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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
☒    QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2020
or
☐    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the transition period from            to            
Commission file number 001-33366
Cheniere Energy Partners, L.P.
(Exact name of registrant as specified in its charter)
Delaware 20-5913059
(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)
700 Milam Street, Suite 1900
Houston, Texas 77002
(Address of principal executive offices) (Zip Code)
(713) 375-5000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act: 
Title of each class Trading Symbol Name of each exchange on which registered
Common Units Representing Limited Partner Interests CQP NYSE American
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes ☒   No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  Yes  ☒   No  ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ☒ Accelerated filer ☐
Non-accelerated filer ☐ Smaller reporting company ☐
Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes ☐    No ☒
As of October 30, 2020, the registrant had 484,019,623 common units outstanding.


CHENIERE ENERGY PARTNERS, L.P.
TABLE OF CONTENTS

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i


DEFINITIONS
As used in this quarterly report, the terms listed below have the following meanings: 

Common Industry and Other Terms
Bcf billion cubic feet
Bcf/d billion cubic feet per day
Bcf/yr billion cubic feet per year
Bcfe billion cubic feet equivalent
DOE U.S. Department of Energy
EPC engineering, procurement and construction
FERC Federal Energy Regulatory Commission
FTA countries countries with which the United States has a free trade agreement providing for national treatment for trade in natural gas
GAAP generally accepted accounting principles in the United States
Henry Hub the final settlement price (in USD per MMBtu) for the New York Mercantile Exchange’s Henry Hub natural gas futures contract for the month in which a relevant cargo’s delivery window is scheduled to begin
LIBOR London Interbank Offered Rate
LNG liquefied natural gas, a product of natural gas that, through a refrigeration process, has been cooled to a liquid state, which occupies a volume that is approximately 1/600th of its gaseous state
MMBtu million British thermal units, an energy unit
mtpa million tonnes per annum
non-FTA countries countries with which the United States does not have a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted
SEC U.S. Securities and Exchange Commission
SPA LNG sale and purchase agreement
TBtu trillion British thermal units, an energy unit
Train an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
TUA terminal use agreement


1


Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of September 30, 2020, including our ownership of certain subsidiaries, and the references to these entities used in this quarterly report:
CQP-20200930_G1.JPG
Unless the context requires otherwise, references to “Cheniere Partners,” “the Partnership,” “we,” “us” and “our” refer to Cheniere Energy Partners, L.P. and its consolidated subsidiaries, including SPLNG, SPL and CTPL. 

2

PART I.    FINANCIAL INFORMATION 
ITEM 1.     CONSOLIDATED FINANCIAL STATEMENTS 
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in millions, except unit data)

September 30, December 31,
2020 2019
ASSETS (unaudited)  
Current assets    
Cash and cash equivalents $ 1,254  $ 1,781 
Restricted cash 157  181 
Accounts and other receivables, net 204  297 
Accounts receivable—affiliate 82  105 
Advances to affiliate 120  158 
Inventory 113  116 
Derivative assets 14  17 
Other current assets 117  51 
Other current assets—affiliate —  1 
Total current assets 2,061  2,707 
Property, plant and equipment, net 16,666  16,368 
Operating lease assets, net 100  94 
Debt issuance costs, net 18  15 
Non-current derivative assets 30  32 
Other non-current assets, net 155  168 
Total assets $ 19,030  $ 19,384 
LIABILITIES AND PARTNERS’ EQUITY    
Current liabilities
Accounts payable $ 17  $ 40 
Accrued liabilities 564  709 
Accrued liabilities—related party 2  — 
Due to affiliates 42  46 
Deferred revenue 179  155 
Deferred revenue—affiliate —  1 
Current operating lease liabilities 7  6 
Derivative liabilities 31  9 
Total current liabilities 842  966 
Long-term debt, net 17,573  17,579 
Non-current operating lease liabilities 92  87 
Non-current derivative liabilities 25  16 
Other non-current liabilities 2  1 
Other non-current liabilities—affiliate 18  20 
Partners’ equity
Common unitholders’ interest (484.0 million and 348.6 million units issued and outstanding at September 30, 2020 and December 31, 2019, respectively)
627  1,792 
Subordinated unitholders’ interest (zero and 135.4 million units issued and outstanding at September 30, 2020 and December 31, 2019, respectively)
—  (996)
General partner’s interest (2% interest with 9.9 million units issued and outstanding at September 30, 2020 and December 31, 2019)
(149) (81)
Total partners’ equity 478  715 
Total liabilities and partners’ equity $ 19,030  $ 19,384 

The accompanying notes are an integral part of these consolidated financial statements.

3

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per unit data)
(unaudited)
Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
Revenues
LNG revenues $ 807  $ 1,140  $ 3,588  $ 3,678 
LNG revenues—affiliate 103  257  352  1,017 
Regasification revenues 67  66  202  199 
Other revenues 5  13  28  36 
Total revenues 982  1,476  4,170  4,930 
Operating costs and expenses  
Cost of sales (excluding items shown separately below) 454  742  1,551  2,501 
Cost of sales—affiliate 33  6  38  6 
Operating and maintenance expense 146  172  463  472 
Operating and maintenance expense—affiliate 34  34  115  100 
General and administrative expense 2  3  12  9 
General and administrative expense—affiliate 24  34  73  82 
Depreciation and amortization expense 137  138  413  390 
Impairment expense and loss on disposal of assets —  1  5  6 
Total operating costs and expenses 830  1,130  2,670  3,566 
Income from operations 152  346  1,500  1,364 
Other income (expense)  
Interest expense, net of capitalized interest (221) (231) (691) (648)
Loss on modification or extinguishment of debt —  (13) (43) (13)
Other income, net 2  8  8  24 
Total other expense (219) (236) (726) (637)
Net income (loss) $ (67) $ 110  $ 774  $ 727 
Basic and diluted net income (loss) per common unit $ (0.08) $ 0.19  $ 1.55  $ 1.38 
Weighted average number of common units outstanding used for basic and diluted net income (loss) per common unit calculation 414.8  348.6  370.9  348.6 

The accompanying notes are an integral part of these consolidated financial statements.

