CQP

Cheniere Energy Partners, L.P.

NYSE · UTILITIES · NATURAL GAS DISTRIBUTION

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MKT CAP $32BP/E —DIV YIELD —FCF YIELD 8.70%REV TTM $11.5B +15.4%NET INCOME $3.1B +28.1%NET DEBT $13.9B52W 50.91 – 71.22SEC XBRL · TTM TO Invalid Date

How CQP rewrote its risk factors

10-K ITEM 1A · FY2024 → FY2025

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New in FY2025

The EPA approved the petition on July 31, 2025 and in October 2025 the LDEQ confirmed that all remaining milestones under the 2023 Compliance Order have been met.
Our subsidiaries continue to work with the LDEQ to resolve the 2023 Compliance Order.
As of December 2025, our subsidiaries had filed test results with the LDEQ indicating that for the 2025 testing period all 44 turbines met the relevant compliance standard.
As of February 20, 2026, we had 484.1 million common units outstanding held by 10 record owners.
Discussion of items for the year ended December 31, 2023 and variance drivers between the year ended December 31, 2024 as compared to December 31, 2023 are not included herein and can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our annual report on Form 10-K for the fiscal year ended December 31, 2024 .
Our discussion and analysis includes the following subjects: • Overview • Overview of Significant Events • Market Environment • Results of Operations • Liquidity and Capital Resources • Summary of Critical Accounting Estimates • Recent Accounting Standards Overview We are a limited partnership formed by Cheniere to provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world.
We own the natural gas liquefaction and export facility in Cameron Parish, Louisiana at Sabine Pass.
Business and Properties, as well as the current geopolitical environment that has intensified the demand for supply security, should enable us to enter into long-term agreements and provide a foundation for additional growth in our business in the future.
Overview of Significant Events Our significant events since January 1, 2025 and through the filing date of this Form 10-K include the following: Strategic • In June 2025, certain of our subsidiaries updated the SPL Expansion Project’s FERC application, originally filed in February 2024, to reflect a two-phased project, inclusive of three liquefaction trains and supporting infrastructure, maintaining an expected total peak production capacity of up to approximately 20 mtpa of LNG, inclusive of estimated debottlenecking opportunities.
Operational • As of February 20, 2026, over 3,270 cumulative LNG cargoes totaling over 225 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project. • During the second quarter of 2025, we completed planned large-scale maintenance activities on two Trains at the Liquefaction Project.
Financial • In December 2025, SPL redeemed $300 million aggregate principal amount of its 5.875% Senior Secured Notes due 2026 (the “2026 SPL Senior Notes” ) and subsequently in February 2026, SPL redeemed the remaining $200 million aggregate principal amount of its 2026 SPL Senior Notes. • We declared aggregate distributions of $3.29 per common unit for the year ended December 31, 2025.
On January 28, 2026, with respect to the fourth quarter of 2025, we declared a cash distribution of $0.830 per common unit to unitholders of record as of February 9, 2026, and the related general partner distribution, which was paid on February 13, 2026.
These distributions consist of a base amount of $0.775 per unit and a variable amount of $0.055 per unit. • In July 2025, we issued and sold $1.0 billion aggregate principal amount of 5.550% Senior Notes due 2035, and the net proceeds, together with cash on hand, were used to redeem $1.0 billion of the aggregate principal amount of SPL’s 2026 SPL Senior Notes. • In March 2025, SPL repaid the remaining $300 million aggregate principal amount outstanding of its 5.625% Senior Secured Notes due 2025 at maturity. • In February 2025, Fitch Ratings upgraded the issuer credit rating of CQP to BBB from BBB- with a stable outlook.
