect, the 2023 RAB of Networks assets in France, as well as the related depreciation and amortization expenses, are as follows:
In millions of euros 2023 RAB
Depreciation
and
amortization
GRDF 16,941 (1,083)
GRTgaz 9,362 (546)
Storengy 4,120 (153)
Elengy 930 (61)
13.4.4 Energy Solutions
At December 31, 2023, goodwill amounted to €1,209 million, intangible assets to €2,351 million and property, plant and equipment to €2,646 million.
Energy Solutions encompasses the construction and management of decentralized energy networks to produce energy (heating and cooling networks, distributed power generation plants, distributed solar power parks, low carbon mobility, lowcarbon cities and public lighting, etc.) and related services (energy efficiency, technical maintenance, sustainable development consulting).
The terminal value used to calculate the value in use of the services and energy sales businesses in France was determined by extrapolating the cash flows beyond the medium-term business plan period using a long-term growth rate of 2% per year.
The main assumptions and key estimates relate primarily to discount rates and changes in price beyond the liquidity period. 822 of 1021
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91 In 2023, the discount rates applied to these activities ranged between 5.3% and 9%. In 2022, they ranged between 4.9% and 8.9%.
Results of the impairment tests
At December 31, 2023, no impairment losses were recognized on goodwill in consideration of the recoverable amount of the cash generating unit to which it belongs.
However, impairment losses totaling €137 million were recognized during the year on property, plant and equipment, mainly in connection with renegotiations of contracts due to expire shortly in France, as well as assets that were subject to revisions to their medium- and long-term forecasts or that encountered operational difficulties in Germany and North America.
Sensitivity analyses
Given the essentially contractual nature of Energy Solutions activities, a reasonable change in any of the valuation inputs would not result in impairment losses on goodwill.
13.4.5 FlexGen
At December 31, 2023, goodwill amounted to €1,123 million, intangible assets to €894 million and property, plant and equipment to €5,883 million.
FlexGen encompasses all the Group's the activities involved in compensating the intermittent nature of renewable energies by providing upstream flexibility (flexible generation as well as pump- or battery- operated storage plants) and downstream flexibility (shaving or shifting the consumption of BtoC customers). They also provide solutions to decarbonize the industry with low-carbon hydrogen. The GBU plays a key role in the energy transition. It also includes the financing, construction, and operation of desalination plants, whether or not connected to power plants.
The main assumptions and key estimates relate primarily to discount rates, estimated demand for electricity and changes in the price of CO2, fuel and electricity beyond the liquidity period. These assumptions also concern the duration of tax measures involving inframarginal rent caps in France and Italy.
In 2023, the discount rates applied to these activities ranged between 6.4% and 10.4%. In 2022, they ranged between 6% and 10.3%.
Results of the impairment tests
At December 31, 2023, no impairment losses were recognized on goodwill in consideration of the recoverable amount of the cash generating unit to which it belongs.
However, impairment losses totaling €624 million were recognized during the year on property, plant and equipment, notably on coal-fired power generation assets in South America for which the Group has decided to accelerate the end of operations by the end of 2025, in line with the Group's decarbonization plan.
Sensitivity analyses
An increase of 50 basis points in the discount rates used would have a negative 1% impact on the recoverable amount of thermal power plants in France, Belgium, the Netherlands and Spain. However, the recoverable amount of goodwill would remain above the carrying amount. A reduction of 50 basis points in the discount rates used would have a positive 1% impact on the calculation.
A 10% decrease in the margin captured by thermal power plants in France, Belgium, the Netherlands and Spain would have a negative impact of 6% on the recoverable amount of goodwill over the carrying amount. An increase of 10% in the margin captured would have a positive 6% impact on this calculation. 823 of 1021
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92 13.4.6 Retail
At December 31, 2023, goodwill amounted to €1,838 million, intangible assets to €610 million and property, plant and equipment to €136 million.
Retail encompasses all the Group's activities relating to the sale of gas and electricity to end customers. It also includes all the Group’s activities in services for residential clients.
The terminal value used to calculate the value in use of the main services and energy sales businesses in Europe was determined by extrapolating cash flows beyond the medium-term business plan period using a long-term growth rate of approximately 2% per year.
In 2023, the discount rates applied to these activities ranged between 8% and 10.6%. In 2022, these rates ranged between
7.8% and 10%.
Results of the impairment tests
At December 31, 2023, no impairment losses were recognized on goodwill in consideration of the recoverable amount of the cash generating unit to which it belongs.
Sensitivity analyses
Given the capital-light nature of Retail activities, a reasonable change in any of the valuation inputs would not result in any impairment losses on goodwill.
13.4.7 Nuclear
At December 31, 2023, goodwill amounted to €797 million, intangible assets to €979 million and property, plant and equipment to €1,045 million.
Nuclear encompasses the power generation activities from the Group's nuclear power plants in Belgium and drawing rights on the Chooz B and Tricastin power plants in France.
Key assumptions used for the impairment test
On June 29, 2023, ENGIE and the Belgian government signed an intermediate agreement defining the terms of the extension of the Doel 4 and Tihange 3 nuclear units only. This agreement became binding on July 21, 2023, following the signature of the supplements to the initial agreements. Transaction documents signed on December 13, 2023 have clarified the implementation of the first agreements of June and July (see Note 17.2 “Obligations relating to nuclear power generation activities”). This agreement also provides for the establishment of a legal structure dedicated to the two extended nuclear units, equally owned by the Belgian State and ENGIE, aligning the interests of the two parties and ensuring the sustainability of their commitments. The business model of the extension is based on a balanced allocation of risks, notably through a Contract for Difference mechanism guaranteeing the value of extension investments, with a limited incentive for the industrial operator to achieve a favorable technical and economic performance at the plants.
In addition, for the period up to the extension of the two Belgian nuclear units, and for the period covering drawing rights on nuclear power plants in France, the cash flow projections are based on a large number of key assumptions, such as prices of fuel and CO2, expected trends in electricity prices, availability of power plants, market outlook, and changes in the regulatory environment (especially concerning the extension of drawing rights agreements for French nuclear plants and the tax measures involving inframarginal rent caps). Lastly, the key assumptions also include the discount rate used to calculate the value in use of these activities, which amounted to 7% for 2023, unchanged from 2022.
Cash flow projections beyond the medium-term business plan for drawing rights on the Chooz B and Tricastin power plants have been determined on the basis of the residual term of the contracts and the assumption of a 10-year extension. 824 of 1021
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93 In France, the Nuclear Safety Authority authorized the start-up of Tricastin 1 on December 20, 2019 after its shutdown for its fourth 10-yearly inspection and, on December 3, 2020, published a draft decision setting out the conditions for the 900 MW reactors to continue operating beyond 40 years. Confirmation of a 10-year extension of the operating life of the 900 MW series reactors is therefore expected to be formalized in the next few years, once the conditions for continued operation have been determined by the Nuclear Safety Authority and a public inquiry has been held. The Group has therefore considered the 10-year extension of the nuclear units, and the corresponding drawing rights, beyond their fourth 10-yearly outage. The last 10-yearly inspection took place in 2021 for Tricastin (VD4) and in 2019 for Chooz B (VD3). The assumption of an extension was already considered in the impairment tests of previous years.
Results of the impairment test
The recoverable amount of the Nuclear assets remains above the value of goodwill, particularly due to the excess value attached to the plants in France.
Following the review procedure initiated by the Commission for Nuclear Provisions (CNP) in September 2022, the industrial scenario and all the technical and financial assumptions were approved on July 7, 2023. This resulted in a €646 million decrease in the plant dismantling provision (see Note 17.2 “Obligations relating to nuclear power generation activities”), against a reduction in the dismantling assets. Given the impairment losses recognized on some of these assets at the end of the previous year, an impairment reversal of €400 million was recorded.
Sensitivity analyses
A decrease of €10/MWh in electricity prices for nuclear power generation in France beyond the liquidity period would lead to a decrease of €0.5 billion in the recoverable amount, but without any impairment of goodwill.
Given the hedging of energy prices for electricity generated by Belgian power plants, and the implementation of the Contract for Difference mechanism as part of the extension of the Doel 4 and Tihange 3 nuclear units, the recoverable amount is not very sensitive to changes in electricity prices for nuclear-generated electricity in Belgium.
An increase of 50 basis points in the discount rates would lead to a non-material decrease in the recoverable amount on the Belgian plants.
A 5% decrease in availability of all Belgian nuclear power plants would lead to a decrease in value of around €0.3 billion on the Belgian plants. A similar decrease for the French plants would lead to a decrease of €0.2 billion in the recoverable amount, but without any impairment.
13.4.8 Other
Goodwill amounted to €346 million at December 31, 2023. The Other segment encompasses energy management and optimization activities, the BtoB supply activities in France of Entreprises & Collectivités (E&C), and the Corporate and holding activities. These entities present a significant difference between recoverable amount and the carrying amount of the segment’s operating activities carrying goodwill at December 31, 2023. 825 of 1021
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94 NOTE 14 FINANCIAL INSTRUMENTS
14.1 Financial assets
Accounting standards
In accordance with the principles of IFRS 9 – Financial Instruments, financial assets are recognized and measured either at amortized cost, at fair value through equity or at fair value through profit or loss based on the following two criteria:
• a first criterion relating to the contractual cash flow characteristics of the financial asset. The analysis of contractual cash flow characteristics makes it possible to determine whether these cash flows are “only payments of principal and interest on the outstanding amounts” (known as the “SPPI” test or Solely Payments of Principal and Interest);
• a second criterion relating to the business model used by the Group to manage its financial assets. IFRS 9 defines three different business models: a first business model whose objective is to hold assets in order to collect contractual cash flows (hold to collect), a second model whose objective is achieved by both collecting contractual cash flows and selling financial assets (hold to collect and sell), and other business models.
The identification of the business model and the analysis of the contractual cash flow characteristics require judgment to ensure that the financial assets are classified in the appropriate category.
Where the financial asset is an investment in an equity instrument and is not held for trading, the Group may irrevocably elect to present the gains and losses on that investment in other comprehensive income.
Except for trade receivables, which are measured at their transaction price in accordance with IFRS 15, financial assets are measured, on initial recognition, at fair value plus, in the case of a financial asset not at fair value through profit or loss, transaction costs that are directly attributable to their acquisition.
At the end of each reporting period, financial assets measured using the amortized cost method or at fair value through other comprehensive income (with a recycling mechanism) are subject to an impairment test based on the expected credit losses method.
Financial assets also include derivatives that are measured at fair value in accordance with IFRS 9.
In accordance with IAS 1, the Group presents current and non-current assets and current and non-current liabilities separately in the statement of financial position. In view of the majority of the Group's activities, it was considered that the criterion to be used to classify assets is the expected time to realize the asset or settle the liability: the asset is classified as current if this period is less than 12 months and as non-current if it is more than 12 months after the reporting period.
826 of 1021
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95 The following table presents the Group’s different categories of financial assets, broken down into current and non-current items:
Dec. 31, 2023 Dec. 31, 2022
In millions of euros Notes
Noncurrent Current TotalNoncurrent Current Total
Other financial assets 14.1 14,817 2,170 16,987 10,599 2,394 12,992 Equity instruments at fair value through other comprehensive income 1,902 ‐ 1,902 1,217 ‐ 1,217
Equity instruments at fair value through income 222 ‐ 222 278 ‐ 278 Debt instruments at fair value through other comprehensive income 1,753 119 1,873 2,128 290 2,418
Debt instruments at fair value through income 2,915 654 3,569 1,178 568 1,745 Loans and receivables at amortized cost 8,024 1,397 9,421 5,798 1,537 7,334 Trade and other receivables 7.2 ‐ 20,092 20,092 ‐ 31,310 31,310 Assets from contracts with customers 7.2 1 9,530 9,531 9 12,575 12,584 Cash and cash equivalents ‐ 16,578 16,578 ‐ 15,570 15,570 Derivative instruments 14.4 12,764 8,481 21,245 33,134 15,252 48,386 TOTAL 27,582 56,850 84,433 43,741 77,101 120,843
14.1.1 Other financial assets
14.1.1.1 Equity instruments at fair value
Accounting standards
Equity instruments at fair value through other comprehensive income (OCI) Under IFRS 9 an irrevocable election can be made to present subsequent changes in the fair value of an investment in an equity instrument that is not held for trading in other comprehensive income. This choice is made on an instrument by instrument basis. Amounts presented in other comprehensive income should not be transferred to profit or loss including proceeds of disposals. However, IFRS 9 authorizes the transfer of the accumulated profits and losses to another component of equity. Dividends from such investments are recognized in profit or loss unless the dividend clearly represents the recovery of a portion of the cost of the investment.
The equity instruments recognized under this line item mainly concern investments in companies that are not controlled by the Group and for which OCI measurement has been selected given their strategic and long-term nature.
Upon initial recognition, these equity instruments are recognized at fair value, which is generally their acquisition cost, plus transaction costs.
At each reporting date, for listed securities, fair value is determined based on the quoted market price at the reporting date. For unlisted securities, fair value is measured using valuation models based primarily on the latest market transactions, the discounting of dividends or cash flows and the net asset value.
Equity instruments at fair value through profit or loss Equity instruments that are held for trading or for which the Group has not elected for measurement at fair value through other comprehensive income are measured at fair value through profit or loss.
This category mainly includes investments in companies not controlled by the Group.
Upon initial recognition, these equity instruments are recognized at fair value, which is generally their acquisition cost.
At each reporting date, for listed and unlisted securities, the same measurement method as described above should be applied.
827 of 1021
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96 In millions of euros
Equity instruments
at fair value
through other
comprehensive
income
Equity instruments
at fair value
through income Total
AT DECEMBER 31, 2022 1,217 278 1,495
Increase 666 84 749
Decrease (105) (4) (109)
Changes in fair value 136 (49) 87
Changes in scope of consolidation, translation adjustments and other (11) (87) (98) AT DECEMBER 31, 2023 1,902 222 2,124
Dividends 2 7 8
Equity instruments break down as €1,653 million of listed equity instruments (€875 million at December 31, 2022) and €473 million of unlisted equity instruments (€620 million at December 31, 2022). Changes in fair value include in particular the impairment of the minority interest held by the Group in Nord Stream AG, now valued at zero (€90 million at December 31, 2022). This change in fair value does not affect the income statement, as it is recorded as a reduction in other items of comprehensive income.
14.1.1.2 Debt instruments at fair value
Accounting standards
Debt instruments at fair value through other comprehensive income Financial assets that are held within a business model whose objective is achieved by both collecting contractual cash flows and selling financial assets and for which the contractual terms give rise on specified dates to cash flows that are solely payments of principal and interest on the outstanding amount (SPPI), are measured at fair value through OCI (with a recycling mechanism). This involves a measurement through profit or loss for interest (at amortized cost using the effective interest method), impairment and foreign exchange gains and losses, and through OCI (with a recycling mechanism) for other gains or losses.
This category mainly includes bonds.
Fair value gains and losses on these instruments are recognized in other comprehensive income, except for the following items which are recognized in profit or loss:
• expected credit losses and reversals;
• foreign exchange gains and losses.
When the financial asset is derecognized, the cumulative gain or loss that was previously recognized in other comprehensive income is reclassified from equity to profit or loss.
Debt instruments at fair value through profit or loss
Financial assets whose contractual cash flows do not consist solely of payments of principal and interest on the amount outstanding (SPPI) or that are held in view of an “other” business model are measured at fair value through profit or loss.
The Group's investments in UCITS are accounted for in this caption. They are considered as debt instruments, according to IAS 32 – Financial Instruments: Presentation, given the existence of an obligation for the issuer to redeem units, at the request of the holder. They are measured at fair value through profit or loss because the contractual cash flow characteristics do not meet the SPPI test.
828 of 1021
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97 In millions of euros
Debt
instruments at
fair value
through other
comprehensive
income
Liquid debt
instruments
held for cash
investment
purposes at
fair value
through other
comprehensive
income
Debt
instruments
at fair value
through
income
Liquid debt
instruments
held for cash
investment
purposes at
fair value
through
income Total
AT DECEMBER 31, 2022 2,418 ‐ 977 769 4,163
Increase 2,147 ‐ 2,942 228 5,317
Decrease (2,717) (24) (1,375) (139) (4,255)
Changes in fair value 25 ‐ 141 26 192
Changes in scope of consolidation, translation adjustments and other ‐ 24 ‐ ‐ 24
AT DECEMBER 31, 2023 1,873 ‐ 2,685 884 5,441
Debt instruments at fair value at December 31, 2023 primarily included bonds and money market funds held by Synatom for €4,536 million (see Note 17.2.4 “Financial assets set aside to cover the future costs of dismantling nuclear facilities and managing radioactive fissile material”) and liquid instruments deducted from net financial debt for €884 million (respectively €3,350 million and €769 million at December 31, 2022).
14.1.1.3 Loans and receivables at amortized cost
Accounting standards
Loans and receivables held by the Group under a business model consisting in holding the instrument in order to collect the contractual cash flows, and whose contractual cash flows consist solely of payments of principal and interest on the principal amount outstanding (SPPI test) are measured at amortized cost. Interest is calculated using the effective interest method.
The following items are recognized in profit or loss:
• interest income using the effective interest method;
• expected credit losses and reversals;
• foreign exchange gains and losses.
