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The contract pays for energy; the system charges for the hour when it is missing

2 days ago
19 min read

Evidence markers: [V] verified in a primary source · [D] derived by calculation · [E] estimate with explicit assumptions · [H] hypothesis pending testing

Contracting energy and covering demand in critical hours are decisions that must be evaluated together. The 7 countries examined have mechanisms for recognizing, contracting, or remunerating firmness (§1). For this note, firmness means a resource’s accredited contribution under critical conditions; each country uses its own definitions and metrics. The cases reviewed show why buyers must distinguish contractual price, coverage, and additional costs. What they receive also depends on the authorities. Those authorities compare generation, storage, network, and contracting alternatives by their total cost, supply risk, and effects on energy transition objectives.

The note examines firmness mechanisms and public procurement processes for regulated supply. It distinguishes energy contract tenders from mechanisms for allocating or settling capacity and firm energy. Depending on the country and process, authorities, tendering entities, distributors, retailers, and generators participate with different responsibilities. Contract analysis is limited to the public documentation cited. Agreements with unregulated buyers fall outside the corpus reviewed. The implications for them are presented as questions to test against their own clauses.

For buyers, there are 3 critical issues: what backup will be available in the system, what firmness is required of and recognized for contracted resources, and how supply shortfalls will be paid for. Developers, in turn, must evaluate which asset to build, with how much storage, and under what conditions they will recover their investment.

What buyers receive depends on 3 decisions by the authorities. First, what level of adequacy to require and which contingencies to cover. Second, how to coordinate generation, storage, and network expansion with contracting and remuneration requirements. Third, how to allocate the costs of coverage and shortfalls among participants. Buyers and developers must understand and factor them in.

0 · Structure of this note

Section 1 identifies firmness mechanisms. Sections 2 to 4 distinguish contractual price, physical availability, and awards; sections 5 to 7 examine system constraints, backup costs, and contracted coverage. Section 8 brings together regulatory changes and section 9 specifies buyers’ and developers’ decisions, with the authorities’ decisions as a condition. Each case separates observed results, projections, and causal hypotheses.

1 · Firmness is recognized in the 7 countries reviewed, with mechanisms to contract and pay for it

Each country recognizes firm capacity or energy, or mandates its procurement, through a mechanism established in regulation [V].

Country

How firmness is contracted or paid for

Source

Mexico

Mercado para el Balance de Potencia (Capacity Balancing Market): annual, ex post market for those who did not cover their capacity requirement through contracts [V]

Centro Nacional de Control de Energía (CENACE), system operator · 1

Chile

Peaking capacity price set by decree in the node price; in tender 2026/01, fixed capacity price in the tender rules [V]

Ministerio de Energía and Comisión Nacional de Energía (CNE) · 4 and 6

Colombia

Cargo por Confiabilidad (Reliability Charge) since 2006: firm energy obligations allocated by auction [V]

Comisión de Regulación de Energía y Gas (CREG) · 7

Peru

Regulated basic capacity price, with a gas turbine as the reference unit [V]

Osinergmin, regulator · 12

Dominican Republic

Distributor contracts with their own capacity price, at USD 27.8–35.5/kW-month [V]

State-owned distributors, 2024 award record · 13

Guatemala

Legal obligation for each distributor to "cover all of its Firm Demand through capacity contracts" [V]

Reglamento del Administrador del Mercado Mayorista (Wholesale Market Administrator Regulations) · 14

Panama

Obligation for each distributor to cover its maximum demand through firm capacity contracts [V]

Centro Nacional de Despacho, operator · 15

Firmness payments reach substantial amounts. In Mexico, the monetary amounts for capacity purchased and sold totaled MXN 19.7 billion for production year 2024 and MXN 21 billion for 2025 [D; N3]. In the market corresponding to 2024, 38.8% of the Sistema Interconectado Nacional’s net capacity obligation remained unmet [D; N3]. That obligation is the balance that had to be purchased in this market after contractual coverage was considered; the percentage describes that balance and is distinct from unserved demand. In Colombia, the CREG reported an amount to be distributed through the Cargo por Confiabilidad exceeding COP 6 trillion in 2024 [V].