4

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY
(in millions)
(unaudited)
Three and Nine Months Ended September 30, 2020
Common Unitholders’ Interest Subordinated Unitholder’s Interest General Partner’s Interest Total Partners’ Equity
Units Amount Units Amount Units Amount
Balance at December 31, 2019 348.6  $ 1,792  135.4  $ (996) 9.9  $ (81) $ 715 
Net income —  307  —  119  —  9  435 
Distributions
Common units, $0.63/unit
—  (220) —  —  —  —  (220)
Subordinated units, $0.63/unit
—  —  —  (85) —  —  (85)
General partner units —  —  —  —  —  (25) (25)
Balance at March 31, 2020 348.6  1,879  135.4  (962) 9.9  (97) 820 
Net income —  287  —  111  —  8  406 
Distributions
Common units, $0.64/unit
—  (223) —  —  —  —  (223)
Subordinated units, $0.64/unit
—  —  —  (86) —  —  (86)
General partner units —  —  —  —  —  (29) (29)
Balance at June 30, 2020 348.6  1,943  135.4  (937) 9.9  (118) 888 
Net income —  (65) —  (1) —  (1) (67)
Conversion of subordinated units into common units 135.4  (1,026) (135.4) 1,026  —  —  — 
Distributions
Common units, $0.645/unit
—  (225) —  —  —  —  (225)
Subordinated units, $0.645/unit
—  —  —  (88) —  —  (88)
General partner units —  —  —  —  —  (30) (30)
Balance at September 30, 2020 484.0  $ 627  —  $ —  9.9  $ (149) $ 478 

The accompanying notes are an integral part of these consolidated financial statements.

5

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY—CONTINUED
(in millions)
(unaudited)
Three and Nine Months Ended September 30, 2019
Common Unitholders’ Interest Subordinated Unitholder’s Interest General Partner’s Interest Total Partners’ Equity
Units Amount Units Amount Units Amount
Balance at December 31, 2018 348.6  $ 1,806  135.4  $ (990) 9.9  $ (16) $ 800 
Net income —  272  —  105  —  8  385 
Distributions
Common units, $0.59/unit
—  (206) —  —  —  —  (206)
Subordinated units, $0.59/unit
—  —  —  (80) —  —  (80)
General partner units —  —  —  —  —  (18) (18)
Balance at March 31, 2019 348.6  1,872  135.4  (965) 9.9  (26) 881 
Net income —  164  —  64  —  4  232 
Distributions
Common units, $0.60/unit
—  (209) —  —  —  —  (209)
Subordinated units, $0.60/unit
—  —  —  (81) —  —  (81)
General partner units —  —  —  —  —  (22) (22)
Balance at June 30, 2019 348.6  1,827  135.4  (982) 9.9  (44) 801 
Net income —  77  —  30  —  3  110 
Distributions
Common units, $0.61/unit
—  (212) —  —  —  —  (212)
Subordinated units, $0.61/unit
—  —  —  (83) —  —  (83)
General partner units —  —  —  —  —  (24) (24)
Balance at September 30, 2019 348.6  $ 1,692  135.4  $ (1,035) 9.9  $ (65) $ 592 


The accompanying notes are an integral part of these consolidated financial statements.

6

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
(unaudited)
  Nine Months Ended September 30,
2020 2019
Cash flows from operating activities    
Net income $ 774  $ 727 
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense 413  390 
Amortization of debt issuance costs, premium and discount 24  23 
Loss on modification or extinguishment of debt 43  13 
Total losses (gains) on derivatives, net 38  (30)
Net cash provided by (used for) settlement of derivative instruments (2) 11 
Impairment expense and loss on disposal of assets 5  6 
Other 10  8 
Changes in operating assets and liabilities:
Accounts and other receivables, net 93  36 
Accounts receivable—affiliate 23  47 
Advances to affiliate 31  (47)
Inventory 2  (3)
Accounts payable and accrued liabilities (96) (209)
Accrued liabilities—related party 2  — 
Due to affiliates (3) (3)
Deferred revenue 24  54 
Other, net (45) (42)
Other, net—affiliate (3) (4)
Net cash provided by operating activities 1,333  977 
Cash flows from investing activities    
Property, plant and equipment, net (795) (1,156)
Other —  (1)
Net cash used in investing activities (795) (1,157)
Cash flows from financing activities    
Proceeds from issuances of debt 1,995  2,230 
Repayments of debt (2,000) (730)
Debt issuance and other financing costs (34) (33)
Debt extinguishment costs (39) (4)
Distributions to owners (1,011) (935)
Other —  3 
Net cash provided by (used in) financing activities (1,089) 531 
Net increase (decrease) in cash, cash equivalents and restricted cash (551) 351 
Cash, cash equivalents and restricted cash—beginning of period 1,962  1,541 
Cash, cash equivalents and restricted cash—end of period $ 1,411  $ 1,892 

Balances per Consolidated Balance Sheet:
September 30,
2020
Cash and cash equivalents $ 1,254 
Restricted cash 157 
Total cash, cash equivalents and restricted cash $ 1,411 


The accompanying notes are an integral part of these consolidated financial statements.