The Group has entered into concession agreements with certain public authorities under which the construction, extension or improvement of infrastructure is carried out in return for an unconditional right to receive payment from the concession holder in cash or other financial assets. In this case, the Group recognizes a financial receivable from the concession holders.
The Group has entered into services or take-or-pay contracts that are, or contain, a lease and under which the Group acts as lessor and its customers as lessees. Leases are analyzed in accordance with IFRS 16 in order to determine whether they constitute an operating lease or a finance lease. Whenever the terms of the lease transfer substantially all the risk and rewards of ownership of the related asset, the contract is classified as a finance lease and a finance receivable is recognized to reflect the financing deemed to be granted by the Group to the customer.
Leasing security deposits are presented in this caption and recognized at their nominal value.
Please refer to Note 15 “Risks arising from financial instruments” regarding the assessment of counterparty risk. 829 of 1021
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98 Dec. 31, 2023 Dec. 31, 2022
In millions of euros Non-current Current Total Non-current Current Total Loans granted to affiliated companies and other debt
instruments at amortized cost 5,021 350 5,371 3,583 427 4,010 Other receivables at amortized cost 219 648 867 261 734 995 Amounts receivable under concession contracts 2,349 211 2,559 1,564 187 1,751 Amounts receivable under finance leases 435 188 624 390 189 579 TOTAL 8,024 1,397 9,421 5,798 1,537 7,334
Loans granted to affiliated companies and other debt instruments at amortized cost include the cash of the debt instruments held by Synatom, awaiting investment for €3,777 million (€2,270 million at December 31, 2022) (see Note 17.2.4. “Financial assets set aside to cover the future costs of dismantling nuclear facilities and managing radioactive fissile material”).
Amounts receivable under concession contracts amounted to €2,559 million at December 31, 2023 (€1,751 million at December 31, 2022). They are mainly related to the Novo Estado and Gralha Azul electric power transmission networks in Brazil, as well as Kathu’s Solar Park (RF) Proprietary Trading concession in South-Africa.
Other net gains and losses recognized in the income statement relating to loans and receivables at amortized cost break down as follows:
Post-acquisition measurement
In millions of euros Interest income
Foreign currency
translation
Expected credit
loss
AT DECEMBER 31, 2023 280 (35) (6)
AT DECEMBER 31, 2022 211 (64) (6)
Amounts receivable under finance leases
These contracts refer to lease contracts in which ENGIE acts as lessor, classified as finance leases in accordance with IFRS 16. They relate to energy purchase and sale contracts where the contract conveys an exclusive right to use a production asset, and certain contracts with industrial customers relating to assets held by the Group.
The Group has recognized finance lease receivables, notably for cogeneration plants for Wapda and NTDC (Uch - Pakistan) one of whose contracts has been extended into 2023.
In millions of euros Dec. 31, 2023 Dec. 31, 2022
Undiscounted future minimum lease payments 1,006 758
Unguaranteed residual value accruing to the lessor 46 12 TOTAL GROSS INVESTMENT IN THE LEASE 1,052 770
Unearned financial income 276 47
NET INVESTMENT IN THE LEASE (STATEMENT OF FINANCIAL POSITION) 776 723 Of which present value of future minimum lease payments 733 718 Of which present value of unguaranteed residual value 43 5 Undiscounted minimum lease payments receivable under finance leases can be analyzed as follows:
In millions of euros Dec. 31, 2023 Dec. 31, 2022
Year 1 222 137
Years 2 to 5 inclusive 360 376
Beyond year 5 423 245
TOTAL 1,006 758
14.1.2 Trade and other receivables, assets from contracts with customers Information on trade and other receivables and assets from contracts with customers are provided in Note 7.2.“Trade and other receivables, assets and liabilities from contracts with customers”. 830 of 1021
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Accounting standards
This item includes cash equivalents as well as short-term investments that are considered to be readily convertible into a known amount of cash and where the risk of a change in their value is deemed to be negligible based on the criteria set out in IAS 7.
Bank overdrafts are not included in the calculation of cash and cash equivalents and are recorded under “Short-term borrowings”.
Cash and cash equivalent items are subject to impairment tests in accordance with the expected credit losses model of IFRS 9.
“Cash and cash equivalents” totaled €16,578 million at December 31, 2023 (€15,570 million at December 31, 2022). This item comprises standard money market funds with daily liquidity (49%), term deposits with a maturity of less than one month (40%), and deposits with a maturity of less than three months and other products (11%).
This amount included funds related to the green bond issues, which remain unallocated to the funding of eligible projects (see section 5 of the Universal Registration Document).
Gains recognized in respect of “Cash and cash equivalents” amounted to €596 million in 2022 compared to €196 million in 2022.
14.1.4 Transfer of financial assets
At December 31, 2023, the outstanding amount of disposals without recourse of financial assets as part of transactions leading to full derecognition, amounted to approximately €1,3 billion at December 31, 2023 (compared with €3.7 billion at December 31, 2022).
14.1.5 Financial assets and equity instruments pledged as collateral for borrowings and debt
In millions of euros Dec. 31, 2023 Dec. 31, 2022
Financial assets and equity instruments pledged as collateral 3,685 3,532 This item mainly includes the carrying amount of equity instruments pledged as collateral for borrowings and debt. 831 of 1021
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14.2 Financial liabilities
Accounting standards
Borrowings and other financial liabilities are measured at amortized cost using the effective interest rate method.
On initial recognition, any issue or redemption premiums and discounts and issuing costs are added to/deducted from the nominal value of the borrowings concerned. These items are taken into account when calculating the effective interest rate and are therefore recorded in the consolidated income statement over the life of the borrowings using the amortized cost method.
As regards structured debt instruments that do not have an equity component, the Group may be required to separate an “embedded” derivative instrument from its host contract. When an embedded derivative is separated from its host contract, the initial carrying amount of the structured instrument is broken down into an embedded derivative component, corresponding to the fair value of the embedded derivative, and a financial liability component, corresponding to the difference between the amount of the issue and the fair value of the embedded derivative. The separation of components upon initial recognition does not give rise to any gains or losses.
The debt is subsequently recorded at amortized cost using the effective interest method while the derivative is measured at fair value, with changes in fair value recognized in profit or loss.
Financial liabilities are recognized either:
• as “Amortized cost liabilities” for borrowings, trade payables and other creditors, and other financial liabilities; • as “Liabilities measured at fair value through profit or loss” for derivative financial instruments and for financial liabilities designated as such.
The following table presents the Group’s different financial liabilities at December 31, 2023, broken down into current and non-current items:
Dec. 31, 2023 Dec. 31, 2022
In millions of euros Notes Non-current Current Total Non-current Current Total Borrowings and debt 14.3 37,920 9,367 47,287 28,083 12,508 40,591 Trade and other payables 14.2 ‐ 22,955 22,955 ‐ 39,801 39,801 Liabilities from contracts with
customers
7.2 93 3,960 4,053 121 3,292 3,412
Derivative instruments 14.4 16,755 7,806 24,561 39,417 11,859 51,276 Other financial liabilities 82 ‐ 82 90 ‐ 90
TOTAL 54,851 44,087 98,938 67,711 67,460 135,171
14.2.1 Trade and other payables
In millions of euros Dec. 31, 2023 Dec. 31, 2022
Trade payables 22,188 39,165
Payable on fixed assets 787 636
TOTAL 22,976 39,801
The carrying amount of these financial liabilities represents a reasonable estimate of their fair value.
The decrease in trade payables is mainly due to a decrease in commodity prices over the period. 832 of 1021
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14.2.2 Liabilities from contracts with customers
Information on liabilities from contracts with customers are provided in Note 7.2. “Trade and other receivables, assets and liabilities from contracts with customers”.
14.3 Net financial debt
14.3.1 Net financial debt by type
Dec. 31, 2023 Dec. 31, 2022
In millions of euros
Noncurrent Current TotalNoncurrent Current Total
Borrowings and debt Bond issues 29,217 1,039 30,256 21,007 2,550 23,557 Bank borrowings 5,985 763 6,748 4,679 797 5,476
Negotiable commercial paper ‐ 5,606 5,606 ‐ 7,386 7,386 Lease liabilities 2,677 470 3,147 2,482 393 2,875
Other borrowings (1) 41 1,034 1,074 (85) 768 682
Bank overdrafts and current account ‐ 455 455 ‐ 615 615 BORROWINGS AND DEBT 37,920 9,367 47,287 28,083 12,508 40,591 Other financial assets
Other financial assets deducted from net financial
debt (2) (303) (1,111) (1,414) (249) (1,133) (1,383)
Cash and cash equivalents Cash and cash equivalents ‐ (16,578) (16,578) ‐ (15,570) (15,570) Derivative instruments Derivatives hedging borrowings (3) 177 20 198 394 22 416 NET FINANCIAL DEBT 37,795 (8,302) 29,493 28,228 (4,174) 24,054 (1) This item corresponds to the revaluation of the interest rate component of debt in a qualified fair value hedging relationship for a negative €-41 million, margin calls on debt hedging derivatives carried in liabilities for €481 million and the impact of amortized cost for €268 million (compared to, respectively, a negative €200 million, a positive €364 million and a positive €144 million at December 31, 2022).
(2) This item notably corresponds to assets related to financing for €105 million, liquid debt instruments held for cash investment purposes for €884 million and margin calls (assets) on derivatives hedging borrowings for €425 million (compared to, respectively, €67 million, €769 million and €547 million at December 31, 2022). (3) This item represents the interest rate component of the fair value of derivatives hedging borrowings in a designated fair value hedging relationship. It also represents the exchange rate and outstanding accrued interest rate components of the fair value of all debt-related derivatives irrespective of whether or not they qualify as hedges.
The fair value of gross borrowings and debt (excluding lease liabilities) amounted to €42,994 million at December 31, 2023, compared with a carrying amount of €44,111 million.
Financial income and expenses related to borrowings and debt are presented in Note 10 “Net financial income/(loss)”. 833 of 1021
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14.3.2 Reconciliation between net financial debt and cash flow from (used in) financing activities
In millions of euros
Dec. 31,
2022
Cash
flow
from
financing
activities
Cash flow
from
operating
and
investing
activities
and
change in
cash and
cash
equivalents
Change
in fair
value
Translation
adjustments
Change in
scope of
consolidation
and others
Dec. 31,
2023
Borrowings and
debt
Bond issues 23,557 6,628 ‐ ‐ 24 48 30,256
Bank borrowings (1) 5,476 (216) ‐ ‐ 5 1,483 6,748
Negotiable commercial paper 7,386 (1,761) ‐ ‐ (18) ‐ 5,606 Lease liabilities (2) (3) 2,875 (418) ‐ ‐ (31) 721 3,147 Other borrowings 682 (129) ‐ 570 16 (65) 1,074
Bank overdrafts and current account 615 (173) ‐ ‐ (14) 27 455 BORROWINGS AND DEBT 40,591 3,930 ‐ 570 (18) 2,214 47,287 Other financial
assets
Other financial assets deducted from
net financial debt (1,383) 15 ‐ (50) 5 (1) (1,414)
Cash and cash
equivalents Cash and cash equivalents (15,570) ‐ (887) ‐ 188 (309) (16,578) Derivative
instruments Derivatives hedging borrowings 416 118 ‐ (104) (232) ‐ 198
NET FINANCIAL
DEBT 24,054 4,063 (887) 417 (57) 1,904 29,493
(1) Bank borrowings: the amount of €1,483 million in the “Change in scope of consolidation and others” column corresponds mainly to the full consolidation of Kathu Solar Park for €475 million, as well as the effect of recognizing Broad Reach Power (€436 million) and BTE Renewables (€301 million) bank borrowings following their acquisition. (2) Lease liabilities: the negative amount of €418 million included in the “Cash flow from financing activities” column corresponds to lease payments, excluding interest (total cash outflow for leases amounted to a negative €480 million, of which €62 million relating to interest).
(3) Lease liabilities: the amount of €721 million in the “Change in scope of consolidation and others” column corresponds mainly to the recognition of right-of-use assets for €324 million relating to new LNG vessels leasing contract.
14.3.3 Main events of the period
14.3.3.1 Impact of changes in the scope of consolidation and in exchange rates on net financial debt
In 2023, changes in exchange rates resulted in a €-57 million decrease in net financial debt, including a €-179 million decrease in relation to the US dollar and a +€94 million increase in relation to the Brazilian real.
Disposals and acquisitions during 2023 (including the effects of changes in the scope of consolidation) impacted net debt by €3,102 million. This change mainly reflects:
• asset disposals during the period, resulting in a €-246 million decrease in net financial debt (see Note 4.1 “Disposals carried out in 2023”), none of which was individually significant. • acquisitions carried out in 2023 which increased net financial debt by €3,348 million (see Note 4.2 “Acquisitions carried out in 2023”). They include:
− the acquisition of Broad Reach Power in the USA, specialized in battery storage; − the full consolidation of Kathu Solar Park (RF) Proprietary Trading in South-Africa following the purchase of an additional stake;
− the acquisition of the activities of BTE Renewables, operating in South Africa; − the acquisition of the biomethane producer Ixora Energy ltd in the United Kingdom. 834 of 1021
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14.3.3.2 Financing and refinancing transactions
The Group carried out the following main transactions in 2023:
ENGIE SA
• on January 11, 2023 ENGIE SA issued a green bond for a total amount of €3,025 million, as follows:
− a €1,000 million tranche, with a 3.625% coupon, maturing on January 11, 2030, plus an additional €100 million on August 14, 2023,
− a €1,000 million tranche, with a 4% coupon, maturing on January 11, 2035, plus an additional €75 million on June 2, 2023, and €100 million on June 6, 2023,
− a €750 million tranche, with a 4.25% coupon, maturing on January 11, 2043; • on February 1, 2023 ENGIE SA redeemed at maturity €742 million worth of bonds, with a 3% coupon; • on February 28, 2023 ENGIE SA redeemed at maturity €500 million worth of green bonds, with a 0.375% coupon; • on April 3, 2023 ENGIE SA issued GBP650 million worth of green bonds (€752 million), maturing on April 3, 2053, with a 5.625% coupon;
• on July 3, 2023, ENGIE SA issued CHF190 million worth of green bonds (€197 million), maturing on January 4, 2027, with a 2.34% coupon, as well as a CHF225 million green bond (€233 million), maturing on July 4, 2031, with a 2.49% coupon;
• on September 6, 2023, ENGIE SA issued €3,000 million worth of bonds, as follows:
− a €500 million tranche, with a 3.75% coupon, maturing on September 6, 2027, − a €800 million tranche, with a 3.875% coupon, maturing on January 6, 2031, − a €800 million tranche, with a 4.25% coupon, maturing on September 6, 2034, − a €900 million tranche green bond, with a 4.5% coupon, maturing on September 6, 2042; • on December 6, 2023, ENGIE SA issued €1,500 million worth of bonds, as follows:
- a €600 million tranche, with a 3.625% coupon, maturing on December 6, 2026, - a €900 million tranche green bond, with a 3.875% coupon, maturing on December 6, 2033.
Other Group entities
• on June 24, 2023 ENGIE Alliance redeemed at maturity €1,000 million worth of bonds, with a 5.75% coupon. • in December 2023, EBE issued a BRL 2.5 bn worth of bonds (€464 million), with a floating coupon. 835 of 1021
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14.4 Derivative instruments
Accounting standards
Derivative financial instruments are measured at fair value. This fair value is determined on the basis of market data, available from external contributors. In the absence of an external benchmark, a valuation based on internal models recognized by market participants and favoring data directly derived from observable data such as OTC quotations is used.
The change in fair value of derivative financial instruments is recorded in the income statement except when they are designated as hedging instruments in a cash flow hedge or net investment hedge. In this case, changes in the value of the hedging instruments are recognized directly in equity, excluding the ineffective portion of the hedges.
The Group uses derivative financial instruments to manage and reduce its exposure to market risks arising from fluctuations in interest rates, foreign currency exchange rates and commodity prices, mainly for gas and electricity. The use of derivative instruments is governed by a Group policy for managing interest rate, currency and commodity risks (see Note 15 – Risks arising from financial instruments).
Derivative financial instruments are contracts (i) whose value changes in response to the change in one or more observable variables, (ii) that do not require any material initial net investment, and (iii) that are settled at a future date.
Derivative instruments include swaps, options, futures and swaptions, as well as forward commitments to purchase or sell listed and unlisted securities, and firm commitments or options to purchase or sell non-financial assets that involve physical delivery of the underlying.
For purchases and sales of electricity and natural gas, the Group systematically analyzes whether the contract was entered into in the “normal” course of operations and therefore falls outside the scope of IFRS 9. This analysis consists firstly in demonstrating that the contract is entered into and continues to be held for the purpose of physical delivery or receipt of the commodity in accordance with the Group’s expected purchase, sale or usage requirements for volumes intended to be used or sold by the Group within a reasonable time frame, as part of its operations.
The second step is to demonstrate that the Group has no practice of settling similar contracts on a net basis and that these contracts are not equivalent to written options. In particular, in the case of electricity and gas sales allowing the buyer a certain degree of flexibility concerning the volumes delivered, the Group distinguishes between contracts that are equivalent to capacity sales considered as transactions falling within the scope of ordinary operations and those that are equivalent to written financial options, which are accounted for as derivative financial instruments.