If firmness is already recognized and paid for, the relevant question for buyers is why inadequacy risks persist and how much it costs to cover them. The following sections examine the 3 issues buyers must evaluate together. They are the backup available in the system, the firmness required of and recognized for contracted resources, and payment for shortfalls.

Sources: 1, 4, 6, 7, 12, 13, 14, and 15. N3: settlements and capacity obligation in Mexico.

2 · Tendering differentiated time bands does not ensure differentiated energy prices: Chile

  • Differentiated time bands were tendered. The CNE divided supply in tender 2025/01 into 3 blocks: nighttime, from 23:00 to 07:59; solar, from 08:00 to 17:59; evening peak, from 18:00 to 22:59 [V].

  • The 3 blocks were awarded at the same price. The CNE received 708 bids from 6 companies, for 3.9 times the energy requested [V]. It awarded 100% to 1 generator, Enel, at USD 64.5/MWh in each block [V], using the criterion of the lowest present value of bid prices and their indexation [V].

  • The CNE distinguishes the contract from physical injection. In its explanation of tender 2026/01, it describes a financial contract: the supplier makes withdrawals from the spot market to serve contracted consumption and has no physical injection commitment [V]. Separately, in the 2025/01 award, the indexation formula was 70% Henry Hub and 30% United States consumer price index [V].

  • Capacity is remunerated separately. Decreto 1T/2025 (Decree 1T/2025) set the regulated peaking capacity price at CLP 8.53 thousand/kW-month for the Quillota reference node, effective from April 2025 [V]. This equals USD 8.95/kW-month at the observed dollar exchange rate of April 1, 2025 [D; R1].

  • In other contracts, the energy payment adjusts according to marginal cost. Exceptional tender 2025/02 included a mechanism under which the price paid by the customer changes according to the system’s marginal cost [V].

Awarding the same energy price across time bands leaves their hourly economic valuation unresolved. The contractual price is the same across blocks. Total payment must include capacity and applicable adjustments. The supplier remains exposed to differences between that price and the cost of supply. In the event of early termination, the buyer must evaluate replacement cost and conditions (§9). Comparing bids requires estimating the total cost and coverage of each alternative under common scenarios.

3 · Awarding capacity does not guarantee that plants operate on time or are available in every critical hour: Colombia

  • Colombia has had the Cargo por Confiabilidad since 2006. This mechanism allocates firm energy obligations against the energy each plant can guarantee under critical hydrology [V]. The CREG reported an amount to be distributed exceeding COP 6 trillion for 2024. Since 2008, the charge has represented about 20% of monthly generation revenue [V].

  • In 2024, almost all new capacity for 2027–28 was awarded to solar. The February 2024 auction allocated 4.44 GW of solar, 99% of new capacity, compared with 48 MW of thermal capacity [V]. The auction cleared at USD 18.2/MWh [V].

  • Nameplate capacity and firm energy are different quantities. The Unidad de Planeación Minero Energética (UPME) applies firm energy factors of 13% to solar and 90% to gas-fired thermal generation [V]. These are planning factors; auctions apply another methodology, plant by plant [V]. These factors measure energy; availability between 18:00 and 22:00 remains unproven.

  • There were delays relative to commitments and forecasts. Of the 17 plants from the 2019 auction cited by the CREG, 5 came online on schedule [V]. Separately, XM, the system operator, considered 3.2 GW of new solar for 2025; 334 MW came online [V], 10.4% of the forecast [D; R2]. These are different project sets from those in the auction for 2027–28.

  • The obligations are activated depending on the scarcity price. During El Niño of 2023–24, according to the CREG, the spot price exceeded the marginal scarcity price "on only a few occasions" [V, as a CREG statement]. On March 27, 2024, aggregate reservoir storage was at 32.5%, below the minimum for March in the previous 20 years [V]. The effectiveness of those activation conditions requires further evaluation.

