Business context and reporting period
Cheniere Energy Partners, L.P. (CQP) filed this unaudited Form 10-Q for the quarter and nine months ended September 30, 2021. It owns the Sabine Pass LNG terminal and related pipeline. Five liquefaction trains were operational; Train 6 was commissioning, with feed gas introduced in September and substantial completion expected in the first quarter of 2022. The facility’s stated production capacity is approximately 30 mtpa.
Financial and operating performance
| Metric | Q3 2021 | Q3 2020 | Nine months 2021 | Nine months 2020 |
|---|---|---|---|---|
| Total revenue | $2.324 billion | $982 million | $6.176 billion | $4.170 billion |
| Operating income | $616 million | $152 million | $1.838 billion | $1.500 billion |
| Net income (loss) | $381 million | $(67) million | $1.123 billion | $774 million |
| Net income (loss) per common unit | $0.69 | $(0.08) | $2.07 | $1.55 |
| Operating cash flow | Not separately provided | Not separately provided | $1.667 billion | $1.333 billion |
Revenue growth reflected higher LNG volumes delivered and higher revenue per MMBtu. LNG volumes recognized as revenue were 308 TBtu in Q3, versus 132 TBtu, and 946 TBtu for nine months, versus 666 TBtu. Management said all available LNG volume was delivered in 2021; there were no revenues from customer-notified cargo cancellations in the 2021 periods, unlike 2020.
Calculated operating margin was approximately 26.5% in Q3 2021 versus 15.5% a year earlier, but approximately 29.8% for the first nine months versus 36.0%. Nine-month cost of sales rose to $3.178 billion from $1.551 billion, mainly due to higher natural gas feedstock prices and increased delivered volumes. Net margin for the nine-month periods was approximately 18.2% and 18.6%, respectively. Derivative gains and losses affect reported results and can cause volatility.
Cash and cash equivalents were $1.713 billion at September 30, 2021, up from $1.210 billion at year-end; restricted cash was $133 million. Available commitments were $804 million under SPL’s working-capital facility and $750 million under CQP’s credit facilities, with no borrowings outstanding under either facility. Nine-month capital expenditures paid were $495 million, compared with $795 million in 2020. Cash distributions to owners were $1.073 billion. Gross debt was $18.115 billion, including $944 million classified as current; long-term debt was $17.171 billion. Debt less cash was approximately $16.4 billion, calculated from reported balances.
Material changes and financing
- Nine-month net income increased $349 million; Q3 moved from a $67 million loss to $381 million of income. Management attributed improvement mainly to higher LNG margins and lower commodity-derivative losses.
- Interest expense, net of capitalized interest, declined to $636 million for nine months from $691 million, reflecting refinancing and increased interest capitalization. Debt-extinguishment losses were $81 million for nine months, including $27 million in Q3, primarily from early redemption fees and write-offs associated with debt refinancing.
- CQP issued $1.5 billion of 4.00% notes due 2031 in March and $1.2 billion of 3.52% notes due 2032 in September. Proceeds and cash were used to redeem the 2025 notes and part of the 2026 notes. Subsequent to quarter-end, it redeemed the remaining 2026 notes and $318 million of SPL’s 2022 notes. SPL also expected to issue approximately $482 million of private-placement notes due 2037 in Q4, subject to closing conditions, to refinance part of the 2022 notes.
- Quarterly common-unit distributions increased from $0.655 for Q1 to $0.660 for Q2 and $0.665 for Q3. A $0.680 distribution for Q3 was declared October 26, payable November 12, 2021.
Outlook, risks and unusual items
Management stated that cash flows from operations, available credit, borrowings and equity contributions were expected to provide adequate resources for currently anticipated capital, operating and debt-service needs for Trains 1 through 6. No specific earnings or cash-flow guidance was provided. Train 6 was 97.1% complete at September 30; the filing gives a first-quarter 2022 expected substantial-completion date.
Long-term contracts provide approximately $52.7 billion of unsatisfied transaction price, with a weighted-average recognition timing of nine years. This excludes substantially all variable consideration and certain short-duration contracts, so it is not a complete revenue forecast. Third-party SPAs cover approximately 75% of production capacity for Trains 1–6, potentially increasing to approximately 85% after an SPA Cheniere committed to provide; fixed fees are expected to rise from approximately $2.9 billion annually for Trains 1–5 to at least $3.3 billion after Train 6’s first commercial delivery.
Key exposures include natural-gas price and basis movements, derivative valuation and counterparty risk, LNG demand and customer performance, construction and commissioning, and reliance on related parties. A Level 3 derivative asset of $59 million depended on significant unobservable inputs; net derivative fair value was a $33 million asset. Individual external customers accounted for 11%–20% of Q3 revenue, and one customer represented 31% of external receivables and contract assets at September 30.
Two LNG storage tanks remained out of service following a 2018 leak and vapor release, subject to PHMSA and FERC conditions. PHMSA reduced its proposed penalty to $1.458 million; SPL elected not to contest the violations and to pay. CQP said it did not expect the order, remediation or penalty resolution to materially adversely affect results or operations. CQP and SPL reported compliance with debt covenants. The filing also identifies LIBOR transition, forward-looking-statement uncertainty and U.S. tax and withholding obligations for non-U.S. unitholders as matters to monitor.
Most important facts for investors to verify
- Train 6 completion timing, commissioning progress, final project costs and the status of the third marine berth.
- Whether the refinancing and expected 2037 private placement close as described, and their effect on debt maturities, interest costs and liquidity.
- How higher natural-gas prices, LNG sales prices, volumes and derivative fair-value changes affect realized margins and cash flow.
- Customer concentration, counterparty credit quality, fixed-fee contract performance and the exclusions underlying the $52.7 billion backlog figure.
- Timing and conditions for returning the two tanks to service, and any further PHMSA or FERC requirements.
- Distribution sustainability relative to available cash, debt-service requirements and the partnership’s distribution provisions.