In June 2025, S&P Global Ratings concurrently assigned a BBB rating to the 2035 CQP Senior Notes and upgraded the remaining unsecured CQP notes to BBB from BBB-.
In November 2025, S&P further upgraded the issuer credit rating of CQP and unsecured CQP notes to BBB+ from BBB and revised its outlook on SPL’s issuer credit rating to positive from stable in December 2025.
Market Environment Our results of operations are affected by the market environment in which we operate, including known trends and uncertainties, macroeconomic factors and other external environmental factors.
With just under 20 mtpa of year on year ( “YoY” ) increase in LNG supplies globally in 2025, the LNG market is transitioning from a multi-year state of tight market conditions into a period of rapid growth.
The continued ramp up in new LNG supplies from the U.S. and Canada mark the start of a more ample supply landscape which is expected to loosen global balances over the next few years and result in a more moderate and stable price environment for LNG.
Sustained downward pressure on global prices could potentially unlock latent demand that has otherwise been priced out since the disruption of Russian natural gas supply to Europe.
The increase in supply corresponded to a 5% YoY uptick in trade, which was primarily supported by Europe and the Middle East and North Africa ( “MENA” ) region amid weaker demand in Asia.
Europe’s demand for LNG increased approximately 27% YoY in 2025 reaching a record level of approximately 125 mtpa.
The main driver for this growth continues to be the replacement of Russian natural gas and the replenishment of underground storage inventories.
We expect this driver to continue to play an important role in keeping LNG demand in Europe resilient, especially in light of the European Parliament’s vote to ban all residual Russian natural gas, including Russian LNG by 2027.
The MENA region also contributed to demand growth in 2025 with imports increasing 7 mtpa or 62% versus 2024.
Egypt was the main driver of this increase as it resorted to additional LNG imports to satisfy its growing domestic energy needs and supplement its own natural gas production.
Asia’s LNG consumption however was down about 4% in 2025, dropping by 12 mtpa to 270 mtpa.
While many of the major markets in Asia saw YoY declines, China’s was the largest, representing nearly the entire YoY change in the region.
China’s LNG imports declined 16% or 12 mtpa YoY, due to broader, likely transient macro-economic challenges.
Natural gas demand growth in China slowed in 2025 and higher piped natural gas flows from Russia and robust domestic natural gas production decreased the call on LNG.
Despite weaker demand in Asia and an easing in geopolitical conflicts during the second half of 2025, average prices remained elevated versus 2024.
The Japan Korea Marker ( “JKM” ) monthly settlement prices in 2025 averaged $12.71 per MMBtu, 7.5% higher YoY while those for Title Transfer Facilities ( “TTF” ) averaged $12.04 per MMBtu, 10.3% higher YoY.
Strong storage injections, an increase in LNG supply and expectations of mild weather resulted in downward pressure in the second half of the year with monthly settlements averaging at least $1.76 per MMBtu lower for JKM and $2.34 per MMBtu lower for TTF versus the first half of the year.
Henry Hub monthly settlements averaged $3.43 per MMBtu during 2025.
As referenced above, expectations of significant LNG capacity expansions in the next few years, and the recent momentum in FIDs if continued, are likely to keep the price trajectory trending lower in Asia and Europe.