  • The UPME identifies reliability standard breaches in its reference scenario. In cases with a deficit, the expected energy rationing value exceeds its 3% limit from 2028 under medium demand. With demand at the upper bound of the 68% confidence interval, it exceeds the limit from 2026 [V, as a UPME projection]. These are simulation results under that scenario’s assumptions; the average across all cases uses another indicator and a different threshold.

Attributing projected inadequacy to the awarded solar mix remains a hypothesis [H]. Testing it would require comparing scenarios with different generation mixes, with comparable demand, hydrology, transmission, and in-service dates. The change in unserved energy from modifying the mix and the share attributable to other constraints would be measured.

4 · Designing contracts with supply obligations for critical hours does not guarantee awards: Colombia

  • The next firmness auction awarded a different mix. In May 2026, 4.07 GW of new capacity was awarded for 2029–30 [V]: 55.9% thermal, 38% solar, and 6% wind [D; N1]. Solar contributed 7.7% of total firm energy allocated; hydro and thermal, 92.2% [D; N1]. These are different denominators: new capacity versus total firm energy. Clearing prices were set at USD 16.4/MWh and USD 22/MWh, in 2 groups of plants according to their variable cost, under the rule the CREG adopted in 2024 [V].

  • Contracts with hourly obligations were offered in a separate auction. In July 2026, the Ministerio de Minas y Energía offered 4 products for 15 years from 2030 in the long-term contract auction [V]. The dedicated battery-backed peak product, P4, required flat supply from 18:00 to 22:00 [V].

  • The dedicated peak product received no award. Bids totaled 558 MWh/day against 5,990 requested [V], 9.3% [D; R3]. The auctioneer attributed the lack of an award to the 40% competition limit and confirmed there were valid bids [V, as an auctioneer statement]. Article 9 of Resolución CREG 101 109 de 2026 (CREG Resolution 101 109 of 2026) limits each seller’s share of daily energy offered for the auction. Parties with the same controlling entity or a control relationship are grouped for this calculation [V]. The bulletin identifies the cause; reconstructing individual shares requires bid details.

  • A hybrid product including peak supply was awarded. Product P3, hybrid with batteries, covers the 08:00 to 18:00 and 18:00 to 22:00 time bands; 390 MWh/day was awarded [V]. That volume corresponds to the complete product, including solar and peak hours. Together with the solar product, a total of 4.56 GWh/day was contracted [D; R4], 19.3% of the amount requested [D; R5]. All awarded generation was solar [V].

  • The hybrid product was awarded at a higher price than the solar profile. The solar profile, from 06:00 to 18:00, was awarded at COP 246/kWh. The hybrid with batteries was awarded at COP 316/kWh, with delivery from 08:00 to 18:00 and 18:00 to 22:00. Its price was 28.3% higher [V; D; R10]. The comparison concerns complete products with different profiles; isolating the value of peak supply and the cost of storage requires additional information. The flat 24-hour product was canceled for lack of the 3 required competitors [V].

The lack of an award concerns dedicated product P4; peak delivery was contracted within the hybrid product. Those designing procurement must verify resource availability, competition conditions, and the cost of backup alternatives. Rules, prices, and the hydrological context also changed between the 2024 and 2026 firmness auctions. Their contribution to the change in mix has yet to be isolated [H; test in §9].

5 · Renewable curtailment, deficit risks, and preventive rationing measures can occur in the same system: Chile

  • Renewable generation was curtailed in large volumes. The Coordinador Eléctrico Nacional, the system operator, recorded 6.08 TWh of solar and wind curtailment in 2025 [V], 18.6% of what those plants generated [D; R6].

  • In July 2026, deficits were projected for that winter. The operator estimated deficits of 305 GWh in July and 558 GWh in August, 4% and 8% of consumption [V, as an operator projection]. The scenario assumed dry hydrology and the Santa María and Nueva Ventanas plants out of service [V].

  • Separately, local preventive rationing was decreed in December 2025. The Ministerio de Energía issued the measure for Los Maquis–Hualañé [V]. The CNE linked it to exclusively solar distributed generation, with a limited nighttime contribution [V, as a CNE attribution]. This is a local, preventive measure; implemented national rationing remains unsubstantiated.

