Pampa Energía (PAM) 6-KCurrent report (foreign)

Buenos Aires, November 6, 2024

¹ The information is based on FS prepared according to IFRS in force in Argentina.
² Sales from the affiliates CTBSA, Transener and TGS are excluded, shown as ‘Results for participation in joint businesses and associates.’ 
³ Consolidated adjusted EBITDA represents the flows before financial items, income tax, depreciations and amortizations, extraordinary and non-cash income and expense, equity income, and includes affiliates’ EBITDA at our ownership. Further information on section 3.1. 

1. Relevant Events

1.1 Tender offer for 2027 Notes and international placement of 2031 Notes

On August 26, 2024, Pampa’s Board of Directors approved the repurchase at par value of the 2027 Notes for US$750 million of face value, 7.5% fixed rate and maturing in January 2027. The tender ended on September 5, 2024, participating approximately 53% of the total, equivalent to US$397 million.

The funds for the tender came from the successful placement of the 2031 Notes for US$410 million at a 7.95% annual fixed rate and 8.25% yield, maturing on September 10, 2031. The issuance received offers exceeding US$1.6 billion from international institutional investors. This transaction strengthens Pampa’s debt profile, paving the way for the upcoming investments in Vaca Muerta, especially in developing the Rincón de Aranda shale oil block.

1.2 Power generation segment

Partial commissioning of PEPE 6

In September 2024, 7 Vestas wind turbines were commissioned, adding 31.5 MW. On October 11, 2024, 4 more were commissioned for 18 MW. Hence, 25 of the 31 wind turbines are commissioned, with a total capacity of 112.5 MW.

All the wind turbines and civil works were finished in October. PEPE 6 is estimated to be fully online and reach a total capacity of 140 MW by November 2024. With this investment of approximately US$250 million, Pampa has 427 MW of total installed wind power capacity, ranking as one of the country’s leading renewable power producers.

2024-2026 contingency plan

On October 1, 2024, the SE established a plan to face the energy system’s critical situation during the seven months of peak demand (December to March and June to August) (Res. No. 294/24). The plan includes a voluntary participation scheme that recognizes an additional remuneration, effective from December 2024 to March 2026. Pampa is analyzing participation in the said scheme.

⁴ Ranges between nodes with high (1.25), medium (1.00), and low (0.75) criticality, and between summer and winter.

Updates for the spot remuneration scheme

License expiration and transition period at Mendoza hydros

On October 19, 2024, the HIDISA license concessions were scheduled to expire, one for the assets and water usage granted by the Province of Mendoza and another for the power generation granted by the National Government. Pampa holds 61% of HIDISA’s share capital.

On October 18, 2024, the Government of Mendoza set a 12-month transition period starting from the expiration date, appointing the Undersecretary of Energy and Mining as observer (Decree No. 2,096/24). Additionally, the National Coordination Secretary of Energy and Mining set the transition period until June 1, 2025, and appointed the SSEE as observer (Res. SCEyM No. 1/24).

The transition period at HINISA expires on November 30, 2024. Pampa sent a letter to the SE seeking guidance on the next steps. 

1.3 Increases in regulated tariffs

Natural gas

On August 29, 2024, the SE adjusted the PIST values for natural gas from September 2024 (Res. SE No. 232/24). Later, on September 27, 2024, an additional reduction was applied, effective from October 2024 (Res. SE No. 284/24):

Note: Consumption exceeding the cap for N2 and N3, which varies according to consumption range, distributor, and zone, will be valued at N1 price without any discount.

Cost variations

1.4 Acquisition of OCP Ecuador shares and end of concession

On August 30, 2024, Pampa acquired the remaining 36% of OCP Ecuador, where it already held 64% of the capital, for US$23 million. With this transaction, Pampa became the sole owner of OCP Ecuador and began consolidating the company in its FS.

OCP Ecuador operates the country’s main private pipeline, extending 485 kilometers and transporting an average of 150 thousand barrels of Ecuadorian crude daily, approximately 30% of national production, along with 10 thousand barrels per day of Colombian oil.

