OPC ENERGY LTD.

Report of the Board of Directors regarding the Company’s Matters

for the year ended December 31, 2024

The Board of Directors of OPC Energy Ltd. (hereinafter – “the Company”) is pleased to present herein the Report of the Board of Directors regarding the activities of the Company and its investee companies (hereinafter together – “the Group”), as at December 31, 2024 and for the year then ended (“the Period of the Report” or “the Year of the Report”).

Except for the data audited in the Company’s consolidated financial statements as at December 31, 2024 (hereinafter – “the Financial Statements”) that is included in this report below, the data appearing in the Report of the Board of Directors has not been audited (or reviewed) by the Company’s auditing CPAs.

Main financial parameters (in millions of shekels)

			For the												For the
			Year Ended												Three Months Ended
			December 31												December 31
			2024				2023				%				2024				2023				%
Consolidated	EBITDA after proportionate consolidation			1,208				1,099				10	%			228				319				(29	)%
	Net income			197				169				17	%			123				29				324	%
	Adjusted net income (loss)			115				180				(64	)%			(47	)			43				(209	)%
	FFO			726				648				12	%			154				4				3,750	%
Israel	EBITDA			639				562				14	%			98				135				(27	)%
	FFO			428				440				(3	)%			45				10				350	%
U.S.	EBITDA after proportionate consolidation			589				564				4	%			137				191				(28	)%
	FFO			339				264				28	%			111				(8	)			1,488	%
	EBITDA after proportionate consolidation – energy transition			588				585				1	%			141				163				(13	)%
	EBITDA after proportionate consolidation – renewable energies			112				31				261	%			28				14				100	%

Israel	Ramat Beka project – the Company is continuing to advance a consolidated project for generation of electricity using photovoltaic technology with integrated storage with a cumulative capacity of about 505 megawatts and about 2,760 megawatts per hour of storage. See also Section 6A(2) below. In September 2024, the Group made an initial payment to Israel Lands Authority (ILA) in respect of the Ramat Beka 2 tender, in the amount of about NIS 178 million (the Company’s share – about NIS 142 million), constituting 20% of the aggregate consideration for the areas of the second tender. As at the approval date of the report, to the best of the Company’s knowledge government was received for advancement of the plan to State’s National Infrastructures Board – for details see Section 7.3.13.1 of Part A of the Periodic Report.
	Additional renewable energy projects – as part of its strategic entry into the renewable energies area in Israel, the Company is developing additional projects using photovoltaic technology with integrated storage, with a cumulative capacity of about 215 megawatts and about 1,100 megawatt hours of storage. To the best of the Company’s knowledge, government was received for advancement of the plan to State’s National Infrastructures Board – for details see Section 6A(2) below.
	Memorandum of principles with Intel for construction of a power plant with a capacity of 450–650 megawatts – in March 2024, a non‑binding memorandum of principles for supply of electricity to Intel’s facilities in Kiryat Gat was signed, including expansion of the currently‑existing facilities, for a period of 20 years from the date of commencement of operation. See also – Section 6A(1) below.
	Sale of electricity to consumers of Partner Communications Ltd. (“Partner”) that are household consumers and small businesses and a decision regarding smart meters – in February 2024, an agreement was signed with Partner that will permit diversification of the mix of the Company’s customers. In April 2024, a decision of the Electricity Authority was received that will permit the Company to also sell electricity to household consumers without a smart meter and assignment thereof to a private conventional supplier commencing from November 1, 2024.
	Refinancing in Israel – in August 2024, OPC Holdings Israel signed two bank financing agreements, with an aggregate scope of NIS 1.65 billion, which were used mainly for purposes of early repayment of the project financing of the Zomet and Gat power plants. In February 2025, OPC Israel signed an additional bank financing agreement in the aggregate amount of NIS 300 million under similar conditions. See also Note 14B(1) to the Financial Statements.
	Hadera 2 project – after the government’s rejection of the plan for construction of a power plant for generation of electricity using natural gas in April 2024, in June 2024 Hadera 2 submitted a petition to the High Court of Justice regarding cancellation of the said Government Decision and approval of the plan. In December 2024, a conditional order was issued by High Court of Justice instructing the government to provide reasons why not to return of the plan for a rehearing by the National Infrastructures Board or, alternatively, to provide reasons why not to approve the plan. A hearing of the petition was scheduled for April 2025. See also – Section 6A.
	Public Announcement regarding a proposal for changes in the tariff structure (the generation component) – for details – see Section 3.2E below and Section 7.2.3 to Part A of the Periodic Report.

1.	Executive Summary (Cont.)

Main developments in 2024 and thereafter (Cont.)

U.S.	Transactions for increase in the holdings in the Shore and Maryland power plants in the area of Energy Transition in the U.S. – in October 2024, acquisition of 25% of the Maryland power plant was completed and in December 2024 acquisition of an additional 25% of Maryland and 31% of Shore was completed. On the completion date of the transactions, consideration was paid in the aggregate amount of about $188 million – see also Section 24C to the financial statements. Furthermore, in February 2025 the CPV Group signed an agreement, subject to preconditions that have not yet been actualized, for acquisition of an additional 20% of the Shore power plant. As part of the aforesaid transactions, the total investment commitments were increased and provision of shareholders’ loans to the CPV Group, in the amount of about $220 million, such that subject to investment of the full amount of the commitments, the Company’s holdings (indirectly) will be about 70.7%.
	Entry of an investor into the area of renewable energy activities in the U.S. – in August 2024, the CPV Group signed binding investment agreements with Harrison Street, in the aggregate amount of $300 million in CPV Renewable, in exchange for 33.3% of the ordinary rights in CPV’s renewable‑energy activities, based on a value “before the money” of $600 million. In November 2024, the transaction was completed. See also – Section 23E to the financial statements.
	Capacity auctions in the PJM market for the period June 2025 through May 2026 – in July 2024, the results of auctions for capacity prices in PJM were published, with a significant increase in the prices to about $270 per megawatt per day. For details regarding the estimated addition to the Group’s revenues from capacity for the period of the auction and with respect to expected changes in the methodology of the auctions on the capacity prices in PJM for 2026–2027, and particularly determination of minimum and maximum (collar) prices of 175–325 megawatts per day – see Section 3.3M below.
	Basin Ranch project – the CPV Group is continuing to advance the Basin Ranch project, a natural gas project with future carbon capture potential located in the western part of Texas, with a capacity of about 1.35 gigawatts, the construction cost of which is estimated at about $1.8 – $2 billion and commencement of its construction is expected by the end of 2025. The project was chosen by the TEF to advance to the stage of due diligence examinations for receipt of a subsidized loan in the amount of about $1 billion. In addition, as at the approval date of the report, the CPV Group is working on a private fundraising process that is required for construction of the project. For additional details – see Section 6B(2) below.
	Refinancing in Towantic, Fairview, Shore and reductions of interest in Maryland and Fairview – during 2024 and in February 2025, undertakings for refinancing in Towantic, Fairview and Shore were completed. In addition, in September 2024 and February 2025, the transactions for interest reductions (repricing) in Maryland and Fairview were completed. See also Section 9 below.
	Start of construction of the Rogue’s Wind project (wind‑energy power plant with a capacity of 114 megawatts located in Pennsylvania) – in August 2024 a Work Commencement Order was issued concurrent with completion of the receipt of financing for construction of the project. See also Section 6A(2) below.

1.	Executive Summary (Cont.)

 Main developments in 2024 and thereafter (Cont.)