  • The operator identifies distinct physical constraints. The Coordinador attributes curtailment to transmission congestion and supply surpluses at certain times [V, as an operator attribution]. In 2025, the 500 kV section between Polpaico and Nueva Pan de Azúcar recorded 1.31 thousand decoupled hours [V]. The report expected the Kimal–Lo Aguirre direct-current link to enter service in 2029 [V]. The projected deficits correspond to the hydrology, plant availability, and fuel supply scenario described in the study [V].

  • Documented responses include fuels and storage. The operator estimated additional gas needs of approximately 30 million cubic meters in July 2026 and 50 million in August [V, as an operator scenario]. It assumed Argentine imports of 3 million cubic meters per day and effective availability of 66% [V, as an operator scenario]. It also instructed preparations for possible diesel operation at Nehuenco in the event of gas suspension and a system emergency [V]. During 2025, 690 MW of batteries entered operation; the report recorded another 6.41 GW of projects under construction or connection [V].

Energy available at certain times or locations can coexist with shortfalls at others. Addressing these risks depends on authorities coordinating procurement, network expansion, and generation and fuel availability. That coordination starts from measures underway and their implementation status. Whether contract design contributes to the documented imbalances remains a hypothesis [H]. Testing it would require comparing contracting alternatives with equivalent demand, network, hydrology, and project in-service dates, separating the effects of additional physical investments.

6 · Users pay for backup in addition to energy, although that backup covers only the critical scenarios the authority chooses to cover: Peru

  • The backup charges users pay exceed the renewable premium. In the tariff for May 2025 to April 2026, reserve, capacity, and reliability charges total PEN 10.1/kW-month [D; R7]. The renewable premium totals PEN 7.08/kW-month [V].

  • Backup charges evolved differently from the renewable premium. Between 2019 and 2025, the premium fell 37%. The cold reserve charge increased 18% and the generation capacity charge, 53% [D; N2]. Those payments remunerate backup for the system as a whole. Attribution to the absence of renewable generation remains unproven.

  • Osinergmin excluded the scenario without Camisea when determining the target firm reserve margin. It calculated a target of 19.9% for May 2025–April 2029 [V]. In the scenario of total pipeline unavailability, the reserve margin including maintenance averaged 57.9% [V]. This indicator is calculated before the deduction of cold reserve firm capacity used to obtain the target. The 2 percentages must be distinguished. Osinergmin excluded that scenario because of its low probability, referring to a total and permanent supply interruption [V, as a regulator decision].

  • A gas supply emergency followed. Osinergmin’s Resolución 40-2026-OS/CD (Resolution 40-2026-OS/CD) records that the Ministerio de Energía y Minas declared an emergency from March 1 to 14, 2026 and activated rationing in gas allocation [V; source 17]. The event’s duration and the scenario of total and permanent interruption must be distinguished when evaluating the previous reserve decision.

The authority sizing backup must decide which risks to cover and at what cost. The emergency must be incorporated into that review, distinguishing the anticipated risk, the event that occurred, and its electricity consequences.

7 · Guatemala requires firmness and evaluates capacity and energy together; PEG-5 left volume unawarded

  • The system uses imports and coal- and coke-fired generation. For 2025, the Administrador del Mercado Mayorista (AMM) reported a 15.5% import share in its production-by-resource chart. The category of energy imports from Mexico represented 67.7% of total imports shown in the balance [V]. Coal and coke contributed 27% [D]. The report uses different aggregates for commercial imports, deviations, and inadvertent energy. The denominators are specified in the file. Demand at 20:00 rose from 1.54 GW in 2018 to more than 1.94 GW in 2025 [V]. The Ministerio de Energía y Minas expansion plan warns of "a growing gap between available supply and demand" [V]. That context alone leaves firmness inadequacy unproven.