7

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)



NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION

The Sabine Pass LNG terminal is located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. Through our subsidiary, SPL, we are currently operating five natural gas liquefaction Trains and are constructing one additional Train for a total production capacity of approximately 30 mtpa of LNG (the “Liquefaction Project”) at the Sabine Pass LNG terminal. Through our subsidiary, SPLNG, we own and operate regasification facilities at the Sabine Pass LNG terminal, which includes pre-existing infrastructure of five LNG storage tanks, two marine berths and vaporizers and an additional marine berth that is under construction. We also own a 94-mile pipeline through our subsidiary, CTPL, that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines (the “Creole Trail Pipeline”).

Basis of Presentation

The accompanying unaudited Consolidated Financial Statements of Cheniere Partners have been prepared in accordance with GAAP for interim financial information and with Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements and should be read in conjunction with the Consolidated Financial Statements and accompanying notes included in our annual report on Form 10-K for the fiscal year ended December 31, 2019.

Results of operations for the three and nine months ended September 30, 2020 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2020.

We are not subject to either federal or state income tax, as our partners are taxed individually on their allocable share of our taxable income.

Recent Accounting Standards

In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. This guidance primarily provides temporary optional expedients which simplify the accounting for contract modifications to existing debt agreements expected to arise from the market transition from LIBOR to alternative reference rates. The optional expedients were available to be used upon issuance of this guidance but we have not yet applied the guidance because we have not yet modified any of our existing contracts for reference rate reform. Once we apply an optional expedient to a modified contract and adopt this standard, the guidance will be applied to all subsequent applicable contract modifications until December 31, 2022, at which time the optional expedients are no longer available.

NOTE 2—UNITHOLDERS’ EQUITY
 
The common units represent limited partner interests in us. The holders of the units are entitled to participate in partnership distributions and exercise the rights and privileges available to limited partners under our partnership agreement. Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement). Generally, our available cash is our cash on hand at the end of a quarter less the amount of any reserves established by our general partner. All distributions paid to date have been made from accumulated operating surplus as defined in the partnership agreement.

In July 2020, the board of directors of our general partner confirmed and approved that, following the distribution with respect to the three months ended June 30, 2020, the financial tests required for conversion of our subordinated units had been met under the terms of the partnership agreement. Accordingly, effective August 17, 2020, the first business day following the payment of the distribution, all of our subordinated units were automatically converted into common units on a one-for-one basis and the subordination period was terminated.

Although common unitholders are not obligated to fund losses of the Partnership, its capital account, which would be considered in allocating the net assets of the Partnership were it to be liquidated, continues to share in losses.

8

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
The general partner interest is entitled to at least 2% of all distributions made by us. In addition, the general partner holds incentive distribution rights (“IDRs”), which allow the general partner to receive a higher percentage of quarterly distributions of available cash from operating surplus after the initial quarterly distributions have been achieved and as additional target levels are met, but may transfer these rights separately from its general partner interest. The higher percentages range from 15% to 50%, inclusive of the general partner interest.
 
As of September 30, 2020, Cheniere held 48.6% limited partner and 2% general partner interest in us, BX CQP Target Holdco L.L.C. (“BX CQP Target Holdco”) and other affiliates of The Blackstone Group Inc. (“Blackstone”) and Brookfield Asset Management Inc. (“Brookfield”) held 41.9% interest in us and the public held 7.5% interest in us. BX CQP Target Holdco’s equity interests are 50.01% owned by BIP Chinook Holdco L.L.C., an affiliate of Blackstone and 49.99% owned by BIF IV Cypress Aggregator (Delaware) LLC, an affiliate of Brookfield. The ownership of BX CQP Target Holdco, Blackstone and Brookfield are based on their most recent filings with the SEC.

NOTE 3—RESTRICTED CASH
 
Restricted cash consists of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. As of September 30, 2020 and December 31, 2019, we had $157 million and $181 million of current restricted cash, respectively.

Pursuant to the accounts agreement entered into with the collateral trustee for the benefit of SPL’s debt holders, SPL is required to deposit all cash received into reserve accounts controlled by the collateral trustee.  The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Project and other restricted payments.

NOTE 4—ACCOUNTS AND OTHER RECEIVABLES

As of September 30, 2020 and December 31, 2019, accounts and other receivables, net consisted of the following (in millions):
September 30, December 31,
2020 2019
SPL trade receivable $ 175  $ 283 
Other accounts receivable 29  14 
Total accounts and other receivables, net $ 204  $ 297 

NOTE 5—INVENTORY

As of September 30, 2020 and December 31, 2019, inventory consisted of the following (in millions):
September 30, December 31,
2020 2019
Natural gas $ 13  $ 9 
LNG 18  27 
Materials and other 82  80 
Total inventory $ 113  $ 116 

9

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
NOTE 6—PROPERTY, PLANT AND EQUIPMENT
 
As of September 30, 2020 and December 31, 2019, property, plant and equipment, net consisted of the following (in millions):
September 30, December 31,
2020 2019
LNG terminal costs    
LNG terminal and interconnecting pipeline facilities $ 16,873  $ 16,894 
LNG terminal construction-in-process 2,001  1,275 
Accumulated depreciation (2,213) (1,807)
Total LNG terminal costs, net 16,661  16,362 
Fixed assets    
Fixed assets 28  27 
Accumulated depreciation (23) (21)
Total fixed assets, net 5  6 
Property, plant and equipment, net $ 16,666  $ 16,368 
The following table shows depreciation expense and offsets to LNG terminal costs during the three and nine months ended September 30, 2020 and 2019 (in millions):
Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
Depreciation expense $ 135  $ 136  $ 409  $ 386 
Offsets to LNG terminal costs (1) —  —  —  48
(1)    We realize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Project during the testing phase for its construction.