 

U.S. (Cont.)	Tax partner agreement in the Backbone project (solar technology‑based power plant with a capacity of 179 megawatts, in the state of Maryland) – in October 2024, a binding agreement was signed with a tax partner for investment of an aggregate amount of about $116 million.  See also Section 6A(2) below.
	Commercial operation of the Stagecoach project with a capacity of 102 megawatts – in May 2024, the project reached commercial operation and an agreement was signed with a tax partner (PTC) in the aggregate amount of about $52 million.
Group headquarters	Raising of capital – in July 2024, the Company completed raising of capital, in the amount of about NIS 800 million.
	Credit rating – in July 2024, S&P Maalot reconfirmed the credit rating of the Company and its debentures at the level of ilA– and updated the rating outlook from negative to stable.
	Issuance of a new series of debentures (Series D) – in January 2024, the debentures (Series D) were issued in the amount of NIS 200 million with a term of about 6.4 years and bearing annual interest of 6.2%.

United States (1) (2)

Portfolio of about 12.9 GW and about 3.9 GWh of storage (for details – see Section 6 below) (Cont.)

Israel (1)

That stated with respect to the development stages, capacities and/or expectations regarding construction of the development projects in Israel and in the U.S. constitutes “forward‑looking” information as it is defined in the Securities Law, which is based on the Company’s estimates at the date of the report and regarding which there is no certainty they will be realized. Ultimately, there could be changes in the characteristics of the projects and/or delays due to regulatory, operating, commercial factors and/or realization of one or more of the risk factors to which the Company is exposed, as stated in Part A of the Periodic Report. Advancement of the development projects (or any one of them) is subject to the discretion of the Company’s competent organs and existence (fulfillment) of additional conditions, as stated in Part A of the Periodic Report.

The Company is a public company the securities of which are listed for trade on the Tel Aviv Stock Exchange Ltd. (hereinafter – “the Stock Exchange”).

As at the date of the report, the Group is engaged in the generation and supply of electricity in three activity areas (that constitute reportable segments in the financial statements), as briefly described below:

In addition, through the CPV Group, the Group is involved in additional business activities in the U.S. which, as the date of the report, are not material to the results of the Group’s overall activities (and that do not constitute reportable segments in the financial statements):

For additional details regarding the CPV Group’s activities in its different areas of activities, as well in other activity areas⁵ – see Note 25 to the financial statements.

It is noted that as at the date of the report, the Group’s activities in the area of provision of asset‑management and energy services to the power plants focus mainly on power plants partially owned by the CPV Group, and that since 2024 are no longer considered an independent area of activities and which are part of the activities of the headquarters of the CPV Group.

Regarding the interest in Israel, in the January 2024 interest decision Bank of Israel decided to reduce the interest rate to 4.5% while in the other interest‑rate decisions in 2024 as well as in the beginning of 2025 there was no change. According to the latest forecast published by Bank of Israel, the interest rate is expected to decline a bit and stand at 4.00%–4.25% on average in the fourth quarter of 2025.

Regarding the interest in the U.S., in 2024 a trend of lowering the interest rate began, which was reduced by 1% to the level of 4.25%–4.50%. Since the beginning of 2025, there have been no additional interest-‑rate reductions. Based on the latest forecast published by the U.S. Federal Reserve Bank, the interest rate is expected to decline a bit and stand at 4% on average in 2025.

These parameters with respect to the inflation and interest rates, along with the policies of the central banks, have a significant impact on the worldwide macro‑economic environment, including in Israel and in the U.S., along with the business environment in which the Group operates.

The impacts of that stated above on the business environment could find expression in, among other things, the scope of the financing expenses (higher when the interest rate rises and lower when the interest rate falls), growth rates and extent of the business activities in the economy (in Israel and the U.S.), the financial markets and the possibilities and related attractiveness of raising capital, and the energy, electricity and natural‑gas prices, tariffs in the Israeli electricity market, project construction costs and the like.

In addition to that stated above, the changes and geopolitical tensions in Israel and worldwide impact the macro‑economic environment (including the policy considerations of Bank of Israel with reference to the circumstances of the war), as detailed in Section B below. Events of this type could also impact aspects of the inflation and interest rates.

Set forth below is data with reference to the currency exchange rate, Consumer Price Index (CPI) in Israel and in the U.S., the interest rates of Bank of Israel and the interest rates of the Fed in U.S.:

Dollar/shekel exchange rate*		2024			2023			Change
On December 31		3.647			3.627			0.6	%
On September 30		3.710			3.824			(3.0	)%
Average January– December		3.699			3.689			0.3	%
Average October– December		3.703			3.823			(3.1	)%

					Bank of
					Israel		Federal
	Israeli		U.S.		Interest		interest
	CPI		CPI		Rate		rate
On March 6, 2025	115.4		317.6		4.5%		4.25%–4.50%
On December 31, 2024	115.1		315.5		4.5%		4.25%–4.50%
On September 30, 2024	115.2		314.8		4.5%		4.75%–5.00%
On December 31, 2023	111.3		307.1		4.75%		5.25%–5.50%
On September 30, 2023	111.2		307.0		4.75%		5.25%–5.50%
On December 31, 2022	107.7		297.7		3.25%		4.25%–4.50%
Change in 2024	3.4%		2.7%		(0.25)%		(1)%
Change in 2023	3.3%		3.1%		1.5%		1%
Change in the fourth quarter of 2024	(0.1)%		0.2%		0%		(0.50)%
Change in the fourth quarter of 2023	0.1%		0.1%		0%		0.25%

For details regarding credit linked to the CPI or to prime – see Section 9B below, and that stated in Note 14B to the Financial Statements. For additional details regarding impacts of the changes in the macro‑economic environment on the results of the Group’s activities – see Section 11 below.

In addition, the War has had external impacts including, among others, interruptions in the marine routes due to attacks on commercial and supply ships and a significant cutback of the activities of foreign airline companies in Israel. These events have an occasional impact and could have an adverse impact on the arrival of equipment and foreign teams to Israel (including equipment and teams required for purposes of maintenance and construction of the Group’s activity sites in Israel) and the time schedules for their arrival.

The said events involve significant uncertainty and could impact the macro‑economic environment, including an unfavorable impact on the strength of Israel’s economy.

In a case of a worsening of the security situation, this could negatively impact the Company’s activities and the activities of the Company’s customers and suppliers in Israel, and could also negatively impact the results of the Company’s activities and the availability and cost of the capital and financing sources that are required by the Group. As of the approval date of the report, there is a ceasefire in most combat areas, however the instability and risk of a resurgence of the War still constitutes a significant risk. For details regarding the significance of the War on the Group’s business activities and results – see Section 6.1.1 to Part A of the Periodic Report.

As at the approval date of the report, the CPV Group is monitoring the changes being advanced by the new government, including by force of the said executive orders, and at this early stage there is no certainty regarding the manner of their application and/or impact on the CPV Group (which could be different than the above‑mentioned estimates). For additional details – see Sections 8.1.3.1 and 8.1.4O of Part A of the Periodic Report.

On February 1, 2024, the annual update to the tariff for 2024 for electricity consumers of Israel Electric Company entered into effect. Pursuant to the decision, the generation component was updated to NIS 0.3007 per kilowatt hour, a decrease of 1.1% compared with the generation component at the end of 2023 – this being mainly due to the surplus receipts expected from sale of the Eshkol power plant, which led to a reduction in the generation sector. In addition, as part of the said tariff update decision, it was noted that pursuant to the decision designation of the receipts from sale of Eshkol was determined – the surplus receipts from the sale will first be used to cover expenses incurred during the war, including costs of diesel oil, and only thereafter will the surplus receipts be used to cover non‑recurring past expenses.

3.2

Activities in Israel (Cont.)

Set forth below is data regarding the annual weighted‑average generation component (the prices are denominated in agurot per kilowatt hours):

Period		2024				2023				Change
January–December average			30.10				30.53				(1.4	)%
October–December average			30.07				30.39				(1.1	)%

In January 2025, a decision of the Electricity Authority entered into effect regarding update of the tariff for 2025 for consumers of electricity from the Electric Company. Pursuant to the decision, the weighted‑average generation component was updated to NIS 0.2939 per kilowatt hour – a decline of about 2.2% in the weighted‑average generation component, this being mainly as a result of a decrease in the Electric Company’s generation cost due to a reduction in the use of coal and a forecasted decline in the Electric Company’s natural‑gas price. In addition, there was a non‑recurring recognition of surplus receipts from sale of the Eshkol power plant, which led to a reduction in the generation component.