  • Coverage of all firm demand is required and awards are based on combined cost. Distributors must cover 100% of their firm demand with capacity contracts [V]. Solar and wind firmness is accredited according to delivery from 18:00 to 22:00, with a 95% probability of exceedance [V]. Awards in tender PEG-5 were based on the minimum total cost of capacity and energy [V].

  • Capacity remained to be contracted in PEG-5. Against 1.4 GW requested from 2033 [V], the 42 blocks awarded for 15 years total 1.26 GW of maximum guaranteed capacity [D; N4]. The contract allocation report confirms that volume from 2033 to 2044 [V]. The difference of 142 MW [D; R8] is represented by a virtual bidder [V]. Distributors’ other contracts must be reviewed to determine their coverage.

  • Different ways of providing firmness were allowed. Participants could accredit it through their own resources or backup contracts [V]. The awarded solar component totaled 701 MW [D; N4]; its identifiers include batteries, although 2 descriptions in the list say only "Solar" [V]. Of the maximum 960 MW offered in the 6 natural gas rows, 15 MW was awarded [D; N4].

  • Required supply and eligible technologies were modified for PEG-6. The Comisión Nacional de Energía Eléctrica (CNEE) required firm energy with a capacity factor of at least 90% [V]. It also required an offer of energy associated with capacity during all hours of the day in every year of the supply period [V]. For new plants, it allowed geothermal and natural gas, a category extended to ethane and propane [V].

The authority and buyer must define how much to contract, for which profile, and with which resources. Joint evaluation of capacity and energy already exists in PEG-5 [V]. Achieved coverage, residual risks, and replacement cost remain to be verified. Distributors must consider all their contracts when verifying coverage. Generators must evaluate which bids are eligible in each tender.

Attributing the PEG-6 change to the PEG-5 result remains a hypothesis [H]. That attribution has not been located in the recitals of resoluciones CNEE-323-2026 y CNEE-344-2026 (resolutions CNEE-323-2026 and CNEE-344-2026). Testing it requires reviewing the technical background and decision file for an explicit link to PEG-5 results or alternative documented reasons.

8 · Regulators are adjusting backup requirements; buyers and developers must evaluate energy and firmness together following these changes

Regulators and tendering entities modify technical requirements, procurement products, or remuneration conditions. Changes are documented in 5 countries during 2025–26 [V]. Their effect on contracting, adequacy, and cost remains to be evaluated.

Country

Documented change

Result or pending issue

Mexico

In the May 2026 call for projects, the Secretaría de Energía (SENER) requires new renewable plants to have storage of at least 30% of their capacity and 3 hours [V]

Storage is a technical condition, with no buyer or specific price for that backup in the call [V]; the capacity mechanism continues separately

Dominican Republic

In the 600 MW renewable round, projects with 50% battery backup were awarded [V]

54.3% of the tendered volume was awarded [D; N5]; the award criterion remained unpublished in the cited source

Colombia

A dedicated battery-backed peak product was offered in the 2026 auction [V]

Product P4 received no award; hybrid P3 did include peak supply [V]

Chile

Tender 2026/01 allows storage and fixes the capacity price in its rules; tender 2025/02 adjusts price according to marginal cost [V]

The 2026/01 award is scheduled for January 13, 2027 [V]

Guatemala

PEG-6 requires firm energy in all hours, with a capacity factor of at least 90%; new plants may use geothermal and natural gas [V]

The award is scheduled for May 6, 2027 [V]

In Mexico, the cited calls incorporate storage requirements for new projects; the Mercado para el Balance de Potencia continues separately. Capacity was tendered as a product in the 2016 and 2017 auctions [V]; the 2017 auction allocated 2.56 GW of new capacity, including 550 MW of gas turbines [V; D; N6]. The 2018 auction was canceled in January 2019 [V]. Since 2025, calls have been issued for permits aligned with binding planning, in which storage is a technical condition, with no specific price for that backup [V].