Only contracts that meet all of the above conditions are considered as falling outside the scope of IFRS 9. Adequate specific documentation is compiled to support this analysis.
Embedded derivatives
The main Group contracts that may contain embedded derivatives are contracts with clauses or options potentially affecting the contract price, volume or maturity. This is the case primarily with contracts for the purchase or sale of non-financial assets, whose price is revised based on an index, the exchange rate of a foreign currency or the price of an asset other than the contract’s underlying.
An embedded derivative is a component of a hybrid (combined) instrument that also includes a non-derivative host contract – with the effect that some of the cash flows of the combined instrument vary in a way similar to a stand-alone derivative.
If a hybrid contract contains a host that is an asset within the scope of IFRS 9, the Group applies the presentation and measurement requirements described in Note 18.1 to the entire hybrid contract. 836 of 1021
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Conversely, when a hybrid contract contains a host that is not an asset within the scope of IFRS 9, an embedded derivative shall be separated from the host and accounted for as a derivative if, and only if:
• the economic characteristics and risks of the embedded derivative are not closely related to the economic characteristics and risks of the host;
• a separate instrument with the same terms as the embedded derivative would meet the definition of a derivative; and
• the hybrid contract is not measured at fair value with changes in fair value recognized in profit or loss (i.e., a derivative that is embedded in a financial liability at fair value through profit or loss is not separated).
Where an embedded derivative is separate from the host contract, it is measured at fair value and fair value changes are recognized in profit or loss (except if the embedded derivative is documented in a hedge relationship).
Hedging instruments: recognition and presentation
Derivative instruments qualifying as hedging instruments are recognized in the consolidated statement of financial position and measured at fair value. However, their accounting treatment varies according to whether they are classified as (i) a fair value hedge of an asset or liability; (ii) a cash flow hedge, or (iii) a hedge of a net investment in a foreign operation.
Fair value hedges
A fair value hedge is defined as a hedge of the exposure to changes in fair value of a recognized asset or liability such as a fixed-rate loan or borrowing, or of assets, liabilities or an unrecognized firm commitment denominated in a foreign currency.
The gain or loss from remeasuring the hedging instrument at fair value is recognized in profit or loss. The gain or loss on the hedged item attributable to the hedged risk adjusts the carrying amount of the hedged item and is also recognized in profit or loss even if the hedged item is in a category in respect of which changes in fair value are recognized through other comprehensive income. These two adjustments are presented net in the consolidated income statement, with the net effect corresponding to the ineffective portion of the hedge.
Cash flow hedges
A cash flow hedge is a hedge of the exposure to variability in cash flows that could affect the Group’s income. The hedged cash flows may be attributable to a particular risk associated with a recognized financial or non-financial asset or a highly probable forecast transaction.
The portion of the gain or loss on the hedging instrument that is determined to be an effective hedge is recognized directly in other comprehensive income, net of tax, while the ineffective portion is recognized in profit or loss. The gains or losses accumulated in equity are reclassified to the consolidated income statement under the same caption as the loss or gain on the hedged item – i.e., current operating income for operating cash flows and financial income or expenses for other cash flows – in the same periods in which the hedged cash flows affect income.
If the hedging relationship is discontinued, in particular because the hedge is no longer considered effective, the cumulative gain or loss on the hedging instrument remains recognized in equity until the forecast transaction occurs.
However, if a forecast transaction is no longer expected to occur, the cumulative gain or loss on the hedging instrument is immediately recognized in profit or loss.
Hedge of a net investment in a foreign operation
In the same way as for a cash flow hedge, the portion of the gain or loss on the hedging instrument that is determined to be an effective hedge of the currency risk is recognized directly in other comprehensive income, net of tax, while the ineffective portion is recognized in profit or loss. The gains or losses accumulated in other comprehensive income are transferred to the consolidated income statement when the investment is liquidated or sold. 837 of 1021
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Hedging instruments: identification and documentation of hedging relationships The hedging instruments and hedged items are designated at the inception of the hedging relationship. The hedging relationship is formally documented in each case, specifying the hedging strategy, the hedged risk and the method used to assess hedge effectiveness. Only derivative contracts entered into with external counterparties are considered as being eligible for hedge accounting.
Hedge effectiveness is assessed and documented at the inception of the hedging relationship and on an ongoing basis throughout the periods for which the hedge was designated.
Hedge effectiveness is demonstrated both prospectively and retrospectively using various methods, based mainly on a comparison between changes in fair value or cash flows between the hedging instrument and the hedged item. Methods based on an analysis of statistical correlations between historical price data are also used.
Derivative instruments not qualifying for hedge accounting: recognition and presentation These items mainly concern derivative financial instruments used in economic hedges that have not been – or are no longer – documented as hedging relationships for accounting purposes.
When a derivative financial instrument does not qualify or no longer qualifies for hedge accounting, changes in fair value are recognized directly in profit or loss under (i) current operating income for derivative instruments with non-financial assets as the underlying, and (ii) financial income or expenses for currency, interest rate and equity derivatives.
Derivative instruments not qualifying for hedge accounting used by the Group in connection with proprietary commodity trading activities and other derivatives expiring in less than 12 months are recognized in the consolidated statement of financial position in current assets and liabilities, while derivatives expiring after this period are classified as non-current items.
Fair value measurement
The fair value of instruments listed on an active market is determined by reference to the market price. In this case, these instruments are presented in level 1 of the fair value hierarchy.
The fair value of unlisted financial instruments for which there is no active market and for which observable market data exist is determined based on valuation techniques such as option pricing models or the discounted cash flow method.
The models used to evaluate these instruments take into account assumptions based on market inputs:
• the fair value of interest rate swaps is calculated based on the present value of future cash flows; • the fair value of forward foreign exchange contracts and currency swaps is calculated by reference to current prices for contracts with similar maturities by discounting the future cash flow spread (difference between the forward exchange rate under the contract and the forward exchange rate recalculated in line with the new market conditions applicable to the nominal amount);
• the fair value of currency and interest rate options is calculated using option pricing models; • commodity derivatives are valued by reference to listed market prices based on the present value of future cash flows (commodity swaps or commodity forwards) and option pricing models (options), for which market price volatility may be a factor. Contracts with maturities exceeding the depth of transactions for which prices are observable, or which are particularly complex, may be valued based on internal assumptions; • exceptionally, for complex contracts negotiated with independent financial institutions, the Group uses the values established by its counterparties.
These instruments are presented in level 2 of the fair value hierarchy except when the evaluation is based mainly on data that are not observable, in which case they are presented in level 3 of the fair value hierarchy. Most often, this is the case for derivatives with a maturity that falls outside the observability period for market data relating to the underlying or when certain inputs such as the volatility of the underlying are not observable. 838 of 1021
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Except in case of enforceable master netting arrangements or similar agreements, counterparty risk is included in the fair value of financial derivative instrument assets and liabilities. It is calculated according to the “expected loss” method and takes into account the exposure at default, the probability of default and the loss given default. The probability of default is determined on the basis of credit ratings assigned to each counterparty (“historical probability of default” approach).
Offsetting of financial assets and liabilities in the statement of financial position Financial assets and liabilities are presented net in the statement of financial position when the offsetting criteria of IAS 32 are met. Offsetting relates to instruments entered into with counterparties for which the contractual terms provide for a net settlement of transactions and a collateralization agreement (margin calls). In particular, commodity derivative assets and liabilities are offset for transactions with the same counterparty, in the same currency, by type of commodity and delivery point and with identical maturities.
Derivative instruments recognized in assets and liabilities are measured at fair value and broken down as follows:
Dec. 31, 2023 Dec. 31, 2022
Assets Liabilities Assets Liabilities
In millions of euros
Noncurrent Current TotalNoncurrent Current TotalNoncurrent Current TotalNoncurrent Current Total Derivatives hedging
borrowings 279 111 390 457 131 588 226 92 319 620 114 735 Derivatives hedging
commodities 10,984 8,344 19,328 15,132 7,516 22,648 30,932 15,076 46,008 37,210 11,698 48,907 Derivatives hedging other
items (1) 1,501 26 1,526 1,167 159 1,325 1,975 84 2,059 1,587 47 1,634 TOTAL 12,764 8,481 21,245 16,755 7,806 24,561 33,134 15,252 48,386 39,417 11,859 51,276 (1) Derivatives hedging other items mainly include the interest rate component of interest rate derivatives (not qualifying as hedges or qualifying as cash flow hedges) that are excluded from net financial debt, as well as net investment hedge derivatives.
The net amount of derivatives hedging commodities recognized in the statement of financial position is measured after taking into account offsetting agreements that meet the criteria set out in paragraph 42 of IAS 32. This offsetting generated balance sheet effects of around €9.2 billion in 2023 and mainly concerned OTC derivatives concluded with counterparties for which the contractual terms provide for a net settlement of the transactions as well as a collateralization agreement (margin calls).
The balance of derivative hedging commodities is lower than at December 31, 2022 due to the decrease in commodity prices in 2023. Most of these derivatives mature in 2024 and 2025. This fair value incorporates market parameters at December 31, 2023, in particular the “bid ask” reserve, which has been updated to reflect the volatility of commodity prices observed on the markets. In the main markets where the Group operates (Europe, United States, Singapore) a 10% increase or decrease in these market parameters (including the “bid ask” spread) would impact the fair value of the derivates concerned by a negative €85 million (increase) and a positive €85 million (decrease). 839 of 1021
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14.4.1 Offsetting of derivative instrument assets and liabilities The net amount of derivative instruments after taking into account enforceable master netting arrangements or similar agreements, whether or not they are offset in accordance with paragraph 42 of IAS 32, are presented in the table below:
Dec. 31, 2023 Dec. 31, 2022
In millions of euros
Gross
amount
Net amount
recognized in the
statement of
financial
position (1)
Other
offsetting
agreements (2)
Total net
amount
Gross
amount
Net amount
recognized in the
statement of
financial
position (1)
Other
offsetting
agreements (2)
Total net
amount
Assets
Derivatives
hedging
commodities 28,522 19,328 (4,927) 14,401 72,322 46,008 (8,866) 37,142 Derivatives
hedging
borrowings and
other items 1,917 1,917 (469) 1,448 2,378 2,378 (364) 2,014 Liabilities
Derivatives
hedging
commodities (31,843) (22,648) 3,898 (18,750) (75,221) (48,907) 5,094 (43,813) Derivatives
hedging
borrowings and
other items (1,913) (1,913) 415 (1,498) (2,369) (2,369) 547 (1,822) (1) Net amount recognized in the statement of financial position after taking into account offsetting agreements that meet the criteria set out in paragraph 42 of IAS 32. Due to the volatility of commodity prices, this offsetting had a significant impact on the statement of financial position at December 31, 2023 and mainly concerns OTC derivatives concluded with counterparties for which the contractual terms provide for a net settlement of the transactions as well as a collateralization agreement (margin calls). (2) Other offsetting agreements include collateral and other guarantee instruments, as well as offsetting agreements that do not meet the criteria set out in paragraph 42 of IAS 32.
840 of 1021
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14.5 Fair value of financial instruments by level in the fair value hierarchy
14.5.1 Financial assets
The table below shows the allocation of financial instruments carried in assets to the different levels in the fair value hierarchy:
Dec. 31, 2023 Dec. 31, 2022
In millions of euros Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Other financial assets (excluding loans and receivables at amortized cost) 7,552 6,189 ‐ 1,363 5,658 4,225 ‐ 1,433 Equity instruments at fair value through other comprehensive income 1,902 1,653 ‐ 249 1,217 875 ‐ 342
Equity instruments at fair value through income 222 ‐ ‐ 222 278 ‐ ‐ 278 Debt instruments at fair value through other comprehensive income 1,873 1,873 ‐ ‐ 2,418 2,418 ‐ ‐
Debt instruments at fair value through income 3,555 2,663 ‐ 891 1,745 933 ‐ 813 Derivative instruments 21,245 43 20,087 1,114 48,386 138 44,730 3,518 Derivatives hedging borrowings 390 ‐ 390 ‐ 319 ‐ 319 ‐
Derivatives hedging commodities - relating to portfolio management activities (1) 16,614 ‐ 16,263 351 40,992 ‐ 40,825 168 Derivatives hedging commodities - relating to trading
activities(1)
2,714 43 1,907 764 5,016 138 1,528 3,350
Derivatives hedging other items 1,526 ‐ 1,526 ‐ 2,059 ‐ 2,059 ‐ TOTAL 28,796 6,232 20,087 2,477 54,044 4,363 44,730 4,951 (1) Derivative financial instruments relating to commodities classified in level 3 mainly include long-term gas supply contracts and electricity contracts measured at fair value through profit or loss. Due to geopolitical uncertainties, the fair value of contracts with Russian suppliers takes into account contingencies related to natural gas supply cuts since 2022.
A definition of these three levels is presented in Note 14.4 “Derivative instruments”.
Other financial assets (excluding loans and receivables at amortized cost) Changes in level 3 equity and debt instruments at fair value can be analyzed as follows:
In millions of euros
Equity
instruments at
fair value
through other
comprehensive
income
Debt
instruments at
fair value
through other
comprehensive
income
Equity
instruments at
fair value
through
income
Debt
instruments
at fair value
through
income
Other
financial
assets
(excluding
loans and
receivables
at amortized
cost)
AT DECEMBER 31, 2022 342 ‐ 278 813 1,433
Acquisitions 14 ‐ 84 228 326
Disposals ‐ (24) (4) (139) (167)
Changes in fair value (1) (95) ‐ (49) (11) (156)
Changes in scope of consolidation, foreign currency translation and other changes (13) 24 (87) 1 (75)
AT DECEMBER 31, 2023 249 ‐ 222 891 1,363
Gains/(losses) recorded in income relating to instruments held at the end of the period (50)
(1) Changes in fair value notably comprise the decrease in value of the Group's minority interest in Nord Stream AG for €-90 million (see Note 14.1.1.1 "Equity instruments at fair value").
Derivative instruments
Changes in level 3 commodity derivatives can be analyzed as follows:
In millions of euros Net Asset/(Liability)
AT DECEMBER 31, 2022 1,837
Changes in fair value recorded in income (3,697)
Settlements 644
Transfer from level 3 to levels 1 and 2 (40)
Net fair value recorded in income (1,256)
Deferred Day-One gains/(losses) (16)
AT DECEMBER 31, 2023 (1,271)
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14.5.2 Financial liabilities
The table below shows the allocation of financial instruments carried in liabilities to the different levels in the fair value hierarchy:
Dec. 31, 2023 Dec. 31, 2022
In millions of euros Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Borrowings used in designated fair value hedges 5,755 ‐ 5,755 ‐ 3,679 ‐ 3,679 ‐ Borrowings not used in designated fair value hedges 37,239 23,251 13,988 ‐ 31,500 17,093 14,407 ‐ Derivative instruments 24,561 112 22,063 2,385 51,276 ‐ 49,595 1,681 Derivatives hedging borrowings 588 ‐ 588 ‐ 735 ‐ 735 ‐
Derivatives hedging commodities - relating to portfolio management activities(1) 20,933 ‐ 20,081 852 48,907 ‐ 47,227 1,681 Derivatives hedging commodities - relating to trading activities(1) 1,715 112 70 1,533 ‐ ‐ ‐ ‐ Derivatives hedging other items 1,325 ‐ 1,325 ‐ 1,634 ‐ 1,634 ‐ TOTAL 67,555 23,363 41,806 2,385 86,455 17,093 67,682 1,681 (1) Derivative financial instruments relating to commodities classified in level 3 mainly include long-term gas supply contracts and electricity contracts measured at fair value through profit and loss. Due to geopolitical uncertainties, the fair value of contracts with Russian suppliers takes into account contingencies related to natural gas supply cuts since 2022.
A definition of these three levels is presented in Note 14.4 “Derivative instruments”.
Borrowings used in designated fair value hedges
This caption includes bonds in a designated fair value hedging relationship, which are presented in level 2 in the above table. Only the interest rate component of the bonds is remeasured, with fair value determined by reference to observable inputs.
Borrowings not used in designated fair value hedges
Listed bond issues are included in level 1.
Other borrowings not used in a designated hedging relationship, are presented in level 2 in the above table. The fair value of these borrowings is determined on the basis of future discounted cash flows and relies on directly or indirectly observable data.
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NOTE 15 RISKS ARISING FROM FINANCIAL INSTRUMENTS
The Group mainly uses derivative instruments to manage its exposure to market risks. Financial risk management procedures are set out in Chapter 2 “Risk factors” of the Universal Registration Document.
15.1 Market risks
15.1.1 Commodity risk
Commodity risk arises primarily from the following activities:
• portfolio management; and
• trading.
The Group has primarily identified two types of commodity risks: price risk resulting from fluctuations in market prices, and volume risk inherent to the business.
In the ordinary course of its operations, the Group is exposed to commodity risks on natural gas, electricity, coal, oil and oil products, other fuels, CO2 and other “green” products. The Group is active on these energy markets either for supply purposes, or to optimize and secure its energy production chain and its energy sales. The Group also uses derivatives to offer hedging instruments to its clients and to hedge its own positions.
15.1.1.1 Portfolio management activities
Portfolio management seeks to optimize the market value of assets (power plants, gas and coal supply contracts, energy sales and gas storage by pump and battery and transportation) over various timeframes (short-, medium- and long-term).