It is noted that the results of the Group’s activities in Israel are materially impacted by changes in the electricity generation component tariff, in such a manner that an increase in the electricity generation component has a positive impact on the Group’s results, and vice‑versa.

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7

That stated constitutes an indicative estimate of the impact of changes to the generation component on the Company, which is subject to changes in, among other things, as a result of the manner of determining the periodic generation component and/or the manner of its application to the demand‑hours brackets, operating factors and/or occurrence of one or more of the risk factors to which the Company is exposed, as stated in Section 19.2 Section A of the Periodic Report.

3.	Main Developments in the Business Environment (Cont.)

          It is noted that in recent years the Electricity Authority has been advancing various processes for increasing competition in the supply area. For further details see Sections 7.9.2 of Part A of the Periodic Report.

For additional details regarding developments of the Group’s activities in Israel – see Section 6 below.

3.	Main Developments in the Business Environment (Cont.)

The results of the activities of the CPV Group are impacted to a significant extent by the electricity prices in effect in the areas in which the Group’s power plants operate. The main factors impacting the electricity prices are demand for electricity, available generation capacity (supply) and the natural gas price in the area in which the power plant operates.

With respect to the area of “energy transition” activity, in general, the natural gas price is significant in determination of the price of the electricity in most of the regions in which the power plants of the CPV Group operate that are powered by natural gas. For the most part, in the existing production mix, over time, to the extent the natural‑gas prices are higher, the marginal energy prices will also be higher, and will have a positive impact on the energy margins of the CPV Group due to the high efficiency of the power plants it owns compared with other power plants operating in the relevant activity markets (the impact could be different between the projects taking into account their characteristics and the area (region) in which they are located).

The following table summarizes the average electricity prices in each of the regions in which the power plants in the area of energy transition activities of the CPV Group are active (the prices are denominated in dollars per megawatt hour)*:

		For the												For the
		Year Ended												Three Months Ended
Region		December 31												December 31
(Power Plant)		2024				2023				Change				2024				2023				Change
PJM West (Shore, Maryland)			33.83				33.06				2	%			34.71				36.31				(4	)%
PJM AEP Dayton (Fairview)			30.73				30.81				0	%			32.48				31.30				4	%
New York Zone G (Valley)			37.64				33.27				13	%			46.26				31.52				47	%
Mass Hub (Towantic)			41.47				36.82				13	%			54.49				34.66				57	%
PJM ComEd (Three Rivers)			25.55				26.68				(4	)%			24.58				26.31				(7	)%

It is noted that the actual electricity prices of the power plants of the CPV Group could be higher or lower than the regional price shown in the above table due to the existence of a Power Basis (the difference between the power plant’s specific electricity price and the regional price). The Power Basis is a function of transport pressures, local cost of electricity generation, local demand for electricity, losses in the transmission lines and additional factors.

The following table provides the average Power Basis data for each power plant (the data is presented in dollars per megawatt hour):

Power plant		For the year ended December 31
		2024				2023
Shore			(6.25	)			(8.32	)
Maryland			3.59				2.47
Fairview			(2.18	)			(1.90	)
Valley			(1.00	)			(1.41	)
Towantic			(2.77	)			(3.02	)
Three Rivers			(1.01	)			(1.18	)

Electricity prices (Cont.)

In the year of the report and in the fourth quarter of 2024, in general, there were no significant changes in the electricity prices compared with the corresponding periods last year except with respect to the Towantic and Valley power plants. In the fourth quarter of 2024, there was a significant increase in the electricity prices in the Towantic and Valley power plants compared with the corresponding quarter last year, due to, among other things, an increase in the natural‑gas prices and an increase in the RGGI price (carbon emission tax), as detailed below. It is noted that the Fairview and Three Rivers power plants are located in areas that as at the approval date of the report are not subject to RGGI.

At the macro level, electricity prices continue to be impacted by supply and demand trends in the activity areas of the CPV Group’s power plants: an increase in the demand for electricity as a result of electrification in the transportation, real estate and industry sectors, and due to the increase in the demand for electricity in the data‑center sector, as a result of the transition to “cloud” and growth in the Artificial Intelligence (AI) activities. At the same time, the available generation capacity is continuing to decline as a result of closing of old, inefficient and polluting conventional power plants (mainly coal‑powered power plants), on the one hand, and the limited supply of new power plants, on the other hand. For details regarding the EPA regulations with respect to the matter of carbon emissions – see Section 8.1.4(C) of Part A of the Periodic Report.

Subsequent to the period of the report, in general, a trend similar to the fourth quarter of 2024 continued, where the electricity prices remained high.

Set forth below are the average natural gas prices in each of the main markets in which the power plants of the CPV Group operate (the prices are denominated in dollars per MMBtu)*:

		For the Year Ended												For the Three Months Ended
Region		December 31												December 31
(Power Plant)		2024				2023				Change				2024				2023				Change
Texas Eastern M‑3 (Shore, Valley – 70%)			2.07				1.90				9	%			2.37				1.78				33	%
Transco Zone 5 North (Maryland)			2.51				2.74				(8	)%			2.38				2.77				(14	)%
Texas Eastern M‑2 (Fairview)			1.71				1.63				5	%			1.99				1.61				24	%
Dominion South Pt (Valley – 30%)			1.67				1.63				2	%			1.97				1.64				20	%
Algonquin City Gate (Towantic)			3.03				2.94				3	%			4.42				2.69				64	%
Chicago City Gate (Three Rivers)			2.12				2.30				(8	)%			2.21				2.28				(3	)%

*Source: The Day‑Ahead prices at gas Midpoints as reported in Platt’s Gas Daily. It is clarified that the actual gas prices of the power plants of the CPV Group could be significantly different.

In general, in the year of the report there were no significant changes in the average natural gas prices compared with the corresponding period last year. In the fourth quarter of 2024, in general, the natural‑gas prices in the U.S. were high compared with the corresponding period last year, due to, among other things, the relatively cold weather that led to high output from the natural‑gas inventories in the U.S and price pressure in the Algonquin region (a region that relies on, among other things, import of liquid gas in order to provide a response to the demand) stemming from uncertainty regarding the levels of the natural gas inventories in Europe. This uncertainty derived from, among other things, the fact that Ukraine and Russia did not renew the natural‑gas transmission agreements through Ukraine, which caused an imbalance between the demand and the supply capability of natural gas throughout Europe. With respect to the Maryland power plant, which is located in the Transco Zone 5 region, the decline in the natural‑gas prices stems from operation of a new gas transport pipeline (Mountain Valley Pipeline) that connects the region with a number of additional regions, including the Texas Eastern M2, which have lower natural gas prices. In addition, operation of the new pipeline in regions where there are lower natural gas prices, where the Valley, Shore and Fairview power plants are also located, led to a decrease in supply of natural gas in these regions and an increase in the gas prices. The Towantic power plant experienced a higher pricing of natural gas against the background of the much colder weather in December 2024 compared with last year.

Subsequent to the period of the report, in general, the trend of increasing natural gas prices continued, as a result of continued relatively cold weather and high levels of withdrawals from the natural gas inventories in the U.S.

Spark Spread is the difference between the price of the electricity in the relevant area (zone) and the price of the natural gas used for generation of the electricity in the relevant area (zone) (it is clarified that RGGI is not included in calculation of the Spark Spread but rather in the energy margin as detailed in Section 4F below).