The OCP concession has been extended for three months until November 30, 2024, when the shares must be transferred to the Ecuadorian State. OCP Ecuador is working with the authorities to carry out the transition per the provisions of the concession contract. 

On October 21, 2024, Pampa transferred its 22.51% stake in the hydrocarbon exploitation license and joint operatorship at the Gobernador Ayala block to Pluspetrol for $23 million. 

Public hearing for the tenure extension of the gas transportation license

On October 21, 2024, ENARGAS held a public hearing to discuss the tenure extension of TGS’s license for natural gas transportation, expiring in December 2027. The original contract allowed for a 10-year extension, but the Ley Bases, passed in July 2024, enables an extension of up to 20 years until December 2047.

Conditioning capacity expansion at Tratayén

In October 2024, the construction and commissioning of the first natural gas conditioning module at TGS’s Tratayén Plant was completed, increasing its capacity by 6.6 million m³ per day. The second module, adding another 6.6 million m³, is expected to be online by the end of 2024. This investment of approximately US$350 million will enable the plant to reach a total conditioning capacity of 28 million m³ per day.

2. Financial highlights

2.1 Consolidated balance sheet

2.2 Consolidated income statement

Note: 1 It considers the Employee stock-based compensation plan shares, which amounted to 3.9 million common shares as of September 30, 2023 and 2024.

2.3 Cash and financial borrowings

Note: Financial debt includes accrued interest. 1 It includes cash and cash equivalents, financial assets at fair value with changing results, and investments at amortized cost. 2 Under IFRS, the affiliates CTBSA, Transener and TGS are not consolidated in Pampa.

Debt transactions

As of September 30, 2024, Pampa’s financial debt under IFRS amounted to US$1,725 million, 19% higher than the end of 2023, mainly due to the international issuance of the 2031 Notes, partially offset by the repurchase of the 2027 Notes. However, net debt decreased to US$539 million, the lowest amount in the last 8 years, explained by the contributions of operating cash flow from power and E&P businesses and improved collections from CAMMESA and ENARSA.

The table below shows the gross debt principal breakdown:

With the issuance of the 2031 Notes, the financial debt increased its average life to 3.4 years. The chart below shows the principal maturity profile, net of repurchases, in US$ million by the end of Q3 24:

Note: The chart only considers Pampa consolidated under IFRS. It does not include affiliates TGS, Transener, and CTBSA.

During Q3 24, Pampa issued the Series 21 CB for US$410 million, at an interest rate of 7.95%, maturing in September 2031, and repurchased in cash at par value its Series 1 CB for US$397 million, remaining an outstanding amount of US$353 million of face value. After the quarter’s closing, Pampa issued the Series 22 CB for US$84 million at an interest rate of 5.75%, maturing in October 2028, and canceled US$47 million from the Series 20 CB, remaining an outstanding amount of US$60 million.

Regarding our affiliates, in Q3 24, TGS issued its Series 3 CB for US$490 million, at an interest rate of 8.5%, maturing in July 2031, and redeemed the total outstanding of its 2025 Notes for US$470 million. In addition, TGS took short-term borrowings for US$5 million and paid import financing equivalent to US$2 million. CTEB paid short-term net bank borrowings for AR$20,496 million and took borrowings for US$10 million. After the quarter’s closing, CTEB took borrowings for US$57 million and canceled its Series 4 CB for US$96 million.

As of this report’s issuance date, we comply with the covenants established in our debt agreements.

Summary of debt securities

Notes: 1 According to IFRS, affiliates are not consolidated in Pampa’s FS. 2 Series 4 CB from CTEB was canceled after Q3 24 closing.
3 Series 22 CB from Pampa was issued after the Q3 24 closing.

Credit ratings

Note: 1 Stand-alone. 2 Local ratings issued by FIX SCR.

3. Analysis of the Q3 24 results

Note: Net income attributable to the Company’s shareholders.

3.1 Reconciliation of consolidated adjusted EBITDA

3.2 Analysis of the power generation segment

During Q3 24, power generation sales increased 12% year-on-year, mainly due to higher legacy or spot energy prices from the AR$ increases that outpaced the devaluation, in addition to outstanding operating performance with higher availability and load factor in spot and PPAs units. MATER sales also grew, thanks to the gradual commissioning of PEPE 6. These effects were partially offset by lower Energía Plus demand due to the decline in industrial activity and the divestment of PEMC in August 2023.