We expect the price elastic markets, particularly in Asia, to respond to the increased availability and affordability of supply by growing imports to satisfy latent demand as well as organic longer-term growth.
Results of Operations Year Ended December 31, (in millions, except per unit data) 2025 2024 Variance Revenues LNG revenues $ 8,200 $ 6,550 $ 1,650 LNG revenues—affiliate 2,358 1,954 404 Regasification revenues 136 135 1 Other revenues 64 65 (1) Total revenues 10,758 8,704 2,054 Operating costs and expenses Cost of sales (excluding operating and maintenance expense and depreciation and amortization expense shown separately below) 5,145 3,570 1,575 Cost of sales—affiliate — 4 (4) Operating and maintenance expense 904 824 80 Operating and maintenance expense—affiliate 177 172 5 Operating and maintenance expense—related party 28 58 (30) General and administrative expense 12 10 2 General and administrative expense—affiliate 93 90 3 Depreciation and amortization expense 688 680 8 Other operating costs and expenses 4 14 (10) Other operating costs and expenses—affiliate 1 2 (1) Total operating costs and expenses 7,052 5,424 1,628 Income from operations 3,706 3,280 426 Other income (expense) Interest expense, net of capitalized interest (753) (800) 47 Loss on modification or extinguishment of debt (8) (3) (5) Interest and dividend income 18 33 (15) Other income—affiliate 24 — 24 Total other expense (719) (770) 51 Net income $ 2,987 $ 2,510 $ 477 Basic and diluted net income per common unit $ 5.17 $ 4.25 $ 0.92 Volumes loaded and recognized from the Liquefaction Project Year Ended December 31, 2025 2024 Variance Volumes loaded and recognized as revenues (in TBtu) 1,546 1,567 (21) 2025 vs. 2024 Net income increased by $477 million during the year ended December 31, 2025 as compared to the same period of 2024 primarily due to $344 million of favorable changes in the fair value of agreements accounted for as derivative instruments and a $199 million increase in revenues, net of cost of natural gas feedstock, from increased Henry Hub pricing.
These increases were partially offset by a $63 million decrease in revenues, net of natural gas feedstock, from decreased volume of LNG loaded and recognized between the years.
The following is an expanded discussion of the significant drivers of the variance in net income by line item.
Total revenues The $2.1 billion increase in total revenues during the year ended December 31, 2025 as compared to the same period of 2024 was primarily due to: • $2.1 billion increase from higher pricing per MMBtu as a result of increased Henry Hub pricing; partially offset by • $140 million decrease from lower production volume primarily due to the planned large-scale maintenance activities on two trains at the Liquefaction Project.
Total operating costs and expenses The $1.6 billion increase in total operating costs and expenses during the year ended December 31, 2025 as compared to the same period of 2024 was primarily attributable to: • $1.9 billion increase in the cost of natural gas feedstock largely due to the increase in U.S. natural gas prices; and • $55 million increase in operating and maintenance expense (including affiliate and related party), mainly as a result of the planned large-scale maintenance activities on two trains at the Liquefaction Project; partially offset by • $344 million of gains from changes in fair value of agreements accounted for as derivative instruments included in cost of sales, largely due to favorable changes on our IPM agreements from the narrowing of global and U.S. domestic natural gas spreads and the effect of relative change in volatilities of applicable global and U.S. domestic natural gas prices, partially offset by changes in market-based locational forward price differentials for North American natural gas deliveries.