NOTE 7—DERIVATIVE INSTRUMENTS

We have entered into commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project (“Physical Liquefaction Supply Derivatives”) and associated economic hedges (collectively, the “Liquefaction Supply Derivatives”).

We recognize our derivative instruments as either assets or liabilities and measure those instruments at fair value. None of our derivative instruments are designated as cash flow or fair value hedging instruments, and changes in fair value are recorded within our Consolidated Statements of Operations to the extent not utilized for the commissioning process.

The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of September 30, 2020 and December 31, 2019, which are classified as derivative assets, non-current derivative assets, derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets (in millions).
Fair Value Measurements as of
September 30, 2020 December 31, 2019
Quoted Prices in Active Markets
(Level 1) 		Significant Other Observable Inputs
(Level 2) 		Significant Unobservable Inputs
(Level 3) 		Total Quoted Prices in Active Markets
(Level 1) 		Significant Other Observable Inputs
(Level 2) 		Significant Unobservable Inputs
(Level 3) 		Total
Liquefaction Supply Derivatives asset (liability) $ (7) $ (5) $ —  $ (12) $ 3  $ (3) $ 24  $ 24 

We value our Liquefaction Supply Derivatives using a market-based approach incorporating present value techniques, as needed, using observable commodity price curves, when available, and other relevant data.

10

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
The fair value of our Physical Liquefaction Supply Derivatives is predominantly driven by observable and unobservable market commodity prices and, as applicable to our natural gas supply contracts, our assessment of the associated events deriving fair value, including evaluating whether the respective market is available as pipeline infrastructure is developed. The fair value of our Physical Liquefaction Supply Derivatives incorporates risk premiums related to the satisfaction of conditions precedent, such as completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow. As of September 30, 2020 and December 31, 2019, some of our Physical Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure was under development to accommodate marketable physical gas flow.

We include a portion of our Physical Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks, such as future prices of energy units for unobservable periods, liquidity, volatility and contract duration.

The Level 3 fair value measurements of natural gas positions within our Physical Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas prices. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of September 30, 2020:
Net Fair Value Asset
(in millions) 		Valuation Approach Significant Unobservable Input Range of Significant Unobservable Inputs / Weighted Average (1)
Physical Liquefaction Supply Derivatives $— Market approach incorporating present value techniques Henry Hub basis spread
$(0.527) - $0.055 / $0.001
(1)    Unobservable inputs were weighted by the relative fair value of the instruments.

Increases or decreases in basis, in isolation, would decrease or increase, respectively, the fair value of our Physical Liquefaction Supply Derivatives.

The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the three and nine months ended September 30, 2020 and 2019 (in millions):
Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
Balance, beginning of period $ 51  $ 34  $ 24  $ (25)
Realized and mark-to-market gains (losses):
Included in cost of sales (47) (42) (22) (22)
Purchases and settlements:
Purchases 5  (1) 4  (4)
Settlements (8) 1  (6) 43 
Transfers into Level 3, net (1) (1) —  —  — 
Balance, end of period $ —  $ (8) $ —  $ (8)
Change in unrealized losses relating to instruments still held at end of period $ (47) $ (42) $ (22) $ (22)
(1)    Transferred into Level 3 as a result of unobservable market, or out of Level 3 as a result of observable market for the underlying natural gas purchase agreements.

Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis, as all counterparty derivative contracts provide for the unconditional right of set-off in the event of default. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances when our derivative instruments are in an asset position. Additionally, counterparties are at risk that we will be unable to meet our commitments in instances where our derivative instruments are in a liability position. We incorporate both our own nonperformance risk and the respective counterparty’s nonperformance risk in fair value measurements. In adjusting the fair value of our derivative contracts for the effect of nonperformance risk, we have considered the impact of any applicable credit enhancements, such as collateral postings, set-off rights and guarantees.
11

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)

Liquefaction Supply Derivatives

SPL has entered into primarily index-based physical natural gas supply contracts and associated economic hedges to purchase natural gas for the commissioning and operation of the Liquefaction Project. The remaining terms of the physical natural gas supply contracts range up to 10 years, some of which commence upon the satisfaction of certain events or states of affairs.

The notional natural gas position of our Liquefaction Supply Derivatives was approximately 3,207 TBtu and 3,663 TBtu as of September 30, 2020 and December 31, 2019, respectively, of which 91 TBtu and zero TBtu, respectively, were for a natural gas supply contract that SPL has with a related party.
The following table shows the fair value and location of our Liquefaction Supply Derivatives on our Consolidated Balance Sheets (in millions):
Fair Value Measurements as of (1)
Consolidated Balance Sheets Location September 30, 2020 December 31, 2019
Derivative assets $ 14  $ 17 
Non-current derivative assets 30  32 
Total derivative assets 44  49 
Derivative liabilities (31) (9)
Non-current derivative liabilities (25) (16)
Total derivative liabilities (56) (25)
Derivative asset (liability), net $ (12) $ 24 
(1)    Does not include collateral posted with counterparties by us of $12 million and $2 million for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of September 30, 2020 and December 31, 2019, respectively. Includes a natural gas supply contract that SPL has with a related party, which had a fair value of zero as of September 30, 2020.

The following table shows the changes in the fair value, settlements and location of our Liquefaction Supply Derivatives recorded on our Consolidated Statements of Operations during the three and nine months ended September 30, 2020 and 2019 (in millions):
 Consolidated Statements of Operations Location (1) Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
Liquefaction Supply Derivatives gain LNG revenues $ 7  $ 1  $ 3  $ 2 
Liquefaction Supply Derivatives gain (loss) Cost of sales (74) (55) (41) 28 
(1)    Does not include the realized value associated with derivative instruments that settle through physical delivery. Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.