Planning targets, purchase obligations, and generation results must be distinguished. In Mexico, SENER cites 4 clean generation figures for 2030, with different bases and without reconciling them. They are 38% in the Programa Sectorial (Sectoral Program), 21.5% in the Plan Nacional de Desarrollo (National Development Plan) and up to 45% in Plan México (Plan Mexico). The Plan de Desarrollo del Sector Eléctrico (Electricity Sector Development Plan) gives 35%, "potentially reaching an approximate value of 38%" [V]. The following estimate takes 38% as its reference. In 2024, clean generation was 23.4% of the total [V].

In a scenario calculated from the 2024 base, closing the gap to 38% exclusively with solar is equivalent to adding 4.4 to 5 GW per year between 2025 and 2030 [E; N8]. Production from other clean technologies is held constant and total generation growth of 1.2% to 2.2% per year is assumed. An approximate solar factor based on 2024 data is used. The interval equals 2.5–2.8 times [E; R9] the largest net annual addition in the 2017 to 2024 photovoltaic series: 1.77 GW in 2019. Its average was 977 MW/year [D; N7]. This is an energy equivalence under assumptions. Its cost and feasibility remain to be evaluated.

In Colombia, 10% of retailers’ purchases must come from nonconventional renewable sources; the obligation is enforceable and subject to penalties [V]. In 2025, those sources met about 6% of demand [V]. Retailer purchases and total demand are different universes. These percentages do not establish a compliance gap.

The instruments in the other 5 countries correspond to different obligations and objectives. The Dominican Republic’s Ley 57-07 (Law 57-07) uses "shall endeavor" for the 2025 objective. Panama’s Agenda de Transición Energética (Energy Transition Agenda) of 2020 describes the climate contributions at that time as an "ethical, nonmandatory commitment". Peru repealed the provision establishing the target percentage in January 2025; Guatemala includes a policy target and Chile exceeded its law’s 20% threshold [V, within each source’s scope]. These precedents must be distinguished from a comprehensive legal evaluation of their current enforceability.

These changes redefine participation conditions; their effect on contracting, adequacy, and cost remains to be evaluated. Regulators decide which requirements to incorporate. Buyers and developers must assess the cost of compliance and the coverage they obtain. Even in Guatemala’s design, where capacity and energy are already awarded on their combined cost [V], residual risks and replacement alternatives must be examined.

Sources: 1, 2, 4, 11, 13, 14, and 15. N6–N8: historical results and Mexican estimate. R9: multiple of the estimated interval.

9 · Buyers and developers must integrate energy, availability, and backup into their decision; the authority sets the conditions

The integration of contracted energy, accredited firmness, and physically available supply is evaluated at 2 levels: each company’s coverage and system adequacy. Buyers and developers assess their contracts and assets; authorities set the conditions within which they do so. This requires 2 company decisions and 1 condition that both must require or factor in.

The buyer awarding regulated supply · Capital Allocation. The cited processes compare indexed prices, consumer benefits, or combined capacity and energy costs [V]. An integrated calculation of replacement in the event of nonperformance remains unidentified in the public documents reviewed. In Chile, the CNE explained that exceptional tender 2025/02 responded to early terminations of contracts from previous processes, including one from 2022/01 [V]. It was awarded at an average price of USD 98.7/MWh, compared with USD 64.5/MWh in regular tender 2025/01 [V]. Comparing those prices requires normalizing term, indexation, profile, adjustments, and risks; their difference is distinct from replacement cost.

At InsightIA, we propose that buyers jointly evaluate their contracts, the capacity they pay for separately, and replacement cost. They must do so on the basis of delivery hours and nonperformance scenarios. That evaluation applies within current award criteria and serves to propose adjustments to future processes when those criteria omit relevant costs or risks. To verify its application, the selected bid’s total cost and coverage against the alternatives must be documented, even if a uniform price across time bands is chosen.

The generator building an asset · Capital Projects. In Colombia, solar dominated new capacity in the 2024 firmness auction and thermal in 2026 [V]. Rules, prices, and the hydrological context changed between the 2 [V]. Attributing the change in mix to a specific regulatory modification remains a hypothesis [H]. Testing it would require comparing bids and awards under alternative rules, with other conditions comparable. Mexico requires storage in the cited calls without a specific price for that backup [V].