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Gone since FY2024

Our subsidiaries continue to work with the LDEQ to resolve the matters identified in the 2023 Compliance Order, including the petition pending with the EPA.
As of December 2024, our subsidiaries have filed test results with the LDEQ indicating that for the 2024 testing period all 44 turbines meet the relevant compliance standard.
As of February 14, 2025, we had 484.0 million common units outstanding held by 10 record owners.
Discussion of items for the year ended December 31, 2022 and variance drivers between the year ended December 31, 2023 as compared to December 31, 2022 are not included herein and can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our annual report on Form 10-K for the fiscal year ended December 31, 2023 .
Our discussion and analysis includes the following subjects: • Overview • Overview of Significant Events • M arket Environment • Results of Operations • Liquidity and Capital Resources • Summary of Critical Accounting Estimates • Recent Accounting Standards Overview We are a limited partnership formed by Cheniere to provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world.
We own the natural gas liquefaction and export facility at Sabine Pass, Louisiana.
Through our SPAs and the IPM agreement currently in effect, with approximately 13 years of weighted average remaining life as of December 31, 2024, we have contracted approximately 80% of the total anticipated production from the Liquefaction Project, excluding volumes that are contractually subject to additional liquefaction capacity beyond what is currently in construction or operation.
The majority of our contracts are fixed-priced, long-term SPAs consisting of a fixed fee per MMBtu of LNG plus a variable fee per MMBtu of LNG, with the variable fees generally structured to cover the cost of natural gas purchases, transportation and liquefaction fuel consumed to produce LNG.
Since we procure most of our feedstock for LNG production from the U.S., the structure of these contracts helps limit our exposure to fluctuations in U.S. natural gas prices.
Business and Properties, will provide a foundation for additional growth in our business in the future.
Overview of Significant Events Our significant events since January 1, 2024 and through the filing date of this Form 10-K include the following: Strategic • In February 2024, certain of our subsidiaries submitted an application to the FERC under the NGA for authorization to site, construct and operate the SPL Expansion Project, as well as an application to the DOE requesting authorization to export LNG to FTA countries and non-FTA countries, both of which applications exclude debottlenecking.
In October 2024, the authorization from the DOE to export LNG to FTA countries was received for the SPL Expansion Project.
Operational • As of February 14, 2025, approximately 2,840 cumulative LNG cargoes totaling over 195 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.
Financial • We declared aggregate distributions of $3.465 per common unit for the year ended December 31, 2024.
On January 29, 2025, with respect to the fourth quarter of 2024, we declared a cash distribution of $0.820 per common unit to unitholders of record as of February 10, 2025, and the related general partner distribution, that was paid on February 14, 2025.
These distributions consist of a base amount of $0.775 per unit and a variable amount of $0.045 per unit. • In May 2024, we issued $1.2 billion aggregate principal amount of 5.750% Senior Notes due 2034 (the “2034 CQP Senior Notes” ).
In June 2024, the net proceeds, together with cash on hand, were used to redeem $1.2 billion of the outstanding aggregate principal amount of SPL’s 5.625% Senior Secured Notes due 2025 (the “2025 SPL Senior Notes” ). • Excluding amounts refinanced, SPL redeemed $800 million of outstanding aggregate principal amount of its senior secured notes during the year ended December 31, 2024. • In May 2024, in connection with the 2034 CQP Senior Notes issuance, Moody’s Ratings ( “Moody ’ s” ) upgraded our issuer credit rating to Baa2 from Ba1 and revised our outlook to stable from positive.
Moody’s also upgraded SPL’s issuer credit rating to Baa1 from Baa2 and revised SPL’s outlook to stable from positive.
Market Environment The LNG market in 2024 remained relatively tight as a result of low supply capacity growth, strong demand outside Europe and continued geopolitical tensions.
Global LNG imports registered a very modest growth in 2024, increasing by less than 4 mtpa year on year due to constrained supply from delays to projects under construction, Russian sanctions and a fallow period for new projects coming on-line.
Consequently, a recovery in Asia’s LNG consumption had to be satisfied at the expense of other regions.
Asian demand increased significantly from 2023, adding over 20 mtpa of import year-over-year.
The largest single country contribution to this growth came from China, which increased 6.8 mtpa year-over-year after a slowdown during the previous two years.
Growth outside of Asia tightened the balances further this year by increasing the call on supply away from Europe.
Egypt and Brazil propelled imports from the Middle East, North Africa and Latin America regions by 6.2 mtpa to a total of 25.5 mtpa in 2024.
In contrast, Europe’s imports declined 19% year-over-year, down approximately 22.7 mtpa, due to weak gas-fired power generation demand and sluggish growth in the industrial sector.