12

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
Consolidated Balance Sheets Presentation

Our derivative instruments are presented on a net basis on our Consolidated Balance Sheets as described above. The following table shows the fair value of our derivatives outstanding on a gross and net basis (in millions):
Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)
As of September 30, 2020
Liquefaction Supply Derivatives $ 47  $ (3) $ 44 
Liquefaction Supply Derivatives (59) 3  (56)
As of December 31, 2019
Liquefaction Supply Derivatives $ 51  $ (2) $ 49 
Liquefaction Supply Derivatives (27) 2  (25)
NOTE 8—OTHER NON-CURRENT ASSETS

As of September 30, 2020 and December 31, 2019, other non-current assets, net consisted of the following (in millions):
September 30, December 31,
2020 2019
Advances made to municipalities for water system enhancements $ 85  $ 87 
Advances and other asset conveyances to third parties to support LNG terminal 34  35 
Tax-related prepayments and receivables 17  17 
Information technology service prepayments 6  6 
Advances made under EPC and non-EPC contracts 4  15 
Other 9  8 
Total other non-current assets, net $ 155  $ 168 

NOTE 9—ACCRUED LIABILITIES
 
As of September 30, 2020 and December 31, 2019, accrued liabilities consisted of the following (in millions):
September 30, December 31,
2020 2019
Interest costs and related debt fees $ 264  $ 241 
Accrued natural gas purchases 212  325 
LNG terminal and related pipeline costs 62  135 
Other accrued liabilities 26  8 
Total accrued liabilities $ 564  $ 709 

13

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
NOTE 10—DEBT
 
As of September 30, 2020 and December 31, 2019, our debt consisted of the following (in millions):
September 30, December 31,
2020 2019
Long-term debt:
SPL — 4.200% to 6.25% senior secured notes due through 2037 and working capital facility (“2020 SPL Working Capital Facility”)
$ 13,650  $ 13,650 
Cheniere Partners — 4.500% to 5.625% senior notes due through 2029 and credit facilities (“2019 CQP Credit Facilities”)
4,100  4,100 
Unamortized premium, discount and debt issuance costs, net (177) (171)
Total long-term debt, net 17,573  17,579 
Current debt:
$1.2 billion Amended and Restated SPL Working Capital Facility executed in 2015 (“2015 SPL Working Capital Facility”)
—  — 
Total debt, net $ 17,573  $ 17,579 

Issuances

The following table shows the issuances of debt during the nine months ended September 30, 2020:
Maturity Date Interest Rate Principal Amount Issued (in millions)
Three Months Ended June 30, 2020
SPL — 4.500% Senior Secured Notes due 2030 (the “2030 SPL Senior Notes”) (1)
May 15, 2030 4.500% $ 2,000 
Nine Months Ended September 30, 2020 total $ 2,000 
(1)Proceeds of the 2030 SPL Senior Notes, along with available cash, were used to redeem all of SPL’s outstanding 5.625% Senior Secured Notes due 2021 (the “2021 SPL Senior Notes”), resulting in the recognition of debt extinguishment costs of $43 million for the nine months ended September 30, 2020 relating to the payment of early redemption fees and write off of unamortized debt premium and issuance costs.

Credit Facilities

Below is a summary of our credit facilities outstanding as of September 30, 2020 (in millions):
2020 SPL Working Capital Facility (1) 2019 CQP Credit Facilities
Original facility size $ 1,200  $ 1,500 
Less:
Outstanding balance —  — 
Commitments prepaid or terminated —  750 
Letters of credit issued 413  — 
Available commitment $ 787  $ 750 
Interest rate on available balance
LIBOR plus 1.125% - 1.750% or base rate plus 0.125% - 0.750%
LIBOR plus 1.25% - 2.125% or base rate plus 0.25% - 1.125%
Weighted average interest rate of outstanding balance n/a n/a
Maturity date March 19, 2025 May 29, 2024
(1)The 2020 SPL Working Capital Facility contains customary conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. SPL pays a commitment fee equal to an annual rate of 0.1% to 0.3% (depending on the then-current rating of SPL), which accrues on the daily amount of the total commitment less the
14

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
sum of (1) the outstanding principal amount of loans, (2) letters of credit issued and (3) the outstanding principal amount of swing line loans.

Restrictive Debt Covenants

As of September 30, 2020, we and SPL were in compliance with all covenants related to our respective debt agreements.

Interest Expense

Total interest expense, net of capitalized interest consisted of the following (in millions):
Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
Total interest cost $ 246  $ 246  $ 759  $ 718 
Capitalized interest (25) (15) (68) (70)
Total interest expense, net of capitalized interest $ 221  $ 231  $ 691  $ 648 

Fair Value Disclosures

The following table shows the carrying amount and estimated fair value of our debt (in millions):
September 30, 2020 December 31, 2019
  Carrying
Amount 		Estimated
Fair Value 		Carrying
Amount 		Estimated
Fair Value
Senior notes — Level 2 (1) $ 16,950  $ 18,666  $ 16,950  $ 18,320 
Senior notes — Level 3 (2) 800  946 800  934 
Credit facilities (3) —  —  —  — 
(1)The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.
(2)The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market.
(3)The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty. 