Spark Spread ($/MWh) = price of the electricity ($/MWh) – [the gas price ($/MMBtu) x thermal conversion ratio (heat rate) (MMBtu/MWh)]

Set forth below are the average Spark Spread margins for each of the main markets in which the power plants of the CPV Group are operating (the prices are denominated in dollars per megawatt/hour)*:

		For the												For the
		Year Ended												Three Months Ended
		December 31												December 31
Power Plant9		2024				2023				Change				2024				2023				Change
Shore			19.55				19.95				(2	)%			18.36				24.03				(24	)%
Maryland			16.51				14.15				17	%			18.29				17.20				6	%
Valley			24.19				20.72				17	%			30.74				19.53				57	%
Towantic			21.78				17.71				23	%			25.76				17.18				50	%
Fairview			19.62				20.22				(3	)%			19.55				20.84				(6	)%
Three Rivers			11.77				11.73				0	%			10.22				11.49				(11	)%

In the period of the report and in the fourth quarter of 2024, compared with the corresponding periods last year there was an increase in the electricity margins (Spark Spread) stemming mainly from an increase in the electricity prices in the Valley and Towantic power plants and a decline in the natural‑gas price in the Maryland power plant, as detailed above. Regarding the Shore power plant, most of the decline in the electricity margins in the fourth quarter of 2024 compared with the corresponding period last year stems from an increase of the natural gas price in the Texas Eastern M‑3 region.

It is noted that the hedging plans of the electricity margins in the power plants of the CPV Group that are powered by natural gas is intended to reduce the fluctuations of the CPV Group’s electricity margin resulting from changes in the natural gas and electricity prices in the energy market (for details regarding hedging agreements of the electricity margin of the CPV Group – see Section 4F below).

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3.	Main Developments in the Business Environment (Cont.)

Electricity margin in the operating markets of the CPV Group (Spark Spread) (Cont.)

For details regarding a forecast of the EOX company of electricity and natural gas prices for 2025 through 2027 – see Appendix A below.

Regional Greenhouse Gas Initiative (RGGI) is a joint effort of the states of Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Pennsylvania, Rhode Island and Vermont to determine quotas and to reduce the emissions of carbon dioxide from the energy sector. The RGGI regulation requires the power plants running on fossil fuels to hold, through public tenders or commerce in a secondary market, gas‑emission quotas for purposes of offsetting emissions of carbon dioxide for every facility. Pursuant to the RGGI regulation, an independent market supervisor provides supervision of the tenders for gas‑emission quotas, as well as activities in the secondary market, in order to assure integrity of and confidence in the market. The RGGI regulation applies to 4 of the 6 power plants of the CPV Group in the Energy Transition segment: Maryland, Shore, Valley and Towantic. With respect to the legal proceeding underway in Pennsylvania (the location of the Fairview power plant) in connection with application of RGGI and the possible significance of the matter – see Section 8.1.4B of Part A of the Periodic Report.

Set forth below is a summary of the prices of the gas‑emission quotas (carbon emission tax) from the RGGI tenders. In general, the tenders take place four times a year, in March, June, September and December.

		Average for												Average for
		the year ended												the three months ended
		December 31												December 31
		2024				2023				Change				2024				2023				Change
Price of carbon emission tax in the RGGI
tenders ($ per short ton / 2,000 pounds)*			19.42				13.02				49	%			25.75				13.85				86	%
Cost of the carbon emission tax (in terms
of gas cost) ($ per MMBtu)**			1.16				0.77				49	%			1.53				0.82				86	%

In the period of the report and the fourth quarter of 2024 compared with the corresponding periods last year, there was a significant increase in prices of the carbon emissions tax, which in the estimation of the CPV Group was mostly impacted by speculative trading and release of all the gas emission quotas from the cost containment reserve in the first quarter of 2024. In the tender in December 2024 (which reflects prices in the first quarter of 2025), the price declined to $20.05 per short ton.

3.	Main Developments in the Business Environment (Cont.)

Capacity is a component that is paid by regulatory bodies that manage demand and loads (system operators) for electricity generators, with respect to their ability to generate energy at the required times for purposes of reliability of the system. This revenue component is an additional component, separate and apart from the component based on the energy prices (which is paid in respect of sale of the electricity). Definition of the capacity component, as stated, including entitlement to revenue for seeing to availability of the electricity, including provisions regarding bonus or penalty payments, are governed by the tariffs determined by the ISO of every market. Accordingly, NY‑ISO, PJM and ISO‑NE publish mandatory public auctions for determination of the capacity tariffs. It is noted that, in the nature of things, an increase in the capacity prices favorably impacts CPV’s results, and vice‑versa. The extent of the impact on the overall results changes as a function of the energy margins, which is the most significant component of the gross profit (margin for generation of the electricity and the sale thereof) – this being taking into account that the weight of the capacity component is usually lower than the weight of the energy margin component.

In the PJM market, the capacity payments vary between the market’s sub‑regions, as a function of local supply and demand and transmission capabilities.

Set forth below are the capacity tariffs in the sub‑regions that are relevant to the CPV Group’s power plants and in the general market (the prices are denominated in dollars per megawatt per day). It can be seen in the following table that in prior years, generally, the capacity prices have declined from period to period up to a significant reversal in the trend in the last auction for the period from June 2025 through May 2026.

Sub-Region	CPV Plants10	2025/2026	2024/2025	2023/2024	2022/2023
PJM RTO		269.92	28.92	34.13	50.00
PJM COMED	Three Rivers	269.92	28.92	34.13	–
PJM MAAC	Fairview, Maryland, Maple Hill	269.92	49.49	49.49	95.79
PJM EMAAC	Shore	269.92	54.95	49.49	97.86

Source: PJM

¹⁰          The Three Rivers power plant, which commenced commercial operation in July 2023, is entitled to capacity payments, from this date.

In July 2024, PJM published the results of auctionss on capacity prices for the period from June 2025 through May 2026. This, being after in October 2023, PJM submitted to FERC changes in the format for the capacity market that entered into effect commencing from the present auction (at this stage for a one‑year period starting from the middle of 2025). The changes include, among others, adjustments to the scope of capacity permitted to be sold, examination requirements for generators and adjustment of planning parameters with an increase in the weight of the winter reliability risk parameter.

The significant increase in the capacity tariff in the auction, as shown in the above table, relates to, among other things, the forecast of an increase in demand, an increase in the reserves required and a decline in the total supply as a result of demands and a change in the manner of calculating capacities and load capability of the generation sources by PJM. The change in the manner of calculating availability capacities of the power plants caused a decrease in the availability capacity that is provided for sale in most of the power plants operating in the PJM market. The impact of the said change on the power plants of the CPV Group operating in the energy transition area is a decline in the availability capacity provided for sale from about 96% to about 79%. In the estimation of the CPV Group, as a result of the increase in the capacity tariff, the addition to its revenues from capacity from all its power plants, as at the date of the report, in the PJM market for the period from June 2025 through May 2026 compared with the period from June 2024 through May 2025 is estimated at about $89 million. In addition, upon completion of the transaction for acquisition of an additional 20% of the Shore power plant, if ultimately completed, the capacity revenues will increase by the estimated additional amount of about $11 million (for details – see Note 24 to the financial statements)¹¹.

In September 2024, complaints were filed with the FERC in order to make certain changes in the upcoming capacity auctions in the PJM market. In response, PJM proposed a postponement of the auction that was originally scheduled for December 2024 by about six months in order to permit the making of changes to the rules of the auctions.

In February 2025, the FERC approved proposals of PJM for changes in the framework of the capacity market, which are aimed at reducing the pricing fluctuations between the auctions. The amendments include: (A) continued use of gas turbines as a representative index for the demand curve; (B) inclusion of RMR (reliability must run) units – the planned sources for scrap remain for purposes of assurance of reliability in the auctions in the capacity market as an alternative source of supply: (C) determination of a uniform penalty rate for inferior performances for all the generation sources; (D) increase of the flexibility regarding submission of bids; and (E) cancellation of the automatic exemptions from the bid requirement for certain types of sources.