Market value is optimized by:
• guaranteeing supply and ensuring the balance between physical needs and resources; • managing market risks (price, volume) to unlock optimum value from portfolios within a specific risk framework.
The risk framework aims to safeguard the Group’s financial resources over the budget period and smooth out medium-term earnings (over three or five years, depending on the maturity of each market). It encourages portfolio managers to take out economic hedges on their portfolio.
Sensitivities of the commodity-related derivatives portfolio used as part of the portfolio management activities at December 31, 2023 are detailed in the table below. Due to the volatility in commodity prices on the markets since 2022, particularly impacting the European zone, the price assumptions for natural gas and electricity in Europe were revised upwards last year. These sensitivities have been established in the current uncertain context.
These new assumptions do not constitute an estimate of future market prices and are not representative of future changes in consolidated earnings and equity, insofar as they do not include the sensitivities relating to the purchase and sale contracts for the underlying commodities, which are not recognized at fair value. 843 of 1021
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Sensitivity analysis (1)
Dec. 31, 2023 Dec. 31, 2022
In millions of euros Changes in price
Pre-tax impact on
income
Pre-tax impact on
equity
Pre-tax impact on
income
Pre-tax impact on
equity
Oil-based products +USD 10/bbl ‐ 64 ‐ 81
Natural gas - Europe (2)-€10/MWh (411) (1,288) (700) (1,237) Natural gas - Europe (2) +€10/MWh 398 1,288 700 1,237
Natural gas - Rest of the world (2) +€3/MWh 37 138 29 206 Electricity - Europe (2)-€20/MWh (353) 338 (51) 245
Electricity - Europe (2) +€20/MWh 353 (338) 51 (245)
Electricity - Rest of the world (2) +€5/MWh (166) ‐ (122) ‐ Greenhouse gas emission rights +€2/ton 12 9 24 1
EUR/USD +10% (40) (111) 36 (186)
EUR/GBP +10% 66 ‐ (17) (34)
(1) The sensitivities shown above apply solely to financial commodity derivatives used for hedging purposes as part of the portfolio management activities.
(2) For December 2023 and in relation to the sensitivities shown, more drastic upward price changes, although difficult to quantify, could occur depending how the economic or political situation evolves. For example, an increase of 50€/MWh for natural gas and 100€/MWh for electricity would impact sensitivities by a positive €8.4 billion and a positive €0.1 billion, respectively for natural gas and electricity.
The decrease in commodity prices in 2023 contributed to substantial changes in the fair value of financial instruments, impacting the income statement (see Note 8 “Operating expenses”) as well as the other comprehensive income of the Group (see “Statement of comprehensive income”).
The sensitivity of equity to European electricity price changes is due to the application, since 2023, of cash flow hedge accounting to certain supply activities in France, Belgium and the Netherlands, as well as the sales resulting from the production of some of our assets in the same areas. The expected extension of this practice to other hedging strategies should contribute to reducing the sensitivity in the future of the pre-tax profit.
15.1.1.2 Trading activities
Revenues from trading activities totaled €3,441 million in 2023 (€4,499 million in 2022).
The Group’s trading activities are primarily conducted within:
• ENGIE Global Markets. Its role is to manage the risks of the physical and financial energy portfolio for the Group or external customers, providing them with access to the market and implementing customized hedging strategies; • ENGIE SA for the optimization of part of its long-term gas supply contracts, of a power swap contract, of part of its gas sales contracts with retail entities in France and Benelux and of power generation facilities in France and Belgium.
These entities operate on organized or OTC markets in derivative instruments such as futures, forwards, swaps, or options.
Exposure to trading activities is strictly controlled by daily monitoring of compliance with Value at Risk (VaR) limits.
The use of VaR to quantify market risk arising from trading activities provides a transversal measure of risk, taking all markets and products into account. VaR represents the maximum potential loss on a portfolio over a specified holding period based on a given confidence interval. It is not an indication of expected results but is back-tested on a regular basis.
The Group uses a one-day holding period and a 99% confidence interval to calculate VaR, as well as stress tests, in accordance with banking regulatory requirements.
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The VaR shown below corresponds to the global VaR of the Group’s entities with trading activities.
Value at Risk
In millions of euros Dec. 31, 2023 2023 average(1) 2023 maximum(2) 2023 minimum(2) 2022 average(1) Trading activities 14 15 39 4 33
(1) Average daily VaR.
(2) Maximum and minimum daily VaR observed in 2023.
VaR limits are set within the framework of Group governance, which was strengthened since the beginning of the crisis to take into account the more volatile market environment. The minimum and the maximum, in 2023, are to be compared respectively with €6 million and with €143 million in 2022.
The continuous monitoring of market risks and the strict application of these measures have enabled the Group to perform its trading activities in a supervised environment during the year.
15.1.2 Hedges of commodity risks
Hedging instruments and sources of hedge ineffectiveness The Group enters into cash flow hedges, using derivative instruments (firm or option contracts) contracted over the counter or on organized markets, to reduce its commodity risks, which relate mainly to future cash flows from contracted or expected sales and purchases of commodities. These instruments may be settled net or involve physical delivery of the underlying.
Sources of hedge ineffectiveness are mainly related to uncertainty regarding the timing and potential mismatches in settlement dates, and, in a context of volatile commodity market prices, indices between the derivative instruments and the associated underlying exposures.
The fair values of commodity derivatives are indicated in the table below:
Dec. 31, 2023 Dec. 31, 2022
Assets Liabilities Assets Liabilities
In millions of euros
Noncurrent CurrentNoncurrent CurrentNoncurrent CurrentNoncurrent Current Derivative instruments relating to portfolio
management activities 10,984 5,630 (15,132) (5,801) 30,932 10,060 (37,210) (11,698) Cash flow hedges 1,648 4,268 (2,321) (5,782) 3,538 4,400 (2,483) (4,140) Other derivative instruments 9,336 1,362 (12,811) (19) 27,394 5,660 (34,726) (7,558) Derivative instruments relating to trading
activities ‐ 2,714 ‐ (1,715) ‐ 5,016 ‐ ‐
TOTAL 10,984 8,344 (15,132) (7,516) 30,932 15,076 (37,210) (11,698) The fair values shown in the table above reflect the amounts for which assets could be exchanged, or liabilities settled, at the end of the reporting period. They are not representative of expected future cash flows insofar as positions (i) are sensitive to changes in prices, (ii) can be modified by subsequent transactions, and (iii) can be offset by future cash flows arising on the underlying transactions.
845 of 1021
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15.1.2.1 Cash flow hedges
The fair values of cash flow hedges by type of commodity are as follows:
Dec. 31, 2023 Dec. 31, 2022
Assets Liabilities Assets Liabilities
In millions of euros
Noncurrent CurrentNoncurrent CurrentNoncurrent CurrentNoncurrent Current Natural gas 760 1,848 (1,052) (2,733) 3,204 3,825 (1,825) (3,149) Electricity 660 2,081 (1,057) (2,664) 114 324 (208) (521) Oil 227 338 (211) (384) 219 248 (449) (470)
Other (1) 1 1 (1) (1) 1 3 (1) 1
TOTAL 1,648 4,268 (2,321) (5,782) 3,538 4,400 (2,483) (4,140) (1) Mainly includes foreign currency hedges on commodities.
Notional amounts (net) (1)
Notional amounts and maturities of cash flow hedges are as follows:
Unit 2024 2025 2026 2027 2028
Beyond 5
years
Total at
Dec. 31,
2023
Natural gas GWh 138,694 21,168 (8,934) (1,392) 422 ‐ 149,958 Electricity GWh 88,624 50,082 16,065 8,515 871 (648) 163,509 Oil-based products Thousands of barrels (11,916) (5,240) ‐ ‐ ‐ ‐ (17,156) Forex Millions of euros 2 ‐ ‐ ‐ ‐ ‐ 2
Greenhouse gas emission rights Thousands of tons (228) (64) (187) 20 20 ‐ (439) (1) Long/(short) position.
Effects of hedge accounting on the Group’s financial position and performance Dec. 31, 2023 Dec. 31, 2022
Fair Value Nominal Fair value Nominal
In millions of euros Assets Liabilities Total Total Total Total Cash flow hedges 5,916 (8,103) (2,187) 10,553 1,315 39,983 TOTAL 5,916 (8,103) (2,187) 10,553 1,315 39,983
The fair values represented above are positive for assets and negative for liabilities.
In millions
of euros
Nominal
amount
Fair
Value
Change in fair value
used for calculating
hedge
ineffectiveness
Change in the
value of the
hedging instrument
recognized in
equity (1)
Ineffective
portion
recognized in
profit or loss (1)
Amount
reclassified from
the hedge reserve
to profit or loss (1)
Line item of
profit or loss
Cash
flow
hedges
Hedging
instruments 10,553 (2,187) (3,873) 120 711
Current
operating
income
Hedged
items (4,944)
(1) Gains/(losses).
The amount of hedge inefficiency is affected in 2023 by the volatility of commodity prices during the year and the partial decorrelation of the various markets particularly in Europe. It is calculated based on the change in fair value of the hedging instrument compared to the change in fair value of the hedged items since inception of the hedging relationship. The fair value of the hedging instruments at December 31, 2023 reflects the cumulative change in fair value of the hedging instruments since inception of the hedges.
846 of 1021
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Maturity of commodity derivatives designated as cash flow hedges In millions of euros 2024 2025 2026 2027 2028 Beyond 5 years Dec. 31, 2023 Dec. 31, 2022 Fair Value of derivatives by maturity (1,459) (692) (7) (14) (5) (10) (2,187) 1,315 Amounts presented in the statement of changes in equity and the statement of comprehensive income The following table provides a reconciliation of each component of equity and an analysis of other comprehensive income:
Cash flow hedge
In millions of euros Derivatives hedging commodities
At DECEMBER 31, 2022 (699)
Effective portion recognized in equity (3,873)
Amount reclassified from hedge reserve to profit or loss 711 Translation differences ‐
Changes in scope of consolidation and other 9
At DECEMBER 31, 2023 (3,852)
15.1.2.2 Other commodity derivatives
Other commodity derivatives include:
• commodity purchase and sale contracts that were not entered into or are no longer held for the purpose of the receipt or delivery of commodities in accordance with the Group’s expected purchase, sale or usage requirements; • embedded derivatives; and
• derivative financial instruments that are not eligible for hedge accounting in accordance with IFRS 9 or for which the Group has elected not to apply hedge accounting.
15.1.3 Currency risk
The Group is exposed to currency risk, defined as the impact on its statement of financial position and income statement of fluctuations in exchange rates affecting its operating and financing activities. Currency risk comprises (i) transaction risk arising in the ordinary course of business, (ii) specific transaction risk related to investments, mergers and acquisitions or disposal projects, and (iii) translation risk arising from the conversion into euros of income statement and statement of financial position items from subsidiaries with a functional currency other than the euro. The main translation risk exposures correspond to assets in US dollars, Brazilian real and pounds sterling. 847 of 1021
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15.1.3.1 Financial instruments by currency
The following tables present a breakdown by currency of outstanding borrowings and debt and net financial debt, before and after hedging:
15.1.3.2 Currency risk sensitivity analysis
A sensitivity analysis to currency risk on financial income/(loss) – excluding the income statement translation impact of foreign subsidiaries – was performed based on all financial instruments managed by the treasury department and representing a currency risk (including derivative financial instruments).
A sensitivity analysis to currency risk on equity was performed based on all financial instruments qualified as net investment hedges at the reporting date.
For currency risk, sensitivity corresponds to a 10% rise or fall in exchange rates of foreign currencies against the euro compared to closing rates.
Dec. 31, 2023
Impact on income Impact on equity
In millions of euros +10%(1)
-10%(1) +10%(1)-10%(1)
Exposures denominated in a currency other than the functional currency of companies carrying the liabilities on their statements of financial position(2) (32) 32 NA NA Financial instruments (debt and derivatives) qualified as net investment hedges(3) NA NA 410 (410) (1) +(-)10%: depreciation (appreciation) of 10% of all foreign currencies against the euro. (2) Excluding derivatives qualified as net investment hedges. (3) This impact is offset by the change in the net investment hedged.
15.1.4 Interest rate risk
The Group seeks to manage its borrowing costs by limiting the impact of interest rate fluctuations on its income statement.
The Group’s policy is therefore to arbitrate between fixed rates, floating rates and capped floating rates for its net debt.
The interest rate mix may shift within a range defined by Group Management in line with market trends.
In order to manage the interest rate structure for its net debt, the Group uses hedging instruments, particularly interest rate swaps and options.
The Group also uses forward interest rate pre-hedges to protect the refinancing rate of part of its debt. 848 of 1021
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15.1.4.1 Analysis of financial instruments by type of interest rate The following tables present a breakdown by type of interest rate of outstanding borrowings and debt and net financial debt before and after hedging:
15.1.4.2 Interest rate risk sensitivity analysis
Sensitivity was analyzed based on the Group’s net debt position (including the impact of interest rate and foreign currency derivatives relating to net debt) at the reporting date.
For interest rate risk, sensitivity corresponds to a 100-basis-point rise or fall in the yield curve compared to year-end interest rates.
Dec. 31, 2023
Impact on income Impact on equity
In millions of euros +100 basis points -100 basis points +100 basis points -100 basis points Net interest expense on floating-rate net debt (nominal amount) and on floating-rate leg of derivatives (29) 29 NA NA Change in fair value of derivatives not qualifying as
hedges
(39) 43 NA NA
Change in fair value of derivatives qualifying as cash
flow hedges NA NA 280 (343)
15.1.5 Currency and interest rate hedges
15.1.5.1 Currency risk management
Foreign currency exchange risk (or “FX” risk) is reported and managed based on a Group-wide approach, reflected in a policy approved by Group Management. The policy distinguishes between the three following main sources of currency risk:
• Regular transaction risk
Regular transaction risk corresponds to the potential negative financial impact of currency fluctuations on business and financial operations denominated in a currency other than the functional currency.
The management of regular transaction risk is fully delegated to the subsidiaries for their scope of activities, while the risks related to central activities are managed at corporate level.
FX risks related to operational activities are systematically hedged when the related cash flows are certain, with a hedging horizon that corresponds at least to the medium-term plan horizon. For cash flows that are not certain, in their entirety, the hedge is initially based on a “no regret” volume. Exposures are monitored and managed based on the sum of nominal cash flows in FX, including highly probable amounts and related hedges. 849 of 1021
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For FX risks related to financial activities, all significant exposures related to cash, financial debt, etc. are systematically hedged. Exposures are monitored based on the net sum of balance sheet items in FX. • Project transaction risk
Specific project transaction risk corresponds to the potential negative financial impact of FX fluctuations on specific major operations such as investment projects, acquisitions, disposals and restructuring projects, involving multiple currencies.
The management of these FX risks includes the definition and implementation of hedging transactions, taking into account the likelihood of the risk (including probability of project completion) and its evolution, the availability of hedging instruments and their associated cost. Management’s aim is to ensure the viability and the profitability of the transactions.
• Translation risk
Translation risk corresponds to the potential negative financial impact of FX fluctuations concerning consolidated entities with a functional currency other than the euro. It relates to the translation of their income and expenses and their net assets.
Translation risk is managed centrally, with a focus on securing the net asset value.
The relevance of hedging this translation risk is assessed regularly for each currency (as a minimum) or set of assets in the same currency, taking into account notably the value of the assets and the hedging costs.
Hedging instruments and sources of hedge ineffectiveness The Group principally uses the following risk management levers for mitigating currency risk:
• derivative instruments: these mostly correspond to over-the-counter contracts and include FX forward transactions, FX swaps, currency swaps, cross currency swaps, plain vanilla FX options or combinations (calls, puts or collars); • monetary items such as debt, cash and loans.
Sources of hedge ineffectiveness are mainly related to uncertainty regarding the timing and in some cases the amount of the future cash flows in foreign currency that are being hedged.
15.1.5.2 Interest rate risk management
The Group is exposed to interest rate risk through its financing and investing activities. Interest rate risk is defined as a financial risk resulting from fluctuations in base interest rates that may increase the cost of debt and affect the viability of investments. Base interest rates are market interest rates, such as EURIBOR, SOFR, etc., that do not include the borrower’s credit spread.
Reform of interbank benchmark rates
As part of the interest rate benchmark reform in 2022, the Group benchmarked all new USD denominated financing contracts to the SOFR index. It also aligned its existing financing and derivative contracts with the same index in first-half 2023, following the end of the publication of the US Libor at June 30, 2023.
No impact has been recognized by the Group as a result of this transition.
The two main sources of interest rate risk are as follows:
• Interest rate risk relating to Group net debt
Interest rate risk relating to Group net debt designates the financial impact of base rate movements on the debt and cash portfolio from recurring financing activities. This risk is mainly managed centrally. 850 of 1021
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Risk management objectives are, by order of importance:
− to protect the long-term viability of assets;
− to optimize financing costs and ensure competitiveness; and − to minimize uncertainty on the cost of debt.
Interest rate risk is actively managed by monitoring changes in market rates and their impact on the Group’s gross and net debt.
• Project interest rate risk
Specific project interest rate risk corresponds to the potential negative financial impact of base rate movements on specific major operations such as investment projects, acquisitions, disposals and restructuring projects. Interest rate risk after the closing of an operation is considered as regular (see “Interest rate risk”).