Additionally, spot energy remuneration increases impacted the CCGTs capacity payment, which also has a partial income in US$ (US$5.3 thousand per MW-month, +16% year-on-year and +11% vs. Q2 24). For open cycles (GT and ST), the remuneration was equivalent to US$4.8 thousand per MW-month (+23% vs. Q3 23 and vs. Q2 24) and US$2.3 thousand per MW-month for hydros (+24% vs. Q3 23 and +15% vs. Q2 24).

Compared to Q2 24, the increase of 9% in sales responds to better spot prices and higher thermal dispatch.

The operating performance of Pampa’s operated power generation grew by 19% vs. Q3 23, compared to a 3% year-on-year drop in national generation, because of the lower availability of the grid’s power plants due to maintenance. This increase was mainly attributed to higher dispatch at CTGEBA because of improved natural gas supply and overhauls in Q3 23 (+597 GWh), at CTEB (+173 GWh) and CTLL due to an outage in the GT05 and overhauls in Q3 23 (+159 GWh). Lower water at HPPL (-148 GWh) and PEMC’s divestment (-97 GWh) partially offset these effects.

The availability of Pampa’s operated units reached 96.2% in Q3 24, 244-basis points higher than Q3 23’s 93.7%, due to the outage at CTLL’s GT05 and programmed overhauls at CTGEBA’s GT03 in Q3 23, that were offset by an outage at CTLL’s GT05 during August 2024. Therefore, a 96.0% thermal availability rate was reached in Q3 24, 392 basis points higher than 92.1% from Q3 23.

Note: Gross margin before amortization and depreciation. It includes CTEB, operated by Pampa (co-operated by Pampa, 50% equity stake). PEMC was de-consolidated in August 2023.

Excluding depreciation and amortizations, net operating costs increased by 14% to US$88 million vs. Q3 23, mainly explained by lower overdue interests from CAMMESA due to a drop in rates and days of sales outstanding, and by gas and electricity transportation tariff increases. These effects were partially offset by lower power purchases to cover contracts. Compared to Q2 24, operating costs rose 42% due to lower overdue interests from CAMMESA and higher maintenance expenses and power purchases, partially offset by lower labor costs.

Financial results in Q3 24 reached a net profit of US$12 million, 83% lower than Q3 23, mainly due to lower gains from financial instruments, offset by reduced financial interests because of lower AR$-debt stock and lesser losses from FX differences, due to minor devaluation impact over AR$ trade receivables.

Adjusted EBITDA from the power generation segment was US$112 million, a 23% increase year-on-year, boosted by the spot energy prices and operational outperformance, offset by higher operating expenses. Adjusted EBITDA excludes non-operating, non-recurrent and non-cash items and considers CTEB’s 50% ownership, which posted US$16 million in Q3 24, the same as in Q3 23.

Finally, without CTEB, capital expenditures registered US$24 million in Q3 24 vs. US$46 million in Q3 23, explained by the completion of works in PEPE 4 (commissioned in Q4 23) and partially offset by the last disbursements for PEPE 6, which is estimated to be fully operating by Q4 24. The PEPE 6 project is detailed below:

Note: 1 Without value-added tax. 2 Estimated average.

3.3 Analysis of the oil and gas segment

In Q3 24, sales from the oil and gas segment grew by 10% vs. Q3 23, mainly due to the increased gas deliveries under Plan Gas, thanks to the GPNK commissioned in August 2023. However, deliveries were limited by transportation constraints due to delays in the commissioning of GPNK’s compressor stations and higher temperatures in September. Higher gas sales prices to distribution companies, in line with the demand tariff increases, and better crude oil prices and volumes contributed to the segment’s sales increase. These effects were partially offset by lower gas sales to large users and exports to Chile, which were affected by the economic downturn and higher hydrology, respectively.

Note: The net production in Argentina. The gas volume is standardized at 9,300 kilocalories (kCal).