NOTE 11—REVENUES FROM CONTRACTS WITH CUSTOMERS

The following table represents a disaggregation of revenue earned from contracts with customers during the three and nine months ended September 30, 2020 and 2019 (in millions):
Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
LNG revenues (1) $ 800  $ 1,139  $ 3,585  $ 3,676 
LNG revenues—affiliate 103  257  352  1,017 
Regasification revenues 67  66  202  199 
Other revenues 5  13  28  36 
Total revenues from customers 975  1,475  4,167  4,928 
Net derivative gains (2) 7  1  3  2 
Total revenues $ 982  $ 1,476  $ 4,170  $ 4,930 
(1)LNG revenues include revenues for LNG cargoes in which our customers exercised their contractual right to not take delivery but remained obligated to pay fixed fees irrespective of such election. LNG revenues during the three and nine months ended September 30, 2020 included $109 million and $513 million, respectively, in revenues associated with LNG cargoes for which customers have notified us that they will not take delivery, of which $21 million would have otherwise been recognized subsequent to September 30, 2020, if the cargoes were lifted pursuant to the delivery
15

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
schedules with the customers. LNG revenues during the three months ended September 30, 2020 excluded $244 million in prior period cancellations that would have otherwise been recognized during the quarter if the cargoes were lifted pursuant to the delivery schedules with the customers. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied.
(2)See Note 7—Derivative Instruments for additional information about our derivatives.

Deferred Revenue Reconciliation

The following table reflects the changes in our contract liabilities, which we classify as deferred revenue on our Consolidated Balance Sheets (in millions):
Nine Months Ended September 30, 2020
Deferred revenues, beginning of period $ 155 
Cash received but not yet recognized 179 
Revenue recognized from prior period deferral (155)
Deferred revenues, end of period $ 179 

Transaction Price Allocated to Future Performance Obligations

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of September 30, 2020 and December 31, 2019:
September 30, 2020 December 31, 2019
Unsatisfied
Transaction Price
(in billions) 		Weighted Average Recognition Timing (years) (1) Unsatisfied
Transaction Price
(in billions) 		Weighted Average Recognition Timing (years) (1)
LNG revenues $ 52.9  9 $ 55.0  10
Regasification revenues 2.2  5 2.4  5
Total revenues $ 55.1  $ 57.4 
(1)    The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.
We have elected the following exemptions which omit certain potential future sources of revenue from the table above:
(1)We omit from the table above all performance obligations that are part of a contract that has an original expected delivery duration of one year or less.
(2)The table above excludes substantially all variable consideration under our SPAs and TUAs. We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. We have not included such variable consideration in the transaction price to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt. Approximately 39% and 49% of our LNG revenues from contracts included in the table above during the three months ended September 30, 2020 and 2019, respectively, and approximately 37% and 53% of our LNG revenues from contracts included in the table above during the nine months ended September 30, 2020 and 2019, respectively, were related to variable consideration received from customers. During each of the three and nine months ended September 30, 2020 and 2019, approximately 3% of our regasification revenues were related to variable consideration received from customers.
16

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)

We may enter into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching a final investment decision on a certain liquefaction Train, obtaining financing or achieving substantial completion of a Train and any related facilities. These contracts are considered completed contracts for revenue recognition purposes and are included in the transaction price above when the conditions are considered probable of being met.

NOTE 12—RELATED PARTY TRANSACTIONS
 
Below is a summary of our related party transactions as reported on our Consolidated Statements of Operations for the three and nine months ended September 30, 2020 and 2019 (in millions):
Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
LNG revenues—affiliate
Cheniere Marketing Agreements $ 87  $ 255  $ 328  $ 1,015 
Contracts for Sale and Purchase of Natural Gas and LNG 16  2  24  2 
Total LNG revenues—affiliate 103  257  352  1,017 
Cost of sales—affiliate
Cheniere Marketing Agreements 32  —  32  — 
Contracts for Sale and Purchase of Natural Gas and LNG 1  6  6  6 
33  6  38  6 
Operating and maintenance expense—affiliate
Services Agreements 34  34  115  100 
General and administrative expense—affiliate
Services Agreements 24  34  73  82 

As of September 30, 2020 and December 31, 2019, we had $82 million and $105 million, respectively, of accounts receivable—affiliate, under the agreements described below.

Cheniere Marketing Agreements

Cheniere Marketing SPA

Cheniere Marketing has an SPA (“Base SPA”) with SPL to purchase, at Cheniere Marketing’s option, any LNG produced by SPL in excess of that required for other customers at a price of 115% of Henry Hub plus $3.00 per MMBtu of LNG.

In May 2019, SPL and Cheniere Marketing entered into an amendment to the Base SPA to remove certain conditions related to the sale of LNG from Trains 5 and 6 of the Liquefaction Project and provide that cargoes rejected by Cheniere Marketing under the Base SPA can be sold by SPL to Cheniere Marketing at a contract price equal to a portion of the estimated net profits from the sale of such cargo.

Cheniere Marketing Master SPA

SPL has an agreement with Cheniere Marketing that allows the parties to sell and purchase LNG with each other by executing and delivering confirmations under this agreement. SPL executed a confirmation with Cheniere Marketing that obligated Cheniere Marketing in certain circumstances to buy LNG cargoes produced during the period while Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) had control of, and was commissioning, Train 5 of the Liquefaction Project.

17

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
Cheniere Marketing Letter Agreements

In December 2019, SPL and Cheniere Marketing entered into a letter agreement for the sale of up to 43 cargoes scheduled for delivery in 2020 at a price of 115% of Henry Hub plus $1.67 per MMBtu.

Facility Swap Agreement

In August 2020, SPL entered into an arrangement with subsidiaries of Cheniere to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers in the event operational conditions impact operations at either the Sabine Pass or Corpus Christi liquefaction facilities. The purchase price for such cargoes would be (i) 115% of the applicable natural gas feedstock purchase price or (ii) a free-on-board U.S. Gulf Coast LNG market price, whichever is greater.