---

11

That stated in this Section regarding the estimate of the CPV Group constitutes “forward‑looking” information as it is defined in the Securities Law, regarding which there is no certainty it will be realized. Ultimately, the revenues of the CPV Group from capacity could be different (even significantly) as a result of, among other things, regulatory changes (including appeal processes or other processes in the PJM market or as part of other municipal authorities), operating factors, changes in the business environment and/or the occurrence of one or more of the risk factors to which the CPV Group is exposed. In addition, as at the approval date of the report the increase of the additional holdings in the Shore power plant had not yet been completed, the completion of which is subject to conditions that have not yet been fulfilled and there is no certainty regarding their fulfillment.

Results of capacity auction in the PJM market for the period from June 2025 through May 2026 (Cont.)

In addition, PJM proposed to determine maximum and minimum price ceilings (collar) of $325 per MW/day and $175 per MW/day, respectively, for the next two capacity auctions. As at the approval date of the report, PJM’s said proposal for price ceilings (collar) is subject to FERC approval and there is no certainty it will be approved or its final conditions if ultimately approved.

Subject to additional changes in timetables, if any, as at the date of the report, the next capacity auction of PJM for the 2026/2027 capacity year is planned for July 2025 and the auction for the 2027/2028 capacity year is planned for December 2025.

Similar to the PJM market, in the NYISO market capacity payments are made in the framework of a central mechanism for acquisition of capacity. In the NYISO market, there are a number of submarkets, wherein there could be various capacity demands as a function of local supply and demand and transmission capability. NYISO makes seasonal auctions in every spring for the upcoming summer (the months of May through October) and in the fall for the upcoming winter (the months of November through April). In addition, there are supplemental monthly auctions for the balance of the capacity not sold in the seasonal auctions. The power plants are permitted to assure the capacity tariffs in the seasonal auction, the monthly auction or through bilateral sales.

Set forth below are the capacity prices determined in the seasonal auctions in the NYISO market, the capacity prices rose compared with prior periods – this being mainly due to exit from the system of power plants and an anticipated increase in demand (the prices are denominated in dollars per megawatt per day):

Sub-Area	CPV Plants	Winter 2024/2025	Summer 2024	Winter 2023/2024
NYISO Rest of the Market	–	66.30	168.91	127.25
Lower Hudson Valley	Valley	66.30	168.91	128.90

Source: NYISO – the Company’s processing in order to convert from dollars for kilowatt per month to dollars for megawatt per day.

The decline in the capacity prices in the winter of 2024/2025 in the NYISO market stems from relatively stable demand for electricity over the past years, mainly against the background of a slower than expected recovery from the Coronavirus, along with an increase in renewable energy and an improvement of the energy costs.

It is noted that the Valley power plant is located in Area G (Lower Hudson Valley) and the actual capacity prices for the Valley power plants are impacted by the seasonal auctions, the monthly auctions and the SPOT prices, with variable capacity prices every month, as well as bilateral agreements with energy suppliers in the market.

3.	Main Developments in the Business Environment (Cont.)

The Towantic power plant, which operates in this market, participated for the first time in a capacity auction for 2018–2019 at a price of $313.97 MW/day and determination of the tariff for seven years in respect of 725 megawatts linked to the Handy-Whitman Price Index, which will apply up to May 2025.

Similar to the PJM market, in the ISO‑NE market capacity payments are made as part of a central mechanism for acquisition of capacity. In the ISO‑NE market, there are a number of submarkets, in which there should be capacity requirements that differ as a function of local supply and demand and transport capacity. ISO‑NE executes forward auctions for a period of one year, commencing from June 1, three years from the year of the auction. In addition, there are supplementary monthly and annual auctions for the balance of the capacity not sold in the forward auctions. The power plants are permitted to guarantee the capacity payments in the forward auctions, the supplementary auctions or through bilateral sales.

Set forth below are the capacity payments determined in the sub‑regions that are relevant to the Towantic power plant (the prices are denominated in dollars per megawatt per day):

Sub-Region	CPV Power Plants	2027/2028	2026/2027	2025/2026
ISO-NE Rest of the Market	Towantic	117.70	85.15	85.15

Source: NE‑ISO – the Company’s processing in order to convert from dollars for kilowatt per month to dollars for megawatt per day.

It is noted that the actual capacity prices for the Towantic power plant are impacted by forward auctions, supplementary annual auctions, monthly auctions with capacity prices that change every month and bilateral agreements with energy suppliers in the market.

4.	Analysis of the results of operations for the Year Ended December 31, 2024 (in millions of NIS)

4.	Analysis of the results of operations for the Year Ended December 31, 2024 (in millions of NIS) (Cont.)

A.

Statement of income

*

For an analysis of the change in the net income and a definition and analysis of the change in the adjusted net income – see Section 4G below.

4.	Analysis of the results of operations for the Year Ended December 31, 2024 (in millions of NIS) (Cont.)

A.

Statement of income (Cont.)

Revenues		For the							Board’s Explanations
		Year Ended
		December 31
		2024				2023
Revenues in Israel
Revenues from sale of energy to private customers			1,368				1,424
Revenues from sale of energy to the System Operator and to other suppliers			165				120		Most of the increase, in the amount of about NIS 32 million, stems from the commercial operation of Zomet at the end of the second quarter of 2023.
Revenues in respect of capacity payments			171				59		Most of the increase stems from the commercial operation of Zomet at the end of the second quarter of 2023.
Revenues from sale of energy at cogeneration tariff			83				82
Revenues from sale of steam			57				59
Other revenues			23				59		Most of the decline derives from sales of electricity recognized in the corresponding period last year, in the amount of about NIS 26 million, from the Zomet power plant prior to the commercial operation at the end of June 2023.
Total revenues from sale of energy and others in Israel (without infrastructure services)			1,867				1,803
Revenues from private customers in respect of infrastructure services			445				480
Total revenues in Israel			2,312				2,283
Revenues in the U.S.
Revenues from sale of electricity from renewable energy			195				136		The increase derives mainly from the first‑time consolidation of the Mountain Wind project starting from the second quarter of 2023 and the commercial operation of the Maple Hill and Stagecoach projects starting from the fourth quarter of 2023 and the second quarter of 2024, respectively. This increase was partly offset by discontinuance of consolidation of renewable energies segment in November 2024, deriving from loss of control in CPV Renewable and as a result of transition to the equity method of accounting. For additional details – see Note 23E to the Financial Statements.
Revenues from sale of electricity (retail) activities and others			272				133		The increase stems mainly from an increase in the scope of the activities.
Total revenues in the U.S.			467				269
Total revenues			2,779				2,552

4.	Analysis of the results of operations for the Year Ended December 31, 2024 (in millions of NIS) (Cont.)

A.

Statement of income (Cont.)

(2)

Changes in the cost of sales and provision of services (not including depreciation and amortization):

Cost of Sales and Provision of Services		For the Year Ended							Board’s Explanations
		December 31
		2024				2023
Cost of sales in Israel
Natural gas and diesel oil			645				663
Expenses in respect of acquisition of energy			320				303		Most of the increase stems mainly from the background of the maintenance work at the Rotem power plant in the first half of 2024 and the Gat power plant in the second half of 2024.
Cost of transmission of gas			55				41		The increase stems mainly from the first‑time consolidation of Gat, starting from the second quarter of 2023 and the commercial operation of Zomet starting from the end of the second quarter of 2023.
Salaries and related expenses			46				37
Operating expenses			120				87		The increase stems mainly from the first‑time consolidation of Gat commencing from the second quarter of 2023 and the commercial operation of Zomet starting from the end second quarter of 2023.
Other expenses			18				65		In 2023, includes mainly natural gas and other at the Zomet power plant prior to commercial operation at the end of June 2023.
Total cost of sales in Israel without infrastructure services			1,204				1,196
Expenses in respect of infrastructure services			445				480
Total cost of sales in Israel			1,649				1,676

4.	Analysis of the results of operations for the Year Ended December 31, 2024 (in millions of NIS) (Cont.)

A.