Regarding operating performance, total production in Q3 24 was 87.5 kboe per day (+9% vs. Q3 23 but -4% vs. Q2 24), with an increase in gas production to 13.9 million m³ per day (+8% vs. Q3 23 but -4% vs. Q2 24), boosted by the latest round 4.2 of Plan Gas filling the GPNK, but limited by transportation constraints. Lower gas demand from Chile and industries and higher temperatures in September partially offset the year-on-year and quarter-on-quarter increases.

Analyzing the gas output by block, 57% of our total production in Q3 24 came from El Mangrullo, where we reached 8.0 million m³ per day (+7% vs. Q3 23, but -13% vs. Q2 24). Sierra Chata followed with a 29% contribution, growing production to 4.0 million m³ per day (+18% vs. Q3 23 and +20% vs. Q2 24). The outstanding productivity of Sierra Chata’s shale wells hit a production record in July, with 5.0 million m³ per day. At non-operated blocks, Río Neuquén maintained a steady production at 1.7 million m³ per day (+2% vs. Q3 23 and similar to Q2 24), while Rincón del Mangrullo continued to deplete, contributing 0.2 million m³ per day (-21% vs. Q3 23 and -9% vs. Q2 24).

Our gas price in Q3 24 averaged US$4.4 per MBTU (-6% vs. Q3 23 but +10% vs. Q2 24, due to seasonality), primarily explained by lower exports to Chile and sales to large users, partially offset by higher prices to retail, in line with the tariff increases. As a result, Plan Gas compensation decreased 41% vs. Q3 23 to US$18 million.

Regarding our gas deliveries, during Q3 24, 46% was destined for distribution companies and 40% for thermal power generation, both under Plan Gas. 7% supplied the industrial/spot market, 3% was exported, and the remaining was sold to our petchem plants as raw material. Compared to Q3 23, 41% supplied the retail segment, 41% the thermal power units, 10% sold to the industrial/spot market, 5% was exported and the remainder to our petchem plants.

Oil production reached 5.4 kbbl per day in Q3 24 (+16% vs. Q3 23 and similar to Q2 24), driven by the start of shale oil production at Rincón de Aranda (+1.2 kbbl per day), partially offset by year-on-year decreases of 0.2 kbbl per day at El Tordillo and 0.5 kbbl per day at Los Blancos.

Our oil price in Q3 24 was 14% higher than Q3 23, reaching US$71.9 per barrel, with domestic and export prices very similar. 54% of our sales were destined for the domestic market, compared to 85% during Q3 23.

The lifting cost^[5] recorded US$48 million in Q3 24 (+16% vs. Q3 23 and +9% vs. Q2 24), mainly due to the shale oil development in Rincón de Aranda and, to a lesser extent, higher gas treatment and transportation costs. The lifting cost per boe increased to US$6.0 per boe produced in Q3 24, vs. US$5.6 per boe in Q3 23 (+6%) and US$5.3 per boe in Q2 24 (+12%). However, gas lifting cost decreased by 2% vs. Q3 23 to US$0.8/MBTU, explained by the growth in production.

Regarding other operating income and expenses, higher crude oil stock costs and royalties stand out due to the increased crude oil price and gas production. Plan Gas compensation reached US$18 million, a 41% year-on-year decrease because of the higher prices charged to distribution companies, as mentioned before. These effects were partially offset by higher overdue interests, explained by a year-on-year rise in Plan Gas invoicing.

Financial results in Q3 24 recorded net losses of US$24 million, a 69% improvement vs. Q3 23, mainly due to lower financial interests from decreased AR$-debt stock and lesser losses from FX differences due to the minor devaluation impact over trade receivables in AR$, partially offset by lower gains from holding financial securities.

Our oil and gas adjusted EBITDA amounted to US$122 million in Q3 24 (-8% vs. Q3 23), mainly explained by higher operating expenses and lower sales to industries and exports, partially offset by higher gas deliveries under Plan Gas, thanks to the GPNK. The adjusted EBITDA excludes non-recurring and non-cash income and expenses, as well as overdue interests, which are mainly charged to CAMMESA.