Interest rate risk is managed for specific project transactions in order to protect the economic viability of projects, acquisitions, disposals and restructuring initiatives against adverse changes in interest rates. It may include the implementation of hedging transactions, depending on a number of factors including the likelihood of completion, the availability of hedging instruments and their associated cost.
Hedging instruments and sources of hedge ineffectiveness The Group principally uses the following risk management levers for mitigating interest rate risk:
• derivative instruments: these mostly correspond to over-the-counter contracts that are used to manage base interest rates. Such instruments include:
− swaps, to change the nature of interest payments on debts, typically from fixed to floating rates or vice versa, − plain vanilla interest rate options;
• caps, floors and collars that allow the impact of interest rate fluctuations to be limited by setting minimum and/or maximum limits on floating interest rates.
Sources of hedge ineffectiveness are mainly related to changes in the credit quality of the counterparties and related charges, as well as potential gaps in settlement dates and in indices between the derivative instruments and the related underlying exposures.
15.1.5.3 Currency and interest rate hedges
The Group has elected to apply hedge accounting whenever possible and suitable for currency risk and interest rate risk management purposes and also manages a portfolio of undesignated derivative instruments, corresponding to economic hedges relating to net debt and foreign currency exposures.
The Group uses the three hedge accounting methods: cash flow hedging, fair value hedging and net investment hedging.
In general, the Group does not frequently reset hedging relationships, designate specific risk components as a hedged item or designate credit exposures as measured at fair value through income.
The Group qualifies interest rate or cross currency swaps transforming fixed-rate debt into floating-rate debt as fair value hedges.
Cash flow hedges are mainly used to hedge future cash flows in foreign currency, floating-rate debt as well as future refinancing requirements.
Net investment hedging instruments are mainly FX swaps, forwards and cross-currency swaps. 851 of 1021
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The fair values of derivatives (excluding commodity instruments) are indicated in the table below:
Dec. 31, 2023 Dec. 31, 2022
Assets Liabilities Assets Liabilities
In millions of euros
Noncurrent CurrentNoncurrent CurrentNoncurrent CurrentNoncurrent Current Derivatives hedging borrowings 279 111 (457) (131) 226 92 (620) (114) Fair value hedges 190 43 (289) (21) 167 4 (394) (38)
Cash flow hedges 43 ‐ (120) (45) 30 5 (195) (11)
Derivative instruments not qualifying for hedge
accounting 47 68 (48) (66) 30 84 (32) (65)
Derivatives hedging other items 1,501 26 (1,167) (159) 1,975 84 (1,587) (47) Cash flow hedges 189 2 (351) (91) 509 41 (222) (7)
Net investment hedges 180 ‐ (1) ‐ 156 ‐ (1) ‐
Derivative instruments not qualifying for hedge
accounting 1,131 23 (815) (67) 1,310 43 (1,364) (40)
TOTAL 1,780 137 (1,623) (290) 2,201 176 (2,208) (161)
The fair values shown in the table above reflect the amounts relating to the price that would be received for the sale of an asset or paid for the transfer of a liability between market participants in the normal course of business. They are not representative of expected future cash flows insofar as the positions (i) are sensitive to changes in prices or to changes in credit ratings, (ii) can be modified by subsequent transactions, and (iii) can be offset by future cash flows arising on the underlying transactions.
Amount, timing and uncertainty of future cash flows
The following tables provide a profile of the timing at December 31, 2023 of the nominal amount of hedging instruments:
In millions of euros
Buy/Sell
Interest
rate type
Derivative instrument
type Currency Total 2024 2025 2026 2027 2028
Beyond 5
years
Buy Fixed CCS USD (337) (113) (86) (93) ‐ ‐ (45)
GBP (2,589) ‐ ‐ ‐ ‐ (575) (2,014)
EUR (1,230) ‐ ‐ ‐ ‐ (569) (661)
CHF (637) (189) ‐ ‐ (205) ‐ (243)
HKD (266) ‐ ‐ ‐ (104) ‐ (162)
PEN (198) (19) ‐ (61) (61) (56) ‐
Other
currencies
(295) (172) (71) ‐ ‐ ‐ (52)
Floating CCS CLP (46) ‐ ‐ (46) ‐ ‐ ‐
Sell Fixed CCS EUR 3,539 216 75 ‐ 98 638 2,512
USD 1,446 22 ‐ 114 70 607 633
Floating CCS EUR 339 144 ‐ ‐ 195 ‐ ‐
BRL 309 118 93 99 ‐ ‐ ‐
In millions of euros
Buy/Sell
Interest
rate type
Derivative instrument
type Currency Total 2024 2025 2026 2027 2028
Beyond 5
years
Sell Fixed CAP EUR 5 5 ‐ ‐ ‐ ‐ ‐
IRS EUR 9,524 (663) 97 1,216 376 (99) 8,596
USD 1,322 (67) 35 723 296 30 305
ZAR 140 (87) (50) 64 (48) 12 249
Other
currencies
63 3 3 3 3 3 47
Floating IRS EUR 17,643 1,690 2,415 1,950 800 138 10,650 ZAR ‐ (89) (55) 58 (57) 1 142
BRL 59 ‐ ‐ ‐ ‐ 59 ‐
The tables presented above exclude currency derivatives (except for cross currency swaps - CCS). Their maturity dates are aligned with those of the hedged items.
Pursuant to the FX and interest rate risk management policy, FX sensitivity is presented in Note 15.1.3.2 “Currency risk sensitivity analysis” and the average cost of gross debt is 4.31% as presented in Note 10 “Net financial income/(loss)”. 852 of 1021
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Effects of hedge accounting on the Group’s financial position and performance Currency derivatives
Dec. 31, 2023 Dec. 31, 2022
Fair value
Nominal
amount Fair value
Nominal
amount
In millions of euros Assets Liabilities Total Total Total Total Cash flow hedges 51 (581) (530) 4,708 (338) 3,139
Net investment hedges 180 (1) 179 5,596 155 5,939
Derivative instruments not qualifying for
hedge accounting 55 (39) 16 12,086 123 12,007
TOTAL 286 (621) (335) 22,391 (60) 21,085
Interest rate derivatives
Dec. 31, 2023 Dec. 31, 2022
Fair value
Nominal
amount Fair value
Nominal
amount
In millions of euros Assets Liabilities Total Total Total Total Fair value hedges 232 (309) (77) 7,975 (261) 5,148
Cash flow hedges 183 (25) 158 3,399 491 5,260
Derivative instruments not qualifying for
hedge accounting 1,215 (957) 258 25,438 (186) 25,885
TOTAL 1,631 (1,291) 339 36,812 44 36,293
The fair values presented in the above table are positive for assets and negative for liabilities.
In millions of euros
Nominal and
outstanding
amount Fair value (1)
Change in fair
value used for
calculating
hedge
ineffectiveness
Change in
the value of
the hedging
instrument
recognized
in equity (2)
Ineffective
portion
recognized
in profit or
loss (2)
Amount
reclassified
from the
hedge
reserve to
profit or
loss (2)
Line item of
the income
statement
Fair value
hedges
Hedging
instruments 7,975 (77) (77) ‐ ‐ NA Cost of net debt
Hedged items (3) (4) 5,715 (41) 2,076 NA NA
Cash flow
hedges
Hedging
instruments 8,107 (371) (188) 402 (4) (321)
Other financial
income and
expenses /
Current
operating
income
including
operating MtM
Hedged items 186
Net investment
hedges
Hedging
instruments 5,596 179 148 (149) NA 1
Other financial
income and
expenses /
Current
operating
income
including
operating MtM
Hedged items (148)
(1) The adjustment of the fair value of hedged items is presented as long term and short-term borrowings and debt for a negative amount of €-41 million.
(2) Gains/(losses).
(3) The difference between the fair value used to determine the ineffective portion relating to hedging instruments and that relating to the hedged items corresponds to the amortized cost of borrowings and debt that are part of a fair value hedge relationship. (4) Of which €40 million relating to hedging items that are no longer adjusted as a result of discontinuation of the fair value hedge relationship.
Hedge inefficiency is calculated based on the change in the fair value of the hedging instrument compared to the change in the fair value of the hedged items since inception of the hedging relationship. The fair value of the hedging instruments 853 of 1021
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at December 31, 2023 reflects the cumulative change in their fair value since inception of the hedges. The same principle applies to the hedged items.
No significant impact in terms of ineffectiveness or discontinuation of certain hedges was recognized at December 31,2023.
Foreign currency and interest rate derivatives designated as cash flow hedges can be analyzed as follows by maturity In millions of euros 2024 2025 2026 2027 2028
Beyond 5
years
Total at
Dec. 31,
2023
Total at
Dec. 31,
2022
Fair value of derivatives by maturity
date
(64) 23 6 10 (85) (262) (371) 147
Amounts presented in the statement of changes in equity and the statement of comprehensive income The following table provides a reconciliation of each component of equity and an analysis of other comprehensive income:
Cash flow hedge Net investment hedge
In millions of euros
Derivatives hedging
borrowings - currency
risk hedging (1)
Derivatives hedging
other items - interest
rate risk hedging (1) (3)
Derivatives hedging
other items - currency
risk hedging (2)
Derivatives hedging
other items - currency
risk hedging (2) (4)
AT DECEMBER 31, 2022 46 179 35 (386)
Effective portion recognized in equity (381) (21) 149
Amount reclassified from the hedge reserve to
profit or loss 321 ‐ (1)
Translation differences ‐ ‐ ‐ ‐
Changes in scope of consolidation and other ‐ (24) ‐ ‐
AT DECEMBER 31, 2023 45 97 14 (238)
(1) Cash flow hedges for given periods.
(2) Cash flow hedges for given transactions.
(3) Comprises a positive €275 million of cumulated reserves related to hedge transactions (a negative €86 million at December 31, 2022) for which hedge accounting has been discontinued (instruments cancelled prior to their maturity). (4) All of the reserves relate to continuing hedging relationships.
15.2 Counterparty risk
Due to its financial and operational activities, the Group is exposed to the risk of default of its counterparties (customers, suppliers, EPC contractors, partners, intermediaries, and banks). Default could affect payments, delivery of goods and/or asset performance.
The principles of counterparty risk management are set out in the Group counterparty risk policy, which:
• assigns roles and responsibilities for managing and controlling counterparty risk at different levels (Corporate, BU or entity), and ensures operational procedures are in place and consistent across the Group; • characterizes counterparty risk and the mechanisms by which it impacts the economic performance and financial statements of the Group;
• defines indicators, reporting and control mechanisms to ensure visibility and to provide tools for financial performance management; and
• provides guidelines on the use of mitigating mechanisms such as collateral and guarantees, which are widely used by some businesses.
Depending on the nature of the business, the Group is exposed to different types of counterparty risk. As a result some businesses use collateral instruments – particularly the Energy Management business, where the use of margin calls and other types of financial collateral (standardized legal framework) is a market standard. In addition, other businesses may request guarantees from their counterparties in certain cases (parent company guarantees, bank guarantees, etc.). 854 of 1021
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Under the new IFRS 9 standard, the Group has defined and applied a Group-wide methodology, which includes two different approaches:
• a portfolio approach, whereby the Group determines that:
− coherent customer portfolios and sub-portfolios have to be considered (i.e., portfolios that have comparable credit risk and/or comparable payment behavior), taking into account the following aspects:
▪ public or private counterparties,
▪ residential or BtoB counterparties,
▪ geography,
▪ type of activity,
▪ size of the counterparty, and
▪ any other aspects the Group may consider relevant,
− impairment rates must be determined based on historical aging balances and, when correlation is proven and documentation possible, historical data must be adjusted by forward-looking elements; and • an individualized approach for significant counterparties, for which the Group has set rules for defining the stage of the concerned asset for Expected Credit Loss (ECL) calculations:
− stage 1 covers financial assets that have not deteriorated significantly since initial recognition. The ECL for stage 1 is calculated on a 12-month basis,
− stage 2 covers financial assets for which the credit risk has significantly increased. The ECL for stage 2 is calculated on a lifetime basis. The decision to move an asset from stage 1 to stage 2 is based on certain criteria such as:
▪ a significant downgrade in the creditworthiness of a counterparty and/or its parent company and/or its guarantor (if any),
▪ significant adverse change in the regulatory environment, ▪ changes in political or country-related risk, and
▪ any other aspect the Group may consider relevant.
Regarding financial assets that are more than 30 days past due, the move to stage 2 is not systematically applied as long as the Group has reasonable and verifiable information that demonstrates that, even if payments become more than 30 days past due, this does not represent a significant increase in the credit risk since initial recognition. − stage 3 covers assets for which default has already been observed, such as:
▪ when there is evidence of significant and ongoing financial difficulty of the counterparty, ▪ when there is evidence of failure in credit support from a parent company to its subsidiary (in this case the subsidiary is the Group’s at risk counterparty), ▪ when a Group entity has initiated legal proceedings against the counterparty for non-payment.
Regarding financial assets that are more than 90 days past due, the presumption can be rebutted if the Group has reasonable and supportable information that demonstrates that even if payments become more than 90 days past due, this does not indicate counterparty default.
The ECL formula applicable in stages 1 and 2 is ECL = EAD x PD x LGD, where:
• for 12-month ECL, Exposure At Default (EAD) equals the carrying amount of the financial asset, to which the relevant Probability of Default (PD) and the Loss Given Default (LGD) are applied; • for lifetime ECL, the calculation method consists in identifying changes in exposure for each year, especially the expected timing and amount of the contractual repayments, then applying to each repayment the relevant PD and the LGD, and discounting the figures obtained. ECL is then the sum of the discounted figures; and • probability of default is the likelihood of default over a particular time horizon (in stage 1, this time horizon is 12 months after the reporting period; in stage 2 this time horizon is the entire lifetime of the financial asset). This information is based on external data from a reputable rating agency. The PD depends on the time horizon and of 855 of 1021
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the rating of the counterparty. The Group uses external ratings if they are available; ENGIE’s credit risk experts determine an internal rating for major counterparties with no external rating.
LGD levels are notably based on Basel standards:
• 75% for subordinated assets; and
• 45% for standard assets.
For assets considered to be of strategic importance for the counterparty, such as essential public services or goods, LGD is set at 30%.
The Group has decided that write-offs apply in the following situations:
• assets for which a legal recovery procedure is pending: these should not be written off as long as the procedure is ongoing; and
• assets for which no legal recovery procedure is pending: these should be written off once the trade receivable is 3 years overdue (5 years overdue for public counterparties).
In the context of its market activities (mainly concerning BtoB customers), the Group takes into account forward-looking information when assessing its expected credit losses, in order to best reflect the situation in a series of economic sectors deemed to be the most critical. Accordingly, the specific adjustment to the provisioning rate for expected credit losses made at December 31, 2022 on certain business sectors particularly exposed to fluctuations in commodity prices was maintained during the year, in the absence of a significant and lasting improvement in the general economic context.
In addition, the risk of default on the Group's BtoC energy supply activities has evolved differently in each country, depending on the mechanisms put in place. In France, for example, the risk of default has risen due to the end of government measures (i.e. gas tariff shield, energy vouchers) aimed at limiting price increases. This is reflected in longer collection times and more frequent requests for payment instalment plans. Conversely, lower prices in Belgium and the protection mechanisms put in place by the Romanian government have reduced our exposure to credit risk.
15.2.1 Counterparty risk arising on operating activities Counterparty risk arising on operating activities is managed via standard mechanisms such as third-party guarantees, netting agreements and margin calls, using dedicated hedging instruments or special prepayment and debt recovery procedures, particularly for retail customers.
Under the Group’s policy, each global business unit is responsible for managing counterparty risk, although the Group continues to manage the biggest counterparty exposures centrally.
For large and medium-sized customers with which the Group's credit risk exposure exceeds a certain threshold, a specific, comprehensive rating determination model is used to assess the Group's credit risk exposure as accurately as possible.
A simplified scoring model is used for customers for whom the Group's credit risk exposure is lower. These processes are based on formally documented, consistent methods across the Group. Consolidated exposures are monitored by counterparty and by segment (credit rating, sector, etc.) using standard indicators (payment risk, mark-to-market exposure).
GEMS' large exposures to trading counterparties and large commercial clients are regularly monitored by the Group's governance committees.
15.2.1.1 Trade and other receivables, assets from contracts with customers Total outstanding exposures presented in the tables below do not include impacts relating to VAT or to any other item not subject to credit risk, which amounted to €4,579 million at December 31, 2023 (compared to €6,084 million at December 31, 2022).