At InsightIA, we propose that developers evaluate each asset under current firmness rules and explicit scenarios of modification. Storage would be sized according to the cost and value of alternatives, as well as the technical requirement. The evaluation must show whether installing batteries above the technical minimum improves expected profitability or reduces risks at an acceptable cost compared with alternative configurations.

Buyers freely contracting energy fall outside this analysis. In Chile, they withdraw 61.7% of energy [V]. Each can apply the same question to its contract: what covers it when the resource is unavailable and who pays for that hour.

The condition set by the authority. Authorities, together with the planner and operator, define what adequacy level to require, which contingencies to cover, and what residual risk to accept. They also compare expansion and contracting alternatives by total cost and supply risk, and decide who pays. For buyers and developers, those decisions are an input to their calculations. What the rule leaves uncovered, they cover themselves, pay for under another line item, or require in the next process.

For those purchasing energy by contract, the lowest-price offer per MWh and the lowest-total-cost combination for their critical hours may be 2 different purchases. Buyers decide that difference before awarding supply. Developers decide it before committing investment: which asset, with how much storage, and under which firmness rule they recover their investment.

Sources: 4, 7, 8, 12, and 14. The work proposed within InsightIA’s functions has no demonstrated results.

Sources

  1. CENACE · Recálculos del Mercado para el Balance de Potencia (Capacity Balancing Market Recalculations): production year 2024, September 23, 2025, pp. 14–15 and 19 of the PDF; production year 2025, September 3, 2026, p. 19. Presentación del fallo SLP-1/2017 (Presentation of the SLP-1/2017 Award), p. 7. Direct links and sums by zone in the file. https://www.cenace.gob.mx/Paginas/SIM/informesEjecutivos.aspx

  2. SENER · Plan de Desarrollo del Sector Eléctrico 2025–39 (Electricity Sector Development Plan 2025–39), Diario Oficial de la Federación, October 17, 2025, tables 2.1 and 2.2; Programa Sectorial de Energía (Energy Sectoral Program); Segunda Convocatoria (Second Call for Projects), May 11, 2026; Acuerdo de requisitos de Certificados de Energías Limpias (CEL) 2025–26 (Agreement on Clean Energy Certificate Requirements 2025–26). https://sidof.segob.gob.mx/notas/docFuente/5770297

  3. Secretaría de Hacienda y Crédito Público (SHCP) · Cuenta Pública 2024 (2024 Public Accounts), volume VIII, Comisión Federal de Electricidad (CFE) Suministrador de Servicios Básicos, notes to the financial statements.

  4. CNE de Chile · Bases definitivas y comunicado de adjudicación de la licitación 2025/01 (Final Rules and Award Announcement for Tender 2025/01); bases y comunicado de adjudicación de la licitación excepcional 2025/02 (Rules and Award Announcement for Exceptional Tender 2025/02); comunicado de adjudicación de la licitación 2023/01 (Award Announcement for Tender 2023/01); webinar de la licitación 2026/01 (Tender 2026/01 Webinar); informe técnico del Decreto 43/2025 (Technical Report on Decree 43/2025). https://www.cne.cl/

  5. Coordinador Eléctrico Nacional · Reporte Anual Art. 72-15 (Art. 72-15 Annual Report), year 2025; Informe DEAS-GM-SEN N.º 18/2026 (Report DEAS-GM-SEN No. 18/2026). https://www.coordinador.cl/

  6. Ministerio de Energía de Chile · Decreto 1T/2025 de precios de nudo (Decree 1T/2025 on Node Prices); Decreto Supremo 70/2023 (Supreme Decree 70/2023); Política Energética Nacional (National Energy Policy), 2022 update.