Finally, capital expenditures amounted to US$46 million in Q3 24 (-73% vs. Q3 23), mainly driven by the shale gas deployment during 2023, partially offset by the beginning of the shale oil pilot plan in Rincón de Aranda.

⁵ It only considers maintenance, treatment, internal transportation and wellhead staff costs. It does not include amortizations and depreciations.

3.4 Analysis of the petrochemicals segment

The adjusted EBITDA for the petrochemicals segment reached US$2 million in Q3 24, an 88% drop compared to Q3 23. This decrease was driven by lower international spread in reforming products, a drop in domestic polystyrene prices, a decline in domestic volumes of styrenics and higher US$-denominated operating expenses. These effects were partially offset by higher dispatch of reforming products, both in domestic and foreign markets. In addition, we recorded a US$3 million profit from the settlement of exports at a differential FX.

Total volume sold increased by 25% vs. Q3 23, reaching 128 thousand tons, driven by higher reforming dispatch of octane basis in the local market and isomerized naphtha and aromatic for export. Lower demand for styrene, polystyrene and SBR partially offset these gains, mainly due to the local industry activity.

In Q3 24, financial results from the petrochemicals segment reached a profit of US$2 million, similar to Q3 23 US$3 million profit, mainly explained by the lower impact of the AR$ devaluation over payables.

 Note: 1 Includes Propylene.

3.5 Analysis of the holding and others segment

The holding and others segment, excluding the affiliates’ equity income (TGS and Transener), posted a lower loss on operating margin of US$8 million in Q3 24 vs. US$18 million in Q3 23, mainly explained by the accounting consolidation of OCP from September 1, 2024, which contributed US$7 million of operating income, in addition to higher fees, partially offset by higher accrual of executive compensation due to the share price outperformance.

In Q3 24, financial results reached a net profit of US$9 million, US$38 million less than in Q3 23, mainly due to lower earnings from FX difference over tax payables, partially offset by higher gains from holding financial instruments.

The adjusted EBITDA of our holding and others segment reached US$43 million in Q3 24, compared to US$6 million in Q3 23. This calculation excludes non-operating, non-recurring and non-cash items and includes the EBITDA adjusted by equity ownership in TGS and Transener.

Since September 1, OCP Ecuador has contributed an EBITDA of US$7 million to our FS.

In TGS, the EBITDA adjusted by our stake was US$40 million in Q3 24, 90% higher than Q3 23, mainly explained by the 675% tariff increase over the regulated transportation business from April 2024, along with subsequent updates in August and September of 4% and 1%, respectively. To a lesser extent, the midstream segment recorded higher gas transportation and treatment sales in Tratayén vs. Q3 23. These effects were partially offset by lower sales in the liquids segment due to a scheduled overhaul at Cerri and lower ethane prices, partially offset by better propane and butane prices.

In Transener, the EBITDA adjusted by our stake was US$11 million in Q3 24 vs. US$4 million in Q3 23, mainly due to the tariff increase applicable from February 2024 (179.7% Transener and 191.1% Transba), and the tariff updates as from August and September of 6% for each period.

3.6 Analysis of the nine months, by subsidiary and segment

Note: 1 Divested in August 2023. 2 The deletion corresponds to other companies or inter-companies. 3 Net debt includes holding companies. 4 Attributable to the Company’s shareholders.

3.7 Analysis of the quarter, by subsidiary and segment

Note: 1 Divested in August 2023. 2 The deletion corresponds to other companies or inter-companies. 3 Net debt includes holding companies. 4 Attributable to the Company’s shareholders.

4.1 Power generation’s main operational KPIs by plant

Note: Gross margin before amortization and depreciation 1 Fully owned by Pampa from August 2022 to July 2023. 2 Progressive commissioning: 13.5 MW (Jun-24), 31.5 MW (Jul-24), 18 MW (Aug-24), 31,5 MW (Sep-24) and 18 MW (Oct-24). 3 Co-operated by Pampa (50% equity stake).

4.2 Production in the main oil and gas blocks

Note: Production in Argentina. 1 It does not include shale formation. 2 It includes the La Tapera – Puesto Quiroga block. 3 From gas fields.

5. Glossary of terms