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Individual approach
Dec. 31, 2023
In millions of euros
Individual
approach
Level 1:
low credit
risk
Level 2:
increased
credit risk
Level 3:
impaired
assets
Total by
risk level
Investment
Grade (1) Other
Total by
counterparty
type
Trade and other
receivables, net
Gross 13,653 12,304 1,248 101 13,653 11,533 2,121 13,653 Expected
credit losses (909) (696) (116) (97) (909) (594) (315) (909) TOTAL 12,745 11,609 1,132 4 12,745 10,939 1,806 12,745
Assets from
contracts with
customers
Gross 4,377 4,374 2 ‐ 4,377 3,299 1,078 4,377
Expected
credit losses (22) (22) ‐ ‐ (22) (15) (7) (22)
TOTAL 4,354 4,352 2 ‐ 4,354 3,284 1,070 4,354
Dec. 31, 2022
In millions of euros
Individual
approach
Level 1:
low credit
risk
Level 2:
increased
credit risk
Level 3:
impaired
assets
Total by
risk level
Investment
Grade (1) Other
Total by
counterpart
y type
Trade and other
receivables, net
Gross 22,754 21,321 1,316 118 22,754 20,668 2,086 22,754 Expected
credit losses (737) (533) (75) (129) (737) (452) (285) (737) TOTAL 22,017 20,787 1,241 (11) 22,017 20,216 1,801 22,017 Assets from
contracts with
customers
Gross 5,277 5,245 29 3 5,277 4,100 1,177 5,277
Expected
credit losses (20) (16) ‐ (4) (20) (13) (7) (20)
TOTAL 5,256 5,229 29 (1) 5,256 4,087 1,169 5,256
(1) Investment Grade corresponds to counterparties that are rated at least BBB- by Standard & Poor’s.
Collective approach
Dec. 31, 2023
In millions of euros
Collective
approach 0 to 6 months 6 to 12 months beyond
Total past due
assets at Dec.
31, 2022
Trade and other receivables,
net
Gross 3,953 420 212 199 831
Expected credit
losses (1,153) (20) (40) (216) (275)
TOTAL 2,800 400 173 (16) 557
Assets from contracts with
customers
Gross 5,194 31 85 3 119
Expected credit
losses (5) ‐ (2) ‐ (2)
TOTAL 5,189 31 83 3 117
Dec. 31, 2022
In millions of euros
Collective
approach 0 to 6 months 6 to 12 months beyond
Total past due
assets at Dec.
31, 2021
Trade and other receivables,
net
Gross 4,459 300 101 272 673
Expected credit
losses (1,151) (19) (47) (172) (238)
TOTAL 3,308 281 54 100 435
Assets from contracts with
customers
Gross 7,370 8 ‐ 1 10
Expected credit
losses (27) ‐ (8) ‐ (8)
TOTAL 7,343 8 (8) 1 2
15.2.1.2 Commodity derivatives
In the case of commodity derivatives, counterparty risk arises from positive fair value. When calculating the fair value of these derivative instruments, counterparty risk (CVA) is based on default probabilities whose parameters have been updated, in a context of uncertainty, to take account of an increased risk of default. 857 of 1021
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The volatility of commodity prices and the impact on the valuation of derivatives on the assets side of the balance sheet have not significantly altered the Group's exposure due to the credit quality of its counterparties.
Dec. 31, 2023 Dec. 31, 2022
In millions of euros
Investment
Grade(1) Total
Investment
Grade(1) Total
Gross exposure (2) 15,954 19,324 36,371 46,012
Net exposure (3) 6,385 8,050 12,434 16,124
% of credit exposure to "Investment Grade" counterparties 79.3% 77.1% (1) Investment Grade corresponds to transactions with counterparties that are rated at least BBB- by Standard & Poor’s, Baa3 by Moody’s, or equivalent by Dun & Bradstreet. “Investment Grade” is also determined based on an internal rating tool that has been rolled out within the Group, and covers its main counterparties. (2) Corresponds to the maximum exposure, i.e. the value of the derivatives shown under assets (positive fair value). (3) After taking into account the liability positions with the same counterparties (negative fair value), collateral, netting agreements and other credit enhancement techniques.
15.2.2 Counterparty risk arising on financing activities For its financing activities, the Group has put in place procedures for managing and monitoring risk based on (i) the accreditation of counterparties according to external credit ratings, objective market data (credit default swaps, market capitalization) and financial structure, and (ii) counterparty risk exposure limits.
To reduce its counterparty risk exposure, the Group has drawn increasingly on a structured legal framework based on master agreements (including netting clauses) and collateralization contracts (margin calls).
The oversight procedure for managing counterparty risk arising from financing activities is managed by a Middle Office that operates independently of the Group’s Treasury department and reports to the Finance division.
15.2.2.1 Loans and receivables at amortized cost
The total outstanding exposures presented in the tables below do not include impacts relating to VAT or to any other item not subject to credit risk, which amounted to €425 million at December 31, 2023 (compared to €547 million at December 31, 2022).
Dec. 31, 2023
In millions of euros
Level 1: low
credit risk
Level 2:
increased
credit risk
Level 3:
impaired
assets
Total by risk
level
Investment
Grade (1) Other
Total by
counterparty
type
Gross 8,879 285 700 9,865 5,754 4,111 9,865
Expected credit losses (78) (45) (1,180) (1,302) (174) (1,128) (1,302) TOTAL 8,802 240 (479) 8,563 5,580 2,983 8,563
Dec. 31, 2022
In millions of euros
Level 1: low
credit risk
Level 2:
increased
credit risk
Level 3:
impaired
assets
Total by risk
level
Investment
Grade (1) Other
Total by
counterparty
type
Gross 6,596 274 720 7,591 3,490 4,101 7,591
Expected credit losses (99) (38) (1,154) (1,291) (158) (1,133) (1,291) TOTAL 6,497 236 (434) 6,300 3,332 2,967 6,300
(1) Investment Grade corresponds to counterparties that are rated at least BBB- by Standard & Poor’s.
In 2022, the Group had impaired the loan related to the financing of the Nord Stream 2 pipeline project for a total amount of €987 million (including capitalized interest).
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15.2.2.2 Counterparty risk arising on investing activities and the use of derivative financial instruments
The Group is exposed to counterparty risk arising on investments of surplus cash and from the use of derivative financial instruments. In the case of financial instruments at fair value through income, counterparty risk arises on instruments with a positive fair value. Counterparty risk is taken into account when calculating the fair value of these derivative instruments.
Dec. 31, 2023 Dec. 31, 2022
In millions of
euros Total
Investment
Grade (1) Unrated (2)
Non
InvestmentGrade (2) TotalInvestment
Grade (1) Unrated (2)
NonInvestment
Grade (2)
Exposure 17,577 89.6% 3.3% 7.1% 15,738 92.3% 4.5% 3.2%
(1) Investment Grade corresponds to counterparties that are rated at least BBB- by Standard & Poor’s or Baa3 by Moody’s. (2) The bulk of these two exposures is carried by consolidated companies that include non-controlling interests, or by Group companies that operate in emerging countries, where cash cannot be pooled and is therefore invested locally.
Furthermore, at December 31, 2023, Crédit Agricole SA is the main Group counterparty and represents 31% of cash surpluses. This relates mainly to a depositary risk.
15.3 Liquidity risk
In the context of its operating activities, the Group is exposed to a risk of having insufficient liquidity to meet its contractual obligations. As well as the risks inherent in managing working capital requirements (WCR), margin calls are required in certain market activities, which are a way of mitigating counterparty risk on hedging instruments through the use of collateral.
The Group has set up a committee that meets weekly and is tasked with managing and monitoring liquidity risk throughout the Group, by maintaining a broad range of investments and sources of financing, and preparing forecasts of cash investments and divestments. ENGIE has set up a comprehensive framework to monitor and streamline cash movements related to OTC margin calls and margin calls via clearing houses, based on the use of liquidity swaps with its key counterparties, as well as the issuing of letters of credit. Given the current volatility of the markets, these margin calls may have a significant timing impact on the Group’s cash position, and the use of the two above-mentioned levers has therefore been reinforced in order to monitor the impact on its cash position. Quarterly stress-tests are also performed on the margin calls put in place when commodity, interest rate and currency derivatives are negotiated to assess the Group’s resilience in terms of liquidity.
The Group centralizes virtually all the financing needs and cash flow surpluses of the companies it controls, as well as most of their medium- and long-term external financing requirements. Centralization is provided by financing vehicles (long-term and short-term) and by dedicated Group cash pooling vehicles based in France, Belgium and Luxembourg.
Surpluses held by these structures are managed in accordance with a uniform policy. In accordance with this policy, unpooled cash surpluses are invested in instruments selected on a case-by-case basis in light of local financial market imperatives and the financial strength of the counterparties concerned.
The succession of financial crises since 2008 and the ensuing rise in counterparty risk prompted the Group to tighten its investment policy with the aim of keeping an extremely high level of liquidity and protecting invested capital, with a daily monitoring of performance and counterparty risk, allowing the Group to take immediate action where required in response to market developments. Consequently, 89% of the cash pooled at December 31, 2023 was invested in overnight bank deposits and standard money market funds with daily liquidity.
The Group’s financing policy is based on:
• centralizing external financing;
• diversifying sources of financing between credit institutions and capital markets; • achieving a balanced debt repayment profile.
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The Group seeks to diversify its sources of financing by carrying out public or private bond issues within the scope of its Euro Medium Term Notes program. It also issues negotiable commercial paper in France (Negotiable European Commercial Paper) and in the United States (U.S. Commercial Paper) as well as deeply-subordinated perpetual notes. As negotiable commercial paper is relatively inexpensive and highly liquid, it is used by the Group in a cyclical or structural manner to finance its short-term cash requirements. However, the refinancing of all outstanding negotiable commercial paper remains secured by confirmed bank lines of credit – mainly centralized – allowing the Group to continue to finance its activities if access to this financing source were to dry up. These facilities are appropriate for the scale of its operations and for the timing of contractual debt repayments.
The various actions carried out by the Group ensure a high and reinforced level of liquidity.
Diversifying sources of financing and liquidity (1)
In millions of euros
(1) These sources of financing and liquidity do not include the deeply-subordinated perpetual notes recognized in equity (see Note 16.2.1 “Issuance of deeply-subordinated perpetual notes”). (2) Net amount of negotiable commercial paper.
(3) Cash corresponds to cash and cash equivalents for €16,578 million, other financial assets deducted from net financial debt for €884 million, net of bank overdrafts and current accounts for €455 million, of which 76% was invested in the Eurozone.
At December 31, 2023, all Group entities whose debt is consolidated complied with the covenants and declarations included in their financial documentation, except for some non-significant entities for which compliance actions are being implemented. There are no defaults linked to financial ratios or rating levels on available centralized credit lines.
15.3.1 Undiscounted contractual payments relating to financial activities Undiscounted contractual payments on outstanding borrowings and debt by maturity In millions of euros 2024 2025 2026 2027 2028
Beyond 5
years
Total at Dec.
31, 2023
Total at
Dec. 31,
2022
Bond issues 1,039 1,463 2,922 3,130 3,230 18,472 30,256 23,557 Bank borrowings 763 485 387 637 245 4,231 6,748 5,476
Negotiable commercial paper 5,606 ‐ ‐ ‐ ‐ ‐ 5,606 7,386 Lease liabilities 510 480 398 365 407 2,552 3,147 2,875 Other borrowings 92 22 3 3 2 244 366 374
Bank overdrafts and current accounts 455 ‐ ‐ ‐ ‐ ‐ 455 615 Other financial assets and cash and cash equivalents deducted from net financial debt have a liquidity of less than one year.
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Undiscounted contractual interest payments on outstanding borrowings and debt by maturity In millions of euros 2024 2025 2026 2027 2028
Beyond 5
years
Total at Dec.
31, 2023
Total at
Dec. 31,
2022
Undiscounted contractual interest flows on
outstanding borrowings and debt 1,319 1,267 1,230 1,116 1,053 10,915 16,900 11,131 Undiscounted contractual payments on outstanding derivatives (excluding commodity instruments) by maturity In millions of euros 2024 2025 2026 2027 2028
Beyond 5
years
Total at Dec.
31, 2023
Total at
Dec. 31,
2022
Derivatives (excluding commodity instruments) (233) 1 18 17 (20) 743 527 239 To better reflect the economic substance of these transactions, the cash flows linked to the derivatives recognized in assets and liabilities shown in the table above relate to net positions.
Undiscounted contractual payments related to leases
At December 31, 2023, the Group, as lessee, was potentially exposed to future cash outflows not reflected in the measurement of lease liabilities for €1,045 million (of which approximately 75% relate to potential cash outflows beyond 2028). Those potential future cash outflows relate to leases not yet commenced to which the Group is committed (real estate and LNG vessels).
In addition, the Group is also exposed to future cash outflows in the form of variable lease payments in connection with the extension of the Rhone concession. These variable lease payments are dependent on revenue from electricity sales.
Undrawn credit facility programs
In millions of euros 2024 2025 2026 2027 2028
Beyond 5
years
Total at Dec.
31, 2023
Total at
Dec. 31,
2022
Confirmed undrawn credit facility programs 1,619 738 552 ‐ 8,500 822 12,231 12,511 Of these undrawn programs, an amount of €5,606 million is allocated to covering commercial paper.
At December 31, 2023, no single counterparty represented more than 10% of the Group’s confirmed undrawn credit lines.
15.3.2 Undiscounted contractual payments relating to operating activities The table below provides an analysis of undiscounted fair values due and receivable in respect of commodity derivatives recorded in assets and liabilities at the reporting date.
The Group provides an analysis of residual contractual maturities for commodity derivative instruments included in its portfolio management activities. Derivative instruments relating to trading activities are considered to be liquid in less than one year, and are presented under current items in the statement of financial position.
In millions of euros 2024 2025 2026 2027 2028
Beyond 5
years
Total at Dec. 31,
2023
Total at Dec. 31,
2022
Derivative instruments carried in
liabilitiesrelating to portfolio management
activities
(5,831) (497) (9,539) (2,971) (1,249) (994) (21,080) (49,260) relating to trading activities (1,787) ‐ ‐ ‐ ‐ ‐ (1,787) ‐ Derivative instruments carried in assets
relating to portfolio management
activities
5,624 341 6,682 2,934 681 472 16,734 40,975
relating to trading activities 2,766 ‐ ‐ ‐ ‐ ‐ 2,766 5,098 TOTAL 772 (155) (2,857) (37) (568) (522) (3,366) (3,187) 861 of 1021
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15.3.3 Commitments relating to commodity purchase and sale contracts entered into in the ordinary course of business
Some Group operating companies have entered into long-term contracts, some of which include “take-or-pay” clauses.
These consist of firm commitments to purchase or sell specified quantities of gas, electricity or steam as well as related services, in exchange for a firm commitment from the other party to deliver or purchase said quantities and services. These contracts were documented as falling outside the scope of IFRS 9. The table below shows the main future commitments arising from contracts entered into by GBU Renewables and GEMS (expressed in TWh).
In TWh 2024 2025-2028 Beyond 5 years
Total at Dec. 31,
2023
Total at Dec. 31,
2022
Firm purchases (450) (566) (1,134) (2,150) (1,884)
Firm sales 617 470 224 1,310 1,243
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NOTE 16 EQUITY
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NOTE 16 EQUITY
16.1 Share capital
Number of shares Value
(in millions of euros)
Total Treasury stock Outstanding Share capital
Additional paid-in
capital Treasury stock
AT DECEMBER 31, 2022 2,435,285,011 (14,530,427) 2,420,754,584 2,435 25,667 (189) Dividend paid in cash ‐ ‐ ‐ ‐ (1,752) ‐
Purchase/disposal of treasury stock ‐ (3,755,821) (3,755,821) ‐ ‐ (53) Delivery of treasury stock (bonus) ‐ 4,450,881 4,450,881 ‐ ‐ 65 AT DECEMBER 31, 2023 2,435,285,011 (13,835,367) 2,421,449,644 2,435 23,916 (177) Changes in the number of outstanding shares in 2023 resulted exclusively from the disposal of 0.7 million treasury shares, as part of bonus share plans.
16.1.1 Potential share capital and instruments providing a right to subscribe for new ENGIE SA shares
Since 2017, the Group no longer has any stock purchase or subscription option plans.
Shares to be allocated under the performance share award plans described in Note 19 “Share-based payments” are covered by existing ENGIE SA shares.
16.1.2 Treasury stock
Accounting standards
Treasury shares are recognized at acquisition cost and deducted from equity. Gains and losses on disposals of treasury shares are recorded directly in equity and do not, therefore, impact income for the period.
The Group has a stock repurchase program as a result of the authorization granted to the Board of Directors by the Ordinary and Extraordinary Shareholders’ Meeting of April 26, 2023. This program provides for the repurchase of up to 10% of the shares comprising the share capital of ENGIE SA at the date of the said Shareholders’ Meeting. The aggregate amount of acquisitions net of expenses under the program may not exceed €7.3 billion, and the purchase price must be less than €30 per share excluding acquisition costs.
At December 31, 2023, the Group held 13.8 million treasury shares. To date, all the shares have been allocated to cover the Group's share commitments to employees and corporate officers.
The liquidity agreement signed with an investment service provider assigns to the latter the role of operating on the market on a daily basis, to buy or sell ENGIE SA shares, in order to ensure liquidity and an active market for the shares on the Paris and Brussels stock exchanges. To date, the resources allocated to the implementation of this agreement amount to €55 million.
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16.2 Other disclosures concerning additional paid-in capital, consolidated reserves and issuance of deeply-subordinated perpetual notes (Group share)
Total additional paid-in capital, consolidated reserves and issuance of deeply subordinated perpetual notes (including net income for the year), amounted to €32,507 million at December 31, 2023, including €23,916 million in additional paid-in capital. Additional paid-in capital includes a portion of the cash dividend payment for 2022 in an amount of €1,752 million.
Consolidated reserves include the cumulative income of the Group, the legal and statutory reserves of ENGIE SA, cumulative actuarial gains and losses, net of tax and the change in fair value of equity instruments at fair value through OCI.