  7. CREG · Documentos 901 153 de 2024 (Documents 901 153 of 2024) (pp. 5–10), 901 202 de 2025 (901 202 of 2025) (p. 26) and 901 211 de 2025 (901 211 of 2025) (pp. 20–21); Resolución 101 109 de 2026 (Resolution 101 109 of 2026), article 9. https://gestornormativo.creg.gov.co/gestor/entorno/docs/resolucion_creg_101-109_2026.htm

  8. XM · Informe de resultados de la subasta CLPE 03-2021 (CLPE 03-2021 Auction Results Report); Informe de Operación y Mercado 2025 (2025 Operation and Market Report); resultados de la subasta de energía firme 2029–30 (2029–30 Firm Energy Auction Results). https://www.xm.com.co/

  9. UPME · Plan Indicativo de Expansión de la Generación 2025–2039 (Indicative Generation Expansion Plan 2025–2039), tables 9–11 and pp. 35–37 of the PDF. https://docs.upme.gov.co/SIMEC/Energia%20Electrica/PIEG/2025-2039/PIEG_2025_2039_Version_final.pdf

  10. Bolsa Mercantil de Colombia · Informe de cierre de la subasta CLPE 2026 (CLPE 2026 Auction Closing Report) and boletines 8, 9 y 10 (bulletins 8, 9, and 10); bulletin 10 cites Resolución CREG 101 109 de 2026. https://www.bolsamercantil.com.co/

  11. Ministerio de Minas y Energía de Colombia · Resoluciones 40715 de 2019, 40060 de 2021 y 40208 de 2026 (Resolutions 40715 of 2019, 40060 of 2021, and 40208 of 2026).

  12. Osinergmin · Informes técnicos 108-2025-GRT, 225-2025-GRT y 348-2019-GRT (Technical Reports 108-2025-GRT, 225-2025-GRT, and 348-2019-GRT); Resolución 40-2026-OS/CD. https://www.gob.pe/osinergmin

  13. Presidencia de la República Dominicana · Notas sobre la licitación de 600 MW renovables (Notes on the 600 MW Renewable Tender), dated October 15, 2025 and June 25, 2026; nota sobre el informe del Organismo Coordinador del 11 de noviembre de 2025 (note on the Organismo Coordinador report of November 11, 2025). Edeeste · Resultado de adjudicación EDES-LPI-NG-04-2023 (Award Result EDES-LPI-NG-04-2023). Ley 57-07.

  14. CNEE and Administrador del Mercado Mayorista (AMM) of Guatemala · Bases de la licitación PEG-5-2025 (Rules for Tender PEG-5-2025); Resolución CNEE-97-2026 (Resolution CNEE-97-2026) and its award annex; resoluciones CNEE-323-2026 y CNEE-344-2026 (Resolutions CNEE-323-2026 and CNEE-344-2026, PEG-6); Empresa Eléctrica de Guatemala (EEGSA), aviso de la PEG-6 (PEG-6 Notice); Norma de Coordinación Comercial N.º 2 (Commercial Coordination Standard No. 2); Reglamento del AMM (AMM Regulations); Informe Estadístico 2025 (2025 Statistical Report); Ministerio de Energía y Minas, Plan de Expansión Indicativo 2026–50 (Indicative Expansion Plan 2026–50).

  15. Autoridad Nacional de los Servicios Públicos (ASEP), Empresa de Transmisión Eléctrica (ETESA), Centro Nacional de Despacho (CND), and Secretaría Nacional de Energía de Panamá · Plan de Expansión 2025–39 (Expansion Plan 2025–39); capacitación del CND de abril de 2025 (CND Training of April 2025); consulta pública 009-26 (Public Consultation 009-26); Resolución de Gabinete 93 de 2020 (Cabinet Resolution 93 of 2020).

  16. Servicio de Impuestos Internos (SII) de Chile · Dólar observado del 1 de abril de 2025 (Observed Dollar Exchange Rate of April 1, 2025). Accessed: October 15, 2026. https://www.sii.cl/valores_y_fechas/dolar/dolar2025.htm

  17. Osinergmin · Resolución 40-2026-OS/CD, p. 2 of the PDF: records the emergency declaration and activation of gas rationing by the Ministerio de Energía y Minas, from March 1 to 14, 2026. https://cdn.www.gob.pe/uploads/document/file/9570359/7835037-resolucion-de-consejo-directivo-40-2026-os-cd.pdf

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