Statement of income (Cont.)

(2)

Changes in the cost of sales and provision of services (not including depreciation and amortization): (Cont.)

Cost of sales and services in the U.S.
Cost of sales in respect of sale of electricity from renewable energy			60				49		The increase stems mainly from the first‑time consolidation of the Mountain Wind project, commencing from the second quarter of 2023 and commercial operation of the Maple Hill and Stagecoach projects, starting from the fourth quarter of 2023 and the second quarter of 2024, respectively. This increase was partly offset by discontinuance of consolidation of renewable energies segment in November 2024 deriving from loss of control in CPV Renewable and as a result of transition to the equity method of accounting. For additional details – see Note 23E to the Financial Statements.
Cost of sales in respect of sale of electricity (Retail) and others			222				102		The increase stems mainly from an increase in the scope of the activities.
Total cost of sales and provision of services in the U.S.			282				151
Total cost of sales and provision of services			1,931				1,827

4.	Analysis of the results of operations for the Year Ended December 31, 2024 (in millions of NIS) (Cont.)

B.

EBITDA, FFO and net cash flows after debt service

1.

EBITDA indices

2.

“FFO” (funds from operations) – with respect to active projects – cash flows from current operating activities for the period (including changes in working capital) and less investments in property, plant and equipment and periodic maintenance costs that are not included in the operating activities and less net interest payments. With respect to the rest of the Group’s activities – cash flows from current operating activities for the period (including changes in working capital) and less net interest payments (to the extent they do not relate to projects under construction). It is clarified that investments in property, plant and equipment (under construction and/or in development) including the net interest payments in respect thereof, are not included in FFO.

3.

“Net cash flows after service of project debt” – the “FFO” less/plus payment of principal in respect of financial debt and/or taking out of project debt and non‑project debt (loans and/or debentures), and after adjustments for a change in other credit from banks and a change in cash, including cash restricted for debt service and deposits (including to secure transactions hedging electricity margins).

---

12	It is clarified that income in respect of lost profits is included in EBITDA in the consolidated statements.

4.	Analysis of the results of operations for the Year Ended December 31, 2024 (in millions of NIS) (Cont.)

B.

EBITDA, FFO and net cash flows after debt service (Cont.)

---

13	It is noted that other companies might define EBITDA and FFO indices differently.

4.	Analysis of the results of operations for the Year Ended December 31, 2024 (in millions of NIS) (Cont.)

B.

EBITDA, FFO and net cash flows after debt service (Cont.)

(1)

Calculation of the Group’s share in the proportionate EBITDA, FFO and net cash flows after service of project debt of associated companies in the Energy Transition segment (in millions of NIS):

For the year ended December 31, 2024		Fairview				Towantic				Maryland				(1) Shore				Valley				Three Rivers				Total
Revenues from sales of energy			206				217				185				155				352				61				1,176
Cost of natural gas			91				98				73				73				127				36				498
Carbon emissions tax (RGGI)			–				41				33				47				80				–				201
Cost of sales – other expenses (without
depreciation and amortization)			2				4				8				6				7				2				29
Gain (loss) on realization of transactions
hedging the electricity margins			21				(12	)			(3	)			14				47				17				84
Net energy margin			134				62				68				43				185				40				532
Revenues from capacity payments			18				122				16				19				58				4				237
Other income			4				6				9				6				3				2				30
Gross profit			156				190				93				68				246				46				799
Fixed costs (without depreciation and
amortization)			14				21				28				28				76				13				180
Administrative and general expenses
(without depreciation and amortization)			5				4				5				5				8				2				29
Gain (loss) from revaluation of unrealized
hedging transactions			10				(1	)			(1	)			(6	)			–				–				2
Group’s share in proportionate EBITDA in the Energy
Transition segment (2)			147				164				59				29				162				31				592
Group’s share in FFO			106				157				21				18				68				15				385
Net cash flows after service of project debt (3)			(4)289				65				8				17				(1	)			10				388

(1)	At the Shore power plant – gas transmission costs (totaling in 2024 about NIS 22 million) are classified in accordance with IFRS 16 as depreciation expenses and, accordingly, are not included in the EBITDA.

(2)	It is noted that the increase in the holdings in the Shore and Maryland power plants in the fourth quarter of 2024, as detailed in Note 24C to the financial statements, did not have a significant impact on the results of the Energy Transition segment in the U.S. in 2024.

(3)

It is pointed out that the financing agreements of the CPV Group include arrangements for mechanisms of the “cash sweep” type, in the framework of which all or part of the free cash flows of the projects is designated for repayment of loan principal on a current basis along with a predetermined minimum repayment schedule relating to every long‑term loan. Accordingly, there could be an acceleration of execution of repayments upon occurrence of certain events and there are also restrictions on distributions of dividends.

(4)

The net cash flows after debt service in Fairview include taking out of additional financing for the project as part of a refinancing made in the third quarter of 2024 (which was distributed as a dividend to the partners in the project). For details – see Section 8.17.4 of Part A of the Periodic Report.

4.	Analysis of the results of operations for the Year Ended December 31, 2024 (in millions of NIS) (Cont.)

B.

EBITDA, FFO and net cash flows after debt service (Cont.)

(1)

Calculation of the Group’s share in the proportionate EBITDA, FFO and net cash flows after service of project debt of associated companies (in millions of NIS):

For the year ended December 31, 2023		Fairview				Towantic				Maryland				(1) Shore				Valley				(2) Three Rivers				Total
Revenues from sales of energy			191				181				156				147				268				28				971
Cost of natural gas			81				90				77				71				107				17				443
Carbon emissions tax (RGGI)**			(1	)			27				20				29				43				–				118
Cost of sales – other expenses (without
depreciation and amortization)			2				3				7				6				6				–				24
Gain on realization of transactions hedging
the electricity margins			32				(2	)			8				(1	)			77				–				114
Net energy margin			141				59				60				40				189				11				500
Revenues from capacity payments			23				106				24				25				57				2				237
Other income			2				3				3				5				4				1				18
Gross profit			166				168				87				70				250				14				755
Fixed costs (without depreciation and
amortization)			12				19				19				26				68				4				148
Administrative and general expenses
(without depreciation and amortization)			4				5				4				5				8				1				27
Gain (loss) from revaluation of unrealized
hedging transactions			(9	)			56				(1	)			(39	)			–				1				8
Group’s share in proportionate EBITDA in the Energy
Transition segment			141				200				63				–				174				10				588
Group’s share in FFO			124				103				(3)15				(4)5				75				–				322
Net cash flows after service of project debt			11				(37	)			10				(8	)			11				–				(13	)

(1)	At the Shore power plant – gas transport costs (totaling in 2023 about NIS 22 million) are classified in accordance with IFRS 16 as depreciation expenses and, accordingly, are not included in the EBITDA.

(2)	The financial results of Three Rivers are included starting from the commercial operation date, which took place in the third quarter of 2023.

(3)	The FFO in 2023 includes a payment in respect of project for upgrading facilities in the Maryland power plant, in the amount of about NIS 8 million.

(4)	The FFO in 2023 includes a payment, in the amount of about NIS 9 million, in respect of significant maintenance work performed.

4.	Analysis of the results of operations for the Year Ended December 31, 2024 (in millions of NIS) (Cont.)

B.

EBITDA, FFO and net cash flows after debt service (Cont.)

(2)

Calculation of the Group’s share in EBITDA after proportionate consolidation of the renewable energies segment (in NIS millions):

		January–				November–				Total
		October				December				2024				Total
		2024				2024				Proportionate				2023
		Consolidated				Associated				Consolidation				Consolidated
Revenues			203				29				232				136
Fixed costs (without depreciation and
amortization)			(61	)			(5	)			(66	)			(41	)
Administrative and general			(26	)			(4	)			(30	)			(23	)
EBITDA from active projects			126				20				142				72
Business development and other costs			(26	)			(4	)			(30	)			(41	)
Share of the Group in EBITDA after
proportionate consolidation in the renewable
energies segment in the U.S.			96				16				112				31

4.	Analysis of the results of operations for the Year Ended December 31, 2024 (in millions of NIS) (Cont.)

B.