Under French law, 5% of the net income of French companies must be allocated to the legal reserve until the latter reaches 10% of share capital. This reserve can only be distributed to shareholders in the event of liquidation. The ENGIE SA legal reserve amounts to €244 million.
16.2.1 Issuance of deeply subordinated perpetual notes
In accordance with IAS 32 (Financial Instruments: Presentation), and given their characteristics, these instruments are recognized in equity in the Group's consolidated financial statements.
At December 31, 2023, the outstanding nominal value of deeply subordinated perpetual notes amounted to €3,393 million.
No movements have been recorded since December 31, 2022.
In 2023, the Group paid €80 million to the holders of these notes. This amount is accounted for as a deduction from equity in the Group's consolidated financial statements; the related tax saving is accounted for in the income statement.
16.2.2 Distributable capacity of ENGIE SA
ENGIE SA's distributable capacity totaled €24,537 million at December 31, 2023 (compared with €27,365 million at December 31, 2022), including €23,916 million of additional paid-in capital.
16.2.3 Dividends
The Shareholders’ Meeting of 26 April 2023 approved the payment of a unit dividend of €1.40 per share in respect of the 2022 financial year. In accordance with Article 26.2 of the Articles of Association, a bonus dividend of 10%, i.e. €0.14 per share, has been allocated to shares which have been held from for at least two years at December 31, 2022, and which have remained continuously registered in this form in the name of the same shareholder until the dividend payment date.
This bonus dividend may not apply to a number of shares representing more than 0.5% of the share capital for any one shareholder. On May 3, 2023, the Group paid a cash dividend of €3,391 million, including the dividend of €1.40 per share for shares eligible for the ordinary dividend, and a loyalty bonus of €36 million.
Proposed dividend in respect of 2023
At the Shareholders’ Meeting convened to approve the ENGIE Group financial statements for the year ended December 31, 2023, the shareholders will be asked to approve a dividend of €1.43 per share, representing a total payout of €3,482 million based on the number of shares outstanding at December 31, 2023. It will be increased by 10% for all shares held for at least two years at December 31, 2023 and up to the 2023 dividend payment date. Based on the number of outstanding shares at December 31, 2023, this increase is valued at €38 million. 864 of 1021
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Subject to approval by the Shareholders’ Meeting of Tuesday April 30, 2024, this dividend will be detached on Thursday May 2, 2024 and paid on Monday May 6, 2024. It is not recognized as a liability in the financial statements at December 31, 2023, since the financial statements at the end of 2023 were presented before the appropriation of earnings.
16.3 Recyclable gains and losses recognized in equity (Group share) All items shown in the table below correspond to cumulative gains and losses (Group share) at December 31, 2023 and December 31, 2022, which are recyclable to income in subsequent periods.
In millions of euros Dec. 31, 2023 Dec. 31, 2022
Debt instruments (44) (369)
Net investment hedges (1) (238) (386)
Cash flow hedges (excl. commodity instruments) (1) 145 218 Commodity cash flow hedges (1) (3,998) (318)
Deferred taxes on the items above 786 (112)
Share of equity method entities accounted in recyclable items, net of tax (2) 334 300 Recyclable items relating to discontinued operations, net of tax ‐ ‐ TOTAL RECYCLABLE ITEMS BEFORE TRANSLATION ADJUSTMENTS (3,015) (668) Translation adjustments (1,693) (1,422)
TOTAL RECYCLABLE ITEMS (4,708) (2,090)
(1) See Note 15 “Risks arising from financial instruments”. (2) See Note 3 “Investments in equity method entities”.
16.4 Capital management
ENGIE SA seeks to optimize its financial structure at all times by pursuing an optimal balance between its economic net debt and its EBITDA. The Group's key objective in managing its financial structure is to maximize value for shareholders and reduce the cost of capital, while ensuring that the Group has the financial flexibility required to continue its expansion.
The Group manages its financial structure and makes any necessary adjustments in light of prevailing economic conditions. In this context, it may choose to adjust the amount of dividends paid to shareholders, reimburse a portion of capital, carry out share buybacks (see Note 16.1.2 “Treasury stock”), issue new shares, launch share-based payment plans, recalibrate its investment budget, or sell assets in order to scale back its net debt.
The Group's policy is to maintain an “strong investment grade” rating from the rating agencies. To achieve this, it manages its financial structure in line with the indicators usually monitored by these agencies, namely the Group's operating profile, financial policy and a series of financial ratios. One of the most commonly used ratios is the ratio where the numerator includes operating cash flows less cost of debt and taxes paid, and the denominator includes adjusted net financial debt.
Net financial debt is mainly adjusted for nuclear provisions and provisions for pensions, as well as for 50% of hybrid debt (deeply-subordinated notes). In addition, the Group has issued a guidance targeting an “economic net debt to EBITDA” ratio less than or equal 4x.
The Group’s objectives and processes for managing capital have remained unchanged over the past few years.
ENGIE SA is not obliged to comply with any external minimum capital requirements except those provided for by law. 865 of 1021
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NOTE 17 PROVISIONS
Accounting standards
General principles related to the recognition of a provision The Group recognizes a provision where it has a present obligation (legal or constructive) towards a third party arising from past events and where it is probable that an outflow of resources will be necessary to settle the obligation with no expected consideration in return.
A provision for restructuring costs is recognized when the general criteria for setting up a provision are met, i.e., when the Group has a detailed formal plan relating to the restructuring and has raised a valid expectation in those affected that it will carry out the restructuring by starting to implement that plan or announcing its main features to those affected by it.
Provisions with a maturity of over 12 months are discounted when the effect of discounting is material. The Group’s main long-term provisions are provisions for the back-end of the nuclear fuel cycle, provisions for dismantling facilities, provisions for site restoration costs, and provisions for post-employment and other long-term benefits. The discount rates used reflects current market assessments of the time value of money and the risks specific to the liability concerned. Expenses with respect to unwinding the discount on the provision are recognized as other financial income and expenses.
Estimates of provisions
Factors having a significant influence on the amount of provisions, and particularly, but not solely, those relating to the back-end of the nuclear fuel cycle, to the dismantling of nuclear facilities and of gas infrastructures in France, include:
• cost estimates (see Note 17.2);
• the timing of expenditure (notably the timetable for the end of gas operations regarding the main gas infrastructure businesses in France) (see Notes 17.2 and 17.3); and • the discount rate applied to cash flows.
These factors are based on information and estimates deemed by the Group to be the most appropriate as of today.
Modifications to certain factors could lead to a significant adjustment in these provisions. 866 of 1021
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In millions of euros
Postemployment and
other long-term
benefits
Back-end of the
nuclear fuel
cycle and
dismantling of
nuclear facilities
Dismantling of
non-nuclear
facilities
Other
contingencies Total
AT DECEMBER 31, 2022 4,471 19,017 1,330 2,209 27,027
Additions 264 5,271 107 557 6,198
Utilizations (315) (327) (75) (671) (1,388)
Reversals ‐ ‐ ‐ (36) (35)
Changes in scope of consolidation (6) ‐ 15 ‐ 8
Impact of unwinding discount adjustments 161 581 47 14 803 Translation adjustments 1 ‐ (21) (3) (22)
Other 631 (655) (18) 44 2
AT DECEMBER 31, 2023 5,208 23,887 1,384 2,114 32,593
Non-current 5,126 11,948 1,384 334 18,792
Current (1) 82 11,939 ‐ 1,780 13,801
(1) The classification of liabilities as current or non-current reflects the effects of the agreement signed with the Belgian State on June 29, 2023 (which became binding on July 21, 2023), the implementation of which was specified in the transaction documents of December 13, 2023 (see Note 17.2). The Group will settle a large portion of this liability (€11.5 billion2022) when the laws transposing this agreement come into force, and will settle the remaining balance (€3.5 billion2022) when the extended units are restarted at the end of 2025.
The impact of unwinding discount adjustments in respect of post-employment and other long-term benefits relates to the interest expense on the benefit obligation, net of interest income on plan assets.
The “Other” line mainly comprises actuarial gains and losses arising on post-employment benefit obligations in 2023, which are recorded in “Other comprehensive income” as well as reversals of provisions recorded against a dismantling or site rehabilitation asset, notably due to the effect induced by the CNP’s final opinion of July 7, 2023 (see Note 17.2).
Additions, utilizations, reversals and the impact of unwinding discount adjustments are presented as follows in the consolidated income statement:
In millions of euros Dec. 31, 2023
Income/(loss) from operating activities (4,774)
Other financial income and expenses (824)
TOTAL (5,598)
The different types of provisions and the calculation principles applied are described below.
17.1 Post-employment benefits and other long-term benefits See Note 18 “Post-employment benefits and other long-term benefits”.
17.2 Obligations relating to nuclear power generation activities
17.2.1 Current legal context and expected developments following the agreement signed with the Belgian State on June 29, 2023 which became binding on July 21, 2023, the implementation of which was specified in the transaction documents of December 13, 2023
The Belgian law of April 11, 2003, partially repealed and amended by the law of July 12, 2022, granted Group subsidiary Synatom responsibility for managing provisions set aside to cover the costs of dismantling nuclear power plants and managing spent fuel.
The tasks of the Commission for Nuclear Provisions (CNP), set up pursuant to the above-mentioned law, are to oversee the process of computing and managing these provisions. In accordance with the law, every three years the CNP conducts an audit of the application and adequacy of the calculation methods used to compute nuclear provisions. 867 of 1021
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In this context, the CNP issued a final opinion on July 7, 2023 on the proposals submitted by Synatom in September 2022.
The provisions recorded by Synatom as of December 31, 2023 take full account of the comments and assumptions made by the CNP. In 2023, this opinion mainly resulted in a €0.6 billion reduction in the provision for dismantling, offset by an adjustment in the book value of dismantling assets, part of which was the subject of an impairment loss reversal (€0.4 billion). The provisions therefore include, in their assumptions, all existing or planned environmental regulatory requirements on a European, national and regional level.
On June 29, 2023, the Group signed an agreement with the Belgian government which became binding on July 21, 2023, the implementation of which was specified in the transaction documents of December 13, 2023. This agreement provides for:
• the 10-year extension of the Doel 4 and Tihange 3 nuclear reactors as part of a 50/50 partnership between the Belgian State and the Group, contingent upon the implementation of a contract for difference protecting ENGIE against market risks; and
• the transfer of financial responsibility to the Belgian State for managing nuclear waste and spent fuel in return for the payment of a lump sum discharge amount of €15 billion2022, within the limit of a volumetric credit covering all nuclear waste produced by the Belgian power plants during their legal operating life, from commissioning to dismantling.
This agreement is binding on both parties. Although it assumes the enactment and entry into force of draft laws included in the agreement, and the European Commission's assent to state aid, its closing (following the release from or fulfillment of conditions precedent) is considered highly probable. The transfer of financial responsibility for the management of nuclear waste and spent fuel meeting the transfer criteria will be concluded at closing, unless the units are not restarted before November 1, 2027 due to serious negligence on the part of ENGIE. In this highly unlikely event, the Belgian State may cancel the agreement on the lump sum discharge and revert to the current system in which the nuclear operator bears the financial responsibility. The amounts already paid by the Group would accordingly be held in escrow for the benefit of the transferred nuclear provisions until the end of the dismantling program, including nuclear waste and back-end nuclear fuel cycle management.
The Group will settle its liability of €15 billion2022 by means of a payment of €11.5 billion2022 for category B and C waste (highly radioactive wastes, that are intended for geological storage) at the time of closing, after which it will settle the balance for category A waste (low-level radioactive wastes, that are intended for surface storage), i.e., €3.5 billion2022, when the extended units are restarted at the end of 2025. These amounts at December 31, 2022 are subject to a 3% indexation effective from January 1, 2023 until the date of payment.
As a result, the Group has increased its provisions by an amount corresponding to the balance between the liabilities already set aside for future nuclear waste treatment costs and the lump sum amount of €15 billion2022, i.e., an amount of €5.1 billion2022 (including Electrabel’s partners’ share in certain power plants for €0.4 billion). As a result, the Group recognized a net expense of €4.8 billion in “Other items of income/(loss) from operating activities” (see Note 9).
At the end of this agreement, the Group will essentially retain responsibility for the on-site storage of spent fuel waste until the end of the dismantling operations and until 2050 at the latest, as well as for the conditioning of all waste in accordance with the contractual agreement (see Note 17.2). The Group will also remain responsible for the final shutdown of the reactors, their dismantling and the clean-up of the site at the end of their operating life. The process of setting up and managing all these provisions, for which the Group is responsible, will continue to be reviewed by the CNP every 3 years.
17.2.2 Provisions for the back-end of the nuclear fuel cycle When spent nuclear fuel is removed from a reactor and temporarily stored on-site, it requires conditioning, before being consigned to long-term storage.
As part of the implementation of a final payment for the transfer of financial responsibility for managing the storage and disposal of nuclear waste and spent fuel, as provided for in the agreement, the risks associated with this liability, as described in the consolidated financial statements at December 31, 2022 (see Note 17.2 “Obligations relating to nuclear power generation activities”), have been considerably reduced. The agreement stipulates that the State will bear financial responsibility for managing all spent fuel after its transfer to ONDRAF (National agency for radioactive waste and enriched 868 of 1021
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fissile materials). The Group will settle a large portion of this liability (classified as current in the accounts) plus a risk premium for a total of €10.5 billion2022.
With regard to waste management, the Group's responsibility will be essentially limited to on-site storage of fuel elements until the end of dismantling operations, and until 2050 at the latest, as well as compliance with the contractual criteria for transferring waste to ONDRAF, whose liability is estimated at €1.7 billion2022 in the draft law implementing the agreement.
Provisions not covered in the agreement are calculated based on the following principles and inputs:
• storage costs primarily comprise the costs of building and operating additional dry storage facilities and operating existing facilities, along with the costs of purchasing containers; • radioactive spent fuel that has not been reprocessed is to be conditioned, which requires conditioning facilities to be built according to ONDRAF's approved criteria. ONDRAF's recommendations as regards the cost of these facilities have been fully taken into account;
• the discount rate used by the CNP (for the part not covered by the agreement with the Belgian government) is
3.0% (including inflation of 2.0%).
The costs effectively incurred in the future may differ from the estimates in terms of their nature and timing of payment.
Certain ONDRAF recommendations from the 2022 triennial revision of nuclear provisions that could not yet be quantified will be specifically examined under the oversight of the CNP within the context of the next triennial review.
Sensitivity
Following the assumption by the Belgian State of all obligations relating to nuclear waste after its transfer to ONDRAF, the Group will only remain exposed to changes in future storage and conditioning costs and the corresponding discounting inputs prior to the transfer.
• The costs of building dry storage facilities and purchasing fuel element containers at the Group's sites could differ from those covered by the provisions. A 10% change in these costs, still to incur would represent a €60 million change in provisions.
• A 10% change in the annual operating costs of the storage facilities would result in a €30 million change in the provision.
• A 25 basis point change in the discount rate would result in a €40 million adjustment to non-transferred provisions.
A fall in the discount rate would lead to an increase in outstanding provisions, while a rise in the discount rate would reduce the provisions' amount.
It should be noted that the risk of exceeding volumetric credits is considered, at this stage, to be highly unlikely, as the volumetric credits established in the agreement have incorporated the volumetric contingencies estimated as part of the provision review in 2022.
17.2.3 Provisions for dismantling nuclear facilities
Accounting standards
A provision is recognized when the Group has a present legal or constructive obligation to dismantle facilities or to restore a site. The present value of the obligation at the time of commissioning represents the initial amount of the provision for dismantling with, as the counterpart, an asset for the same amount, which is included in the carrying amount of the facilities concerned. This asset is depreciated over the operating life of the facilities and is included in the scope of assets subject to impairment tests. Adjustments to the provision due to subsequent changes in (i) the expected outflow of resources, (ii) the timing of dismantling expenses or (iii) the discount rate, are deducted from or subject to specific conditions, added to the cost of the corresponding asset. The impacts of unwinding the discount each year are recognized in expenses for the period.
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A provision is also recorded for nuclear units for which the Group holds a capacity right up to its share of the expected dismantling costs to be borne by the Group.
At the end of their operating life, the nuclear power plants must be shut down for the period during which spent fuel is unloaded from the plant, and until the site is decommissioned and cleaned up.
The dismantling strategy is based on the facilities being dismantled (i) immediately after the reactor is shut down, (ii) on a mass basis rather than on a unit-by-unit basis, and (iii) completely, the land being subsequently returned to greenfield status.
Until December 31, 2022, the amount of these dismantling provisions included costs related to handling Class A – low or medium activity and short-lived – and B – low or medium activity and long-lived – dismantling waste, that were determined using the fee rate set by ONDRAF and approved by its Board of Directors in May 2022. As a result of the agreement, financial responsibility for all Category A and B waste management operations conditioned in accordance with the contractual transfer criteria will henceforth lie with the State, in return for payment of the lump sum discharge amount described in section 17.2.2 above. The Group will transfer this liability when the laws transposing this agreement come into force, for a total of €1 billion2022 for category B waste, and when the extended units are restarted at the end of 2025, for a total of €3.5 billion2022 for category A waste.