These market conditions contributed to a strong spot price environment albeit annual spot prices in 2024 were overall lower than in the previous year.
The TTF monthly settlement prices averaged $10.91/MMBtu in 2024, 20.5% lower than the 2023 average of $13.73/MMBtu.
Similarly, the average settlement price for the Japan Korea Marker ( “JKM” ) was $11.83/MMBtu in 2024, 26.6% lower than the 2023 average of $16.13/MMBtu.
The Henry Hub benchmark also dropped from an average settlement price of $2.74/MMBtu in 2023 to $2.27/MMBtu in 2024, down 17.1% year-over-year.
However, a drop in temperatures in Europe toward the end of 2024 and into the beginning of 2025 has resulted in faster drawdowns from underground storage and a rebound in spot prices relative to the third quarter.
This, along with the expiry of the gas transit agreement between Russia and Ukraine on December 31, 2024, is likely to increase the call on LNG imports in the coming months in order to replenish European gas storage facilities to 90% capacity by November 1, as required by the EU each year.
Results of Operations Year Ended December 31, (in millions, except per unit data) 2024 2023 Variance Revenues LNG revenues $ 6,550 $ 6,991 $ (441) LNG revenues—affiliate 1,954 2,475 (521) Regasification revenues 135 135 — Other revenues 65 63 2 Total revenues 8,704 9,664 (960) Operating costs and expenses Cost of sales (excluding items shown separately below) 3,570 2,721 849 Cost of sales—affiliate 4 22 (18) Operating and maintenance expense 824 879 (55) Operating and maintenance expense—affiliate 172 166 6 Operating and maintenance expense—related party 58 62 (4) General and administrative expense 10 10 — General and administrative expense—affiliate 90 89 1 Depreciation and amortization expense 680 672 8 Other operating costs and expenses 14 6 8 Other operating costs and expenses—affiliate 2 1 1 Total operating costs and expenses 5,424 4,628 796 Income from operations 3,280 5,036 (1,756) Other income (expense) Interest expense, net of capitalized interest (800) (823) 23 Loss on modification or extinguishment of debt (3) (6) 3 Interest and dividend income 33 46 (13) Other income, net — 1 (1) Total other expense (770) (782) 12 Net income $ 2,510 $ 4,254 $ (1,744) Basic and diluted net income per common unit $ 4.25 $ 6.95 $ (2.70) Volumes loaded and recognized from the Liquefaction Project Year Ended December 31, 2024 2023 Variance Volumes loaded and recognized as revenues (in TBtu) 1,567 1,536 31 Net income Net income declined by $1.7 billion during the year ended December 31, 2024 as compared to the same period of 2023 and was primarily attributable to $1.7 billion of decreases in gains from changes in fair value of derivatives.
The majority of the decrease was attributable to our IPM agreement with Tourmaline Oil Marketing Corp, where the associated gains that are primarily included in cost of sales decreased from $1.8 billion during the year ended December 31, 2023 to $251 million during the year ended December 31, 2024, mainly due to the impact on fair value of the decline and sustained moderation of global LNG and gas price volatility and more subdued changes in the current period relative to the same period of 2023 as global gas prices and spreads narrowed as a result of market rebalancing.
The remaining $189 million of decreases in gains from changes in fair value of derivatives during the comparable years was primarily due to an unfavorable shift in long-term U.S. natural gas basis spreads.
The following is an additional discussion of the significant drivers of the variance in net income by line item: Revenues The $960 million decrease in revenues during the year ended December 31, 2024 as compared to the same period of 2023 was primarily attributable to a $1.1 billion decrease from lower pricing per MMBtu as a result of declining Henry Hub pricing, partially offset by a $188 million increase from higher production volume largely due to reduced maintenance activities compared to the same period of 2023 and cooler weather.
Operating costs and expenses The increase in operating costs and expenses of $796 million during the year ended December 31, 2024 as compared to the same period of 2023 was primarily attributable to $1.7 billion of decreases in gains from changes in fair value of derivatives included in cost of sales, as discussed above under Net income .
The unfavorable variance between the comparative years was partially offset by a $740 million decrease in cost of natural gas feedstock, largely due to the decline and sustained moderation of global LNG and gas prices as well as lower U.S. natural gas prices during the year ended December 31, 2024 as compared to the same period of 2023.
Significant factor affecting our results of operations Below is a significant factor that affects our results of operations.
Gains and losses on derivative instruments Derivative instruments, which we use to manage certain risks, are reported at fair value in our Consolidated Financial Statements.

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Sentence-level comparison of Item 1A in the two most recent 10-Ks (FY2024 ↗, FY2025 ↗). A reworded sentence counts as one dropped and one added, so heavy edits read as low “kept”. Headings and page furniture are stripped; nothing is summarised by a model.

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