EBITDA, FFO and net cash flows after debt service (Cont.)

(3)

Set forth below is a breakdown of the EBITDA after proportionate consolidation data broken down by subsidiaries (on a consolidated basis) and the associated companies (on a proportionate basis, based on the rate of the holdings of the CPV Group therein) as well as FFO and cash flows after service of project debt data (in NIS millions):

						For the year ended												For the year ended
Main projects in operation		Basis of				December 31, 2024												December 31, 2023
		presentation												Net cash												Net cash
		in the				EBITDA								flows				EBITDA								flows
		Company’s				after								after				after								after
		financial				proportionate								debt				proportionate								debt
		statements				consolidation				FFO				service				consolidation				FFO				service
Total operating projects in Israel and
accompanying business activities (1)		Consolidated					670				498				(9)(8)361				602				483				412
Business development costs,
headquarters in Israel and other costs		Consolidated					(31	)			(70	)			(9)(8)59				(40	)			(43	)			(43	)
Total Israel							639				428				420				562				440				369
Total operating projects (2)		Associated					592				385				388				589				322				(13	)
Other costs		Consolidated					(4	)			(14	)			(14	)			(4	)			(4	)			(4	)
Total energy transition in the U.S.							588				371				374				585				318				(17	)
Total operating projects (2) (3)		Associated					142				74				14				72				54				6
Business development and other costs		Associated					(30	)			(23	)			(23	)			(41	)			(41	)			(41	)
Total renewable energy in the U.S.							112				51				(9	)			31				13				(35	)
Total activities as part of the “others”
segment (4)		Consolidated					(22	)			(22	)			(22	)			(26	)			(26	)			(26	)
Headquarters in the United States (5) (6)		Consolidated					(89	)			(61	)			(61	)			(26	)			(41	)			(41	)
Total United States							589				339				282				564				264				(119	)
Company headquarters (not allocated
to the segments)		Consolidated					(20	)			(41	)			(37	)			(27	)			(56	)			(87	)
Total consolidated (7)							1,208				726				665				1,099				648				163

(1)

The accompanying business activities in Israel include mainly virtual supply activities through OPC Israel, sale of electricity from facilities for generation of energy on the customer’s premises through a subsidiary (indirect) and sale/purchase of natural gas, including with third parties through OPC Natural Gas.

(2)	For details regarding active projects in the Energy Transition segment in the U.S. – see Section 1 above and regarding calculation of the Group’s share in the EBITDA after proportionate consolidation of the Renewable Energies segment – see Section 2 above.

(3)	Due to completion of the transaction for investment in the area of renewable energies in the U.S. in November 2024, the data of this segment in the U.S. is calculated from this date on the basis of proportionate consolidation where the share of the CPV Group is 66.67%.

(4)	Includes mainly business development and other costs in the area of initiation and development of high‑efficiency power plants running on natural gas, with future carbon capture potential, and the results of the retail activities in the U.S.

(5)	Most of the change in the year of the report compared with the same period last year, in the amount of $45 million, is with respect to a profit participation plan for employees of the CPV Group, which is measured at fair value. For details – see Note 16 to the financial statements.

(6)	After elimination of management fees between the CPV Group and the Company, in the amounts of about NIS 31 million and about NIS 29 million for the years ended December 31, 2024 and 2023, respectively.

(7)	In the period of the report, the consolidated FFO without adjustments for changes in the working capital was about NIS 663 million (in the corresponding period last year – about NIS 606 million).

(8)	Net cash flows after debt service is presented net and includes taking out of the corporate credit in OPC Israel less early repayment of the project financing in Zomet and Gat. For details – see Note 14B(1) to the financial statements.

(9)	Not including intercompany activities between the Company and the subsidiaries in Israel.

4.	Analysis of the results of operations for the Year Ended December 31, 2024 (in millions of NIS) (Cont.)

C.

Analysis of the change in EBITDA – Israel segment

1.

Availability (operational) – as stated in Section 7.11.1 of Part A of the Periodic Report, in the period of the report, the Rotem power plant was shut down during March 2024 for purposes of planned maintenance work, which lasted for 17 days, which negatively impacted its results in the period of the report, including compared with the corresponding period last year. In addition, the Gat power plant was shut down in July through November 2024 for purposes of unplanned maintenance due to a breakdown that caused a shutdown of the power plant’s activities and had a negative impact on its results in the period of the report including compared with the corresponding period last year.

4.	Analysis of the results of operations for the Year Ended December 31, 2024 (in millions of NIS) (Cont.)

C.

Analysis of the change in EBITDA – Israel segment (Cont.)

2.

Commercial operation and increase in capacity tariffs in Zomet – the financial results of Zomet are included starting from the commercial operation, at the end of June 2024. For details regarding an increase in the capacity tariffs at the Zomet power plant in January 2024 – see Section 7.13 of Part A of the Periodic Report.

3.

One‑time events – in 2023, includes mainly signing of a compromise agreement with Hadera’s construction contractor whereby revenues were recognized, in the amount of about NIS 41 million in respect of lost revenues caused to Hadera due to a delay in the commercial operation of the power plant and non‑recurring income, in the amount of about NIS 18 million, as described in Note 26C(3) to the Financial Statements, while on the other hand expenses of about NIS 18 million are also included, relating to pre‑commercial operation of the Zomet power plant, at the end of June 2023. In addition, in the period of the report, an amendment to the agreement was signed with Zomet’s construction contractor, in the framework of which, among other things, the construction contractor paid Zomet compensation, in the amount of about NIS 26 million (about $7 million) in respect of a loss of revenues caused to Zomet due to delay in the commercial operation date of the power plant. For additional details – see Note 26A(3) to the Financial Statements. Furthermore, in the third quarter of 2024, Hadera received a one‑time amount from its insurers of about NIS 18 million ($5 million) in connection with lost profits that preceded the commercial operation of the power plant. For additional details – see Note 26A(2) to the Financial Statements.

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14

That stated constitutes “forward‑looking” information as it is defined in the Securities Law. Ultimately, there could be delays in completion of the required clarification and repairs and/or other operation limitations as a result of, among other things, technical and/or operational factors and/or factors relating to the construction contractor.

4.	Analysis of the results of operations for the Year Ended December 31, 2024 (in millions of NIS) (Cont.)

D.

Analysis of the change in EBITDA after proportionate consolidation – energy transition segment in the U.S.

(1)

Reflects the results of the Maryland power plant deriving from completion of two transactions for increase of the holdings in Maryland in October and December 2024 at the rate of 25% each. For details – see Note 24C to the financial statements.

(2)

The increase in the operating expenses in the year of the report compared with last year stems mainly from the commercial operation of the Three Rivers power plant in 2023 and from unplanned maintenance performed at the Maryland power plant in 2024.

4.	Analysis of the results of operations for the Year Ended December 31, 2024 (in millions of NIS) (Cont.)

E.

Renewable energies segment in the U.S.

4.	Analysis of the results of operations for the Year Ended December 31, 2024 (in millions of NIS) (Cont.)

F.

Additional details regarding energy hedges and guaranteed capacity payments in the Energy Transition segment in the U.S.

(*)

Pursuant to the policy for hedging electricity margins as at the date of the report, in general the CPV Group seeks to hedge up to 50% of the scope of the expected generation. The actual hedge rate could ultimately be different.

(**)

The net energy margin is the energy margin (Spark Spread) plus/minus Power Basis less carbon tax (RGGI) and other variable costs. For details regarding the manner of calculation of the electricity margin (Spark Spread) – see Section 3.3K above. The market prices of energy margin are based on future contracts for electricity and natural gas.