Natural Gas Transportation and Storage Agreements
SPL is party to various natural gas transportation and storage agreements and CTPL is party to an operational balancing agreement with a related party in the ordinary course of business for the operation of the Liquefaction Project, with initial primary terms of up to 10 years with extension rights. We recorded accrued liabilities—related party of $2 million as of September 30, 2020 related to these agreements.

Services Agreements

As of September 30, 2020 and December 31, 2019, we had $120 million and $158 million of advances to affiliates, respectively, under the services agreements described below. The non-reimbursement amounts incurred under these agreements are recorded in general and administrative expense—affiliate.

Cheniere Partners Services Agreement

We have a services agreement with Cheniere Terminals, a subsidiary of Cheniere, pursuant to which Cheniere Terminals is entitled to a quarterly non-accountable overhead reimbursement charge of $3 million (adjusted for inflation) for the provision of various general and administrative services for our benefit. In addition, Cheniere Terminals is entitled to reimbursement for all audit, tax, legal and finance fees incurred by Cheniere Terminals that are necessary to perform the services under the agreement.

Cheniere Investments Information Technology Services Agreement

Cheniere Investments has an information technology services agreement with Cheniere, pursuant to which Cheniere Investments’ subsidiaries receive certain information technology services. On a quarterly basis, the various entities receiving the benefit are invoiced by Cheniere Investments according to the cost allocation percentages set forth in the agreement. In addition, Cheniere is entitled to reimbursement for all costs incurred by Cheniere that are necessary to perform the services under the agreement.
SPLNG O&M Agreement

SPLNG has a long-term operation and maintenance agreement (the “SPLNG O&M Agreement”) with Cheniere Investments pursuant to which SPLNG receives all necessary services required to operate and maintain the Sabine Pass LNG receiving terminal. SPLNG pays a fixed monthly fee of $130,000 (indexed for inflation) under the SPLNG O&M Agreement and the cost of a bonus equal to 50% of the salary component of labor costs in certain circumstances to be agreed upon between SPLNG and Cheniere Investments at the beginning of each operating year. In addition, SPLNG is required to reimburse Cheniere Investments for its operating expenses, which consist primarily of labor expenses. Cheniere Investments provides the services required under the SPLNG O&M Agreement pursuant to a secondment agreement with a wholly owned subsidiary of Cheniere. All payments received by Cheniere Investments under the SPLNG O&M Agreement are required to be remitted to such subsidiary.
 
18

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
SPLNG MSA

SPLNG has a long-term management services agreement (the “SPLNG MSA”) with Cheniere Terminals, pursuant to which Cheniere Terminals manages the operation of the Sabine Pass LNG receiving terminal, excluding those matters provided for under the SPLNG O&M Agreement. SPLNG pays a monthly fixed fee of $520,000 (indexed for inflation) under the SPLNG MSA.

SPL O&M Agreement

SPL has an operation and maintenance agreement (the “SPL O&M Agreement”) with Cheniere Investments pursuant to which SPL receives all of the necessary services required to construct, operate and maintain the Liquefaction Project. Before each Train of the Liquefaction Project is operational, the services to be provided include, among other services, obtaining governmental approvals on behalf of SPL, preparing an operating plan for certain periods, obtaining insurance, preparing staffing plans and preparing status reports. After each Train is operational, the services include all necessary services required to operate and maintain the Train. Prior to the substantial completion of each Train of the Liquefaction Project, in addition to reimbursement of operating expenses, SPL is required to pay a monthly fee equal to 0.6% of the capital expenditures incurred in the previous month. After substantial completion of each Train, for services performed while the Train is operational, SPL will pay, in addition to the reimbursement of operating expenses, a fixed monthly fee of $83,333 (indexed for inflation) for services with respect to the Train. Cheniere Investments provides the services required under the SPL O&M Agreement pursuant to a secondment agreement with a wholly owned subsidiary of Cheniere. All payments received by Cheniere Investments under the SPL O&M Agreement are required to be remitted to such subsidiary.
SPL MSA

SPL has a management services agreement (the “SPL MSA”) with Cheniere Terminals pursuant to which Cheniere Terminals manages the construction and operation of the Liquefaction Project, excluding those matters provided for under the SPL O&M Agreement. The services include, among other services, exercising the day-to-day management of SPL’s affairs and business, managing SPL’s regulatory matters, managing bank and brokerage accounts and financial books and records of SPL’s business and operations, entering into financial derivatives on SPL’s behalf and providing contract administration services for all contracts associated with the Liquefaction Project. Prior to the substantial completion of each Train of the Liquefaction Project, SPL pays a monthly fee equal to 2.4% of the capital expenditures incurred in the previous month. After substantial completion of each Train, SPL will pay a fixed monthly fee of $541,667 (indexed for inflation) for services with respect to such Train.

CTPL O&M Agreement

CTPL has an amended long-term operation and maintenance agreement (the “CTPL O&M Agreement”) with Cheniere Investments pursuant to which CTPL receives all necessary services required to operate and maintain the Creole Trail Pipeline. CTPL is required to reimburse Cheniere Investments for its operating expenses, which consist primarily of labor expenses. Cheniere Investments provides the services required under the CTPL O&M Agreement pursuant to a secondment agreement with a wholly owned subsidiary of Cheniere. All payments received by Cheniere Investments under the CTPL O&M Agreement are required to be remitted to such subsidiary.
 