The Group only remains responsible for the final shutdown and dismantling, including the conditioning of Category A and B waste from these operations in accordance with the contractual transfer criteria. At December 31, 2023, provisions for dismantling nuclear facilities are calculated based on the following inputs:
• the start of the technical shutdown procedures depends on the unit concerned and on the timing of operations for the whole nuclear reactor. The shutdown procedures are immediately followed by dismantling operations; • the scenario adopted is based on a dismantling program and on timetables that must be approved by the nuclear safety authorities. The safety conditions for the shutdown phases have been defined with the Belgian Federal Agency for Nuclear Control (AFCN) for the Doel 3 and Tihange 2 units that have already been shut down. The safety conditions for the dismantling phase have not yet been determined. The costs may change depending on the outcome of these discussions and the detailed schedule for the implementation of these phases which is currently being defined;
• costs payable over the long term are calculated by reference to the estimated costs for each nuclear facility, based on a study conducted by independent experts under the assumption that the facilities will be dismantled on a mass basis. The costs effectively incurred in the future may differ from the estimates in terms of their nature and timing of payment;
• fees for handling category A – low or medium activity and short-lived – and B – low or medium activity and longlived – dismantling waste are determined using the fee rate set by ONDRAF and approved by its Board of Directors in May 2022;
• for the various phases, margins for contingencies, reviewed by ONDRAF and the Commission for Nuclear Provisions, are included;
• an inflation rate of 2.0% is applied until the dismantling obligations expire in order to determine the value of the future obligation;
• the discount rate used by the CNP is 2.5% (including inflation of 2.0%) The 10-year extension of the Doel 4 and Tihange 3 units provided for in the agreement "deoptimizes" the systematic dismantling of the various units. The State is expected to cover the related additional provisions that are currently estimated at between €500 and €600 million. Pending an agreement on the exact amount under the oversight of the CNP, this additional liability paid in the form of a lump sum by the Belgian State at the time of closing has not been included in the financial statements. If the additional costs are not fully covered by the State, the Group may have to bear a portion of this additional liability.
Lastly, the Group sets aside provisions to cover the costs relating to the final shutdown phase of its drawing rights in Tricastin and Chooz B, as well as for the dismantling period leading to the decommissioning and clean-up of the Chooz B site, in accordance with the respective agreements with EDF. These are based on provisions for Belgian assets that most closely resemble these power plants, and are updated in line with revisions by the CNP. 870 of 1021
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Sensitivity
In light of the agreement, the Group will only be responsible for shutdown and dismantling, including conditioning of the nuclear waste arising from these operations, in accordance with the contractual transfer criteria. The Group's remaining liability is estimated at €6.7 billion2022 in the draft law implementing the agreement. • a 10% change in shutdown costs of the units would lead to a change in the provisions of around €200 million; • a 10% change in unit dismantling costs would lead to a change of around €400 million in nuclear provisions; • a 25 basis point change in the discount rate would lead to an adjustment of approximately €170 million in the provisions. A fall in the discount rate would lead to an increase in outstanding provisions, while a rise in the discount rate would reduce the provisions' amount.
17.2.4 Financial assets set aside to cover the future costs of dismantling nuclear facilities and managing radioactive fissile material
As indicated above, the Belgian law of July 12, 2022, partially repealing and amending the law of April 11, 2003, granted the Group's wholly-owned subsidiary Synatom responsibility for managing and investing funds received from operators of nuclear power plants in Belgium and intended to cover the costs of dismantling nuclear power plants and managing spent fuel. Pursuant to the law of April 11, 2003, Synatom could lend up to 75% of these funds to nuclear power plant operators provided that certain credit quality criteria are met.
The amount of outstanding loans between Synatom and nuclear operators, representing the countervalue of provisions for spent fuel management, will be repaid to Synatom by December 31, 2025, and the amount of outstanding loans between Synatom and Electrabel, representing the countervalue of provisions for dismantling, will be repaid by September 30, 2031.
The percentage of the provisions not subject to loans to nuclear operators is invested by Synatom either in external financial assets or in loans to legal entities meeting the “credit quality” criteria imposed by law.
Synatom invested just over €3 billion in such assets in 2023.
Synatom's objective for its investment in these assets has been adapted in light of the agreement. The objective is:
• for the portion to be liquidated at closing, to maintain the value of the underlying assets by investing in predominantly moneymarket instruments providing a return at least equivalent to the indexation of the fee amounts fixed at 3%; • for the investments aimed at covering the Group’s remaining liabilities, to ensure a sufficient return with an acceptable level of risk in order to cover dismantling costs and the costs of storing radioactive fissile material, under the constraints of diversification, risk minimization and availability as defined by the law of July 12, 2022.
The Synatom Board of Directors and its Investment Committee are responsible for defining Synatom's investment policy after consultation with the CNP, in accordance with the law of July 12, 2022. Based on a rigorous risk control policy, the Investment Committee oversees investment decisions, which are managed by a team headed by an investment director.
The value of financial assets dedicated to covering nuclear provisions amounted to €9,984 million at December 31, 2023, and their return was 5.01% for the year. The year 2023 was marked by the gradual re-exposure of the portfolio to recovering markets, following a year marked by the downward volatility of global equity and bond markets. However, this re-exposure had to be put on hold following the government's request, as part of the agreement, to be paid the fixed fees linked to the cost of nuclear waste treatment in cash rather than in dedicated assets. 871 of 1021
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17.2.4.1 Valuation of financial assets in 2023
Loans to entities outside the Group and other cash investments are shown in the table below:
In millions of euros Dec. 31, 2023 Dec. 31, 2022
Loans to third parties 3 5
Loan to Sibelga 3 5
Other loans and receivables at amortized cost 3 777 2 270 Debt instruments - restricted cash UCITS 3 777 2 270
Total loans and receivables at amortized cost 3 780 2 276 Equity and debt instruments at fair value 1,640 863
Equity instruments at fair value through other comprehensive income 25 24 Equity instruments at fair value through income 1,665 887 Debt instruments at fair value through other comprehensive income 1,873 2,418 Debt instruments at fair value through income 2,663 933 Debt instruments at fair value 4,536 3,350
Total equity and debt instruments at fair value 6,201 4,237 Derivative instruments 3 113
TOTAL (1) 9,984 6,626
(1) Not including €307 million in uranium inventories at December 31,2023 (€308 million at December 31, 2022).
Loans to legal entities outside the Group and the cash held by the Undertaking for Collective Investment in Transferable Securities (UCITS) are presented in the statement of financial position under “Loans and receivables at amortized cost”. Bonds and associated hedging instruments held by Synatom through the UCITS are presented under equity or debt instruments (see Note 14.1 “Financial assets”).
The breakdown in the change in the cumulative fair value of Synatom's assets is presented as follows:
Cumulative change in the fair value of
dedicated financial assets
In millions of euros Dec. 31, 2023 Dec. 31, 2022
Equity instruments at fair value through other comprehensive income 88 (157) Debt instruments at fair value through other comprehensive income (101) (282) Debt instruments at fair value through income 122 (52)
TOTAL 108 (491)
The net loss for the period generated by these assets amounted to €184 million in 2023 (loss of €217 million in 2022).
Effects on the result of the return on
dedicated financial assets
In millions of euros Dec. 31, 2023 Dec. 31, 2022
Disposal proceeds (312) 14
Return on assets 71 66
Change in fair value of derivatives not designated as hedges (108) (15) Change in fair value of dedicated assets through income 167 (282) TOTAL (184) (217)
17.3 Dismantling of non-nuclear plant and equipment and site rehabilitation
17.3.1 Dismantling obligations arising on non-nuclear plant and equipment Certain items of plant and equipment, including conventional power stations, transmission and distribution pipelines, storage facilities and LNG terminals, have to be dismantled at the end of their operational lives or at least safely shut down.
These obligations are the result of prevailing environmental regulations in the countries concerned, contractual agreements, or an implicit Group commitment. The most important issue for the Group concerns gas infrastructures in France.
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France's political and societal guidelines for the energy transition aim to achieve carbon neutrality by 2050, by reducing greenhouse gas emissions and promoting renewable or so-called “green” energies, particularly biomethane and hydrogen.
The various scenarios that make it possible to achieve carbon neutrality, in particular the National Low Carbon Strategy in France, the French Environment and Energy Management Agency (ADEME) scenarios, and the "Energy Futures" prospective study by the electricity transmission system operator, RTE, all lead to a significant decrease in the quantities of gas consumed, while maintaining a high number of gas connection points to manage peak electricity demand. The Group is closely analyzing this prospect, particularly for the purpose of defining its strategy and assessing the useful life of assets and evaluating provisions for their possible dismantling.
The future French Strategy for Energy and Climate (SFEC) will set out France's updated roadmap to achieve carbon neutrality by 2050 and ensure that France can adapt to the impacts of climate change. It will encompass the first five-year programming law on energy and the climate (LPEC), which must be adopted in 2024 and set out in the National LowCarbon Strategy (SNBC, 3rd issue), the National Climate Change and Adaptation Plan (PNACC, 3rd issue) and the Long Term Energy Schedule (PPE 2024-2033), which are all to be adopted in the first half of 2024. Consequently, the next fiveyear review of the PPE and the SNBC will be preceded for the first time by the adoption of a programming law on energy and the climate, which will set the French policy for energy and climate’s priorities for action.
In line with the objective of carbon neutrality by 2050, the long-term scenario adopted by the Group, which governs the implementation of its strategy, is one that combines reasonable electrification, i.e. just under 50% of final demand in 2050, with the development of a diversified range of green gases (biomethane, synthesized e-CH4, natural gas with the CarbonCapture and Storage process, pure hydrogen). The scenario used by the Group is close to the ADEME's S3 scenario.
Due to the importance of green gases in the French energy mix scheduled for 2050 and beyond, gas infrastructures will remain largely necessary and will be essential to provide flexibility to the energy system. The adaptation and conversion of these infrastructures to green gas mean that they can be used in the very distant future, which means that the present value of dismantling provisions is almost zero, except in the specific cases of LNG terminals and reduced operation and non-regulated storage sites mainly in France and Germany, for which provisions for dismantling amounted to €326 million at December 31, 2023 and €359 million at December 31, 2022.
Given its time horizon and developments in French and European public policies, the Group will continue to assess the long-term scenario that will enable it to achieve carbon neutrality by 2050 on a regular basis. These assessments will be accompanied by a review of the valuation of dismantling provisions.
17.3.2 Hazelwood Power Station & Mine (Australia)
The Group and its partner Mitsui announced in November 2016 their decision to close the coal-fired Hazelwood Power Station, and cease coal extraction operations from the adjoining mine from late March 2017. The Group holds a 72% interest in the former 1,600 MW power station and adjoining coal mine, which has been consolidated as a joint operation.
At December 31, 2023, the Group's share (72%) of the provision covering the obligation to dismantle and rehabilitate the mine amounted to €280 million, versus €220 million at December 31, 2022. The updating of certain provision inputs has resulted in an increase of around €90 million.
Dismantling and site rehabilitation work commenced in 2017 and focused on: managing site contamination; planning site wide environmental clean-up; the demolition and dismantling of all of the site's industrial facilities, including the former power station; and ongoing aquifer pumping and designated earthworks within the mine to ensure mine floor and batter stability with a view to long-term rehabilitation into a pit lake.
The ultimate regulatory obligations are likely to be revised during the life of the project and could therefore have an impact on provisions.
The amount of the provision recognized is based on the Group's best current estimate of the demolition and rehabilitation costs that Hazelwood is expected to incur. However, the amount of this provision may be adjusted in the future to take into account any changes in the key inputs.
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17.4 Other contingencies
This caption essentially includes provisions for commercial litigation, tax claims and disputes (except income tax, pursuant to IFRIC 23) as well as provisions for onerous contracts relating to storage and transport capacity reservation contracts 874 of 1021
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NOTE 18 POST-EMPLOYMENT BENEFITS AND OTHER
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NOTE 18 POST-EMPLOYMENT BENEFITS AND OTHER
LONG-TERM BENEFITS
Accounting standards
Depending on the laws and practices in force in the countries where the Group operates, Group companies have obligations in terms of pensions, early retirement payments, retirement bonuses and other benefit plans. Such obligations generally apply to all employees within the companies concerned.
The Group’s obligations in relation to pensions and other employee benefits are recognized and measured in compliance with IAS 19. Accordingly:
• the cost of defined contribution plans is expensed based on the amount of contributions payable in the period; • the Group’s obligations concerning pensions and other employee benefits payable under defined benefit plans are assessed on an actuarial basis using the projected unit credit method. These calculations are based on assumptions relating to mortality, staff turnover and estimated future salary increases, as well as the economic conditions specific to each country or entity of the Group. Discount rates are determined by reference to the yield, at the measurement date, on investment grade corporate bonds in the related geographical area (or on government bonds in countries where no representative market for such corporate bonds exists).
Pension commitments are measured on the basis of actuarial assumptions. The Group considers that the assumptions used to measure its obligations are relevant and documented. However, any change in these assumptions could have a significant impact on the resulting calculations.
Provisions are recorded when commitments under these plans exceed the fair value of plan assets. Where the value of plan assets (capped where appropriate) is greater than the related commitments, the surplus is recorded as an asset under “Other assets” (current or non-current).
As regards post-employment benefit obligations, actuarial gains and losses are recognized in other comprehensive income. Where appropriate, adjustments resulting from applying the asset ceiling to net assets relating to overfunded plans are treated in a similar way. However, actuarial gains and losses on other long-term benefits such as long-service awards, are recognized immediately in profit or loss.
Net interest on the net defined benefit liability (asset) is presented in net financial income/(loss).
18.1 Description of the main pension plans
18.1.1 Companies belonging to the Electricity and Gas Industries sector in France Since January 1, 2005, the CNIEG (Caisse Nationale des Industries Électriques et Gazières) has operated the pension, disability, death, occupational accident and occupational illness benefit plans for electricity and gas industry (hereinafter “EGI”) companies in France. The CNIEG is a social security legal entity under private law placed under the joint responsibility of the ministries in charge of social security and the budget.
Employees and retirees of EGI sector companies have been fully affiliated to the CNIEG since January 1, 2005. The main affiliated Group entities are ENGIE SA, GRDF, GRTgaz, Elengy, Storengy, ENGIE Thermique France, CPCU, CNR and SHEM.
Following the funding reform of the special EGI pension plan introduced by Law No. 2004-803 of August 9, 2004 and its implementing decrees, specific benefits (pension benefits on top of the standard benefits payable under ordinary law) already vested at December 31, 2004 (“past specific benefits”) were allocated between the various EGI entities. Past 875 of 1021
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specific benefits (benefits vested at December 31, 2004) relating to regulated transmission and distribution businesses (“regulated past specific benefits”) are funded by the levy on gas and electricity transmission and distribution services (Contribution Tarifaire d’Acheminement) and therefore no longer represent an obligation for the ENGIE Group. Unregulated past specific benefits (benefits vested at December 31, 2004) are funded by EGI sector companies to the extent defined by Decree No. 2005-322 of April 5, 2005.
The specific benefits vested under the plan since January 1, 2005 are wholly financed by EGI sector companies in proportion to their respective weight in terms of payroll costs within the EGI sector.
As this plan is a defined benefit plan, the Group has set aside a pension provision in respect of specific benefits payable to employees of unregulated businesses and specific benefits vested by employees of regulated businesses since January 1, 2005. This provision also covers the Group’s early retirement obligations. The provision amount may be subject to fluctuations based on the weight of the Group’s companies within the EGI sector.
The special EGI pension plan has been closed to new entrants since September 1st, 2023.
Pension benefit obligations and other “mutualized” obligations are assessed by the CNIEG.
At December 31, 2023, the projected benefit obligation in respect of the special pension plan for EGI sector companies amounted to €2.73 billion.
The duration of the pension benefit obligation of the EGI pension plan is 19 years.
18.1.2 Companies belonging to the electricity and gas sector in Belgium In Belgium, the rights of employees in electricity and gas sector companies, principally Electrabel, Laborelec and some ENGIE Energy Management Trading and ENGIE CC employee categories, are governed by collective bargaining agreements.
These agreements, applicable to “wage-rated” employees recruited prior to June 1, 2002 and managerial staff recruited prior to May 1, 1999, specify the benefits entitling employees to a supplementary pension equivalent to 75% of their most recent annual income, for a full career and in addition to the statutory pension. These top-up pension payments provided under defined benefit plans are partly reversionary. In practice, the benefits are paid in the form of a lump sum for the majority of plan participants. Most of the obligations resulting from these pension plans are financed through pension funds set up for the electricity and gas sector and by certain insurance companies. Pre-funded pension plans are financed by employer and employee contributions. Employer contributions are calculated annually based on actuarial assessments.
The actuarial “pension” liability relating to these plans amounted to €1.22 billion at December 31, 2023. The average duration of these plans is 9 years.
"Wage-rated" employees recruited after June 1, 2002 and managerial staff (i) recruited after May 1, 1999 or (ii) having opted for the transfer through defined contribution plans, are covered under defined contribution plans. Prior to January 1, 2017, the law specified a minimum average annual return (3.75% on wage contributions and 3.25% on employer contributions) when savings are liquidated.
The law on supplementary pensions, approved on December 18, 2016 and enforced on January 1, 2017 henceforth specifies a minimum rate of return, depending on the actual rate of return of Belgian government bonds, within a range of
1.75%-3.25% (the rates are now identical for employee and employer contributions). In 2023, the minimum rate of return stood at 1.75%.