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4.	Analysis of the results of operations for the Year Ended December 31, 2024 (in millions of NIS) (Cont.)

F.

Additional details regarding energy hedges and guaranteed capacity payments in the Energy Transition segment in the U.S. (Cont.)

G.

Net income and adjusted net income (in millions of NIS)

1.

Definitions

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4.	Analysis of the results of operations for the Year Ended December 31, 2024 (in millions of NIS) (Cont.)

G.

Analysis of the change in net income and adjusted net income (in millions of NIS)

(1)

The increase stems mainly from an increase in the financing expenses, in the amount of about NIS 24 million, of the power plants in the Energy Transition segment against the background of signing new financing agreements in 2023 and 2024, particularly in the Valley power plant (for details – see Section 9B below), an increase in depreciation and financing expenses, in the amount of about NIS 18 million, in respect of commercial operation of the Three Rivers power plant in the third quarter of 2023, an increase in depreciation and financing expenses, in the amount of about NIS 21 million, relating to transition to presenting the investment in the renewable energies segment in the U.S. based on the equity method of accounting, commencing from November 2024, and an increase in depreciation and financing expenses, in the amount of about NIS 10 million, due to increase in the rate of holdings in the Shore and Maryland power plants in the fourth quarter of 2024.

(2)

Most of the increase stems from depreciation expenses of the Zomet power plant (in the amount of about NIS 23 million), which was operated commercially at the end of the second quarter of 2023 and in the renewable energies segment in the U.S. prior to the exit from the consolidation (in the amount of about NIS 27 million) mainly in respect of the Maple Hill and Stagecoach projects that were commercially operated in the fourth quarter of 2023 and during the second quarter of 2024. On the other hand, there was a decline of about NIS 23 million, deriving from the decision of the CPV Group made in 2023 to discontinue the development of a natural gas project in the U.S.

(3)

Most of the increase stems from financing expenses relating to the Zomet power plant, in the amount of about NIS 41 million, the Gat power plant, in the amount of about NIS 7 million and financing expenses that were recorded in the statement of income in respect of the financing framework of renewable energy projects in the U.S. prior to exit from the consolidation, in the amount of about NIS 26 million. Furthermore, there was an increase in the interest expenses in respect of the tax equity agreements in the U.S. prior to exit from the consolidation, in the amount of about NIS 15 million. On the other hand, there was an increase in the financing income, deriving from the impact of the changes in the exchange of the dollar against the shekel, in the amount of about NIS 36 million.

4.	Analysis of the results of operations for the Year Ended December 31, 2024 (in millions of NIS) (Cont.)

G.

Analysis of the change in net income and adjusted net income (in millions of NIS) (Cont.)

(4)

For details regarding loss of control, discontinuation of the consolidation and transition to the equity method of accounting in the fourth quarter of 2024 with respect to the investment in CPV Renewable – see Note 23E to the financial statements.

(5)

A loss from impairment in value of the investment in Gnrgy in 2024, in the amount of about NIS 19 million (in 2023 – about NIS 23 million) –for additional details regarding an agreement for sale of Gnrgy shares – see Note 11C to the Financial Statements. In addition, in 2024 there was an impairment loss in Hadera 2, in the amount of about NIS 31 million, in light of the government’s decision to reject the plan, for additional details, particularly regarding the Company’s petition to the High Court of Justice regarding this matter, see Note 10B(4) to the Financial Statements, and in 2023 there were non‑recurring revenues, net, in the amount of about NIS 12 million.

(6)

Includes non‑recurring financing expenses relating to repayment of project credit in Zomet and Gat, in the amount of about NIS 49 million (about NIS 38 million, net of tax). For details – see Note 14B(1) to the Financial Statements.

4.	Analysis of the results of operations for the Year Ended December 31, 2024 (in millions of NIS) (Cont.)

H.

Detail of generation

						For the Year Ended December 31, 2024																For the Year Ended December 31, 2023
																		Actual																Actual
						Potential				Net				Actual				calculated				Potential				Net				Actual				calculated
						electricity				electricity				generation				availability				electricity				electricity				generation				availability
		Capacity				generation				generation				percentage				percentage				generation				generation				percentage				percentage
		(MW)				(GWh)(1)				(GWh)(2)				(%)(3)				(%)				(GWh)				(GWh)				(%)				(%)
Rotem			466				3,736				3,332				89.2	%			95.1	%			3,761				3,514				93.4	%			98.5	%
Hadera			144				1,048				943				90.0	%			92.6	%			1,036				939				90.6	%			90.7	%
Gat			75				616				397				64.4	%			64.4	%			458				433				94.5	%			94.4	%
Zomet			396				3,268				428				13.1	%			83.6	%			1,742				283				16.2	%			88.0	%

(1)

The generation potential is the net generation capability adjusted for temperature and humidity.

(2)

The actual net generation in the period.

(3)

The actual generation percentage is the net electricity generated divided by the generation potential.

(4)

For details regarding planned maintenance at Rotem, unplanned maintenance at Gat and planned and unplanned work at Zomet in 2024 – see Section 4C above.

						For the Year Ended December 31, 2024																For the Year Ended December 31, 2023
						Potential				Net				Actual				Actual				Potential				Net				Actual				Actual
						electricity				electricity				generation				availability				electricity				electricity				generation				availability
		Capacity				generation				generation				percentage				percentage				generation				generation				percentage				percentage
		(MW)				(GWh)(1)				(GWh)(2)				(%)(3)				(%)				(GWh)				(GWh)				(%)				(%)
		Energy transition projects (natural gas)
Fairview			1,050				8,601				7,610				82.1	%			88.5	%			8,160				7,213				81.1	%			84.2	%
Towantic			805				6,521				5,593				77.7	%			89.9	%			6,888				5,551				77.5	%			91.2	%
Maryland			745				5,958				3,628				56.3	%			90.3	%			6,089				4,162				64.5	%			93.0	%
Shore			725				6,130				3,612				56.9	%			92.4	%			5,333				4,000				63.3	%			83.4	%
Valley			720				5,838				5,002				82.1	%			89.1	%			5,867				4,392				72.3	%			77.6	%
Three  Rivers			1,258				9,792				6,366				59.9	%			76.9	%			4,220				2,814				64.0	%			74.8	%

(1)	The potential generation is the gross generation capability during the period after planned maintenance and less the electricity used for the power plant’s internal purposes.

(2)	The net generation of electricity is the gross generation during the period less the electricity used for the power plant’s internal purposes.

(3)	The actual generation percentage is the quantity of the net electricity generated in the facilities compared with the maximum quantity that can be generated in the period.

(*)	It is noted that the generation data of the Gat, Zomet and Three Rivers power plants were included starting from the initial consolidation date or the commercial operation date, as applicable, which took place in 2023.

5.	Analysis of the results of operations for the Three Months Ended December 31, 2024 (in millions of NIS)

A.

Statement of income

		For the Three Months Ended
Section		December 31
		2024				2023
Revenues from sales and provision of services (1)			589				581
Cost of sales and provision of services (without depreciation and amortization) (2)			(438	)			(432	)
Depreciation and amortization			(72	)			(83	)
Gross profit			79				66
Administrative and general expenses			(72	)			(30	)
Share in earnings of associated companies			16				63
Business development expenses			(12	)			(11	)
Compensation for lost revenues			–				41
Other expenses, net			(6	)			(22	)
Gain on loss of control in the renewable energies segment in the U.S.			259				–
Operating income			264				107
Financing expenses, net			(52	)			(54	)
Income before taxes on income			212				53
Taxes on income			(89	)			(24	)
Net income for the period *			123				29
Attributable to:
The Company’s shareholders			28				23
Holders of non‑controlling interests			95				6

*	For an analysis of the change in the net income and an analysis of the change in the adjusted net income – see Section 4F below.