Natural Gas Supply Agreement

SPL is party to a natural gas supply agreement with a related party in the ordinary course of business, to obtain feed gas for the operation of the Liquefaction Project. The term of the agreement is for five years, which can commence no earlier than November 1, 2021 and no later than November 1, 2022, following the achievement of contractually-defined conditions precedent.

Agreement to Fund SPLNG’s Cooperative Endeavor Agreements
 
SPLNG has executed Cooperative Endeavor Agreements (“CEAs”) with various Cameron Parish, Louisiana taxing authorities that allowed them to collect certain annual property tax payments from SPLNG from 2007 through 2016. This initiative represented an aggregate commitment of $25 million over 10 years in order to aid in their reconstruction efforts
19

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
following Hurricane Rita. In exchange for SPLNG’s advance payments of annual ad valorem taxes, Cameron Parish may grant SPLNG a dollar-for-dollar credit against future ad valorem taxes to be levied against the Sabine Pass LNG terminal as early as 2019. Beginning in September 2007, SPLNG entered into various agreements with Cheniere Marketing, pursuant to which Cheniere Marketing would pay SPLNG additional TUA revenues equal to any and all amounts payable by SPLNG to the Cameron Parish taxing authorities under the CEAs. In exchange for such amounts received as TUA revenues from Cheniere Marketing, SPLNG will make payments to Cheniere Marketing equal to ad valorem tax levied on our LNG terminal in the year the Cameron Parish dollar-for-dollar credit is applied.

On a consolidated basis, these advance tax payments were recorded to other non-current assets, and payments from Cheniere Marketing that SPLNG utilized to make the ad valorem tax payments were recorded as obligations. We had $4 million and $2 million in due to affiliates and $18 million and $20 million of other non-current liabilities—affiliate resulting from these payments received from Cheniere Marketing as of September 30, 2020 and December 31, 2019, respectively.

Contracts for Sale and Purchase of Natural Gas and LNG
 
SPLNG is able to sell and purchase natural gas and LNG under agreements with Cheniere Marketing. Under these agreements, SPLNG purchases natural gas or LNG from Cheniere Marketing at a sales price equal to the actual purchase price paid by Cheniere Marketing to suppliers of the natural gas or LNG, plus any third-party costs incurred by Cheniere Marketing with respect to the receipt, purchase and delivery of natural gas or LNG to the Sabine Pass LNG terminal.

SPL has an agreement with CCL that allows them to sell and purchase natural gas from each other. Natural gas purchased under this agreement is initially recorded as inventory and then to cost of sales—affiliate upon its sale, except for purchases related to commissioning activities which are capitalized as LNG terminal construction-in-process. Natural gas sold under this agreement is recorded as LNG revenues—affiliate.

Terminal Marine Services Agreement

In connection with its tug boat lease, Tug Services entered into an agreement with Cheniere Terminals to provide its LNG cargo vessels with tug boat and marine services at the Sabine Pass LNG terminal. The agreement also provides that Tug Services shall contingently pay Cheniere Terminals a portion of its future revenues. Accordingly, Tug Services distributed $1 million and $2 million during the three months ended September 30, 2020 and 2019, respectively, and $4 million and $5 million during the nine months ended September 30, 2020 and 2019, respectively, to Cheniere Terminals, which is recognized as part of the distributions to our general partner interest holders on our Consolidated Statements of Partners’ Equity.

LNG Terminal Export Agreement

SPLNG and Cheniere Marketing have an LNG terminal export agreement that provides Cheniere Marketing the ability to export LNG from the Sabine Pass LNG terminal.  SPLNG did not record any revenues associated with this agreement during the three and nine months ended September 30, 2020 and 2019.

State Tax Sharing Agreements

SPLNG has a state tax sharing agreement with Cheniere.  Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which SPLNG and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, SPLNG will pay to Cheniere an amount equal to the state and local tax that SPLNG would be required to pay if its state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from SPLNG under this agreement; therefore, Cheniere has not demanded any such payments from SPLNG. The agreement is effective for tax returns due on or after January 1, 2008.

SPL has a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which SPL and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, SPL will pay to Cheniere an amount equal to the state and local tax that SPL would be required to pay if SPL’s state and local tax liability were calculated on a separate
20

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from SPL under this agreement; therefore, Cheniere has not demanded any such payments from SPL. The agreement is effective for tax returns due on or after August 2012.

CTPL has a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which CTPL and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, CTPL will pay to Cheniere an amount equal to the state and local tax that CTPL would be required to pay if CTPL’s state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from CTPL under this agreement; therefore, Cheniere has not demanded any such payments from CTPL. The agreement is effective for tax returns due on or after May 2013.

NOTE 13—NET INCOME (LOSS) PER COMMON UNIT
 
Net income (loss) per common unit for a given period is based on the distributions that will be made to the unitholders with respect to the period plus an allocation of undistributed net income (loss) based on provisions of the partnership agreement, divided by the weighted average number of common units outstanding. Distributions paid by us are presented on the Consolidated Statements of Partners’ Equity. On October 27, 2020, we declared a $0.650 distribution per common unit and the related distribution to our general partner and IDR holders to be paid on November 13, 2020 to unitholders of record as of November 6, 2020 for the period from July 1, 2020 to September 30, 2020.

The two-class method dictates that net income (loss) for a period be reduced by the amount of available cash that will be distributed with respect to that period and that any residual amount representing undistributed net income to be allocated to common unitholders and other participating unitholders to the extent that each unit may share in net income as if all of the net income for the period had been distributed in accordance with the partnership agreement. Undistributed income is allocated to participating securities based on the distribution waterfall for available cash specified in the partnership agreement. Undistributed losses (including those resulting from distributions in excess of net income) are allocated to common units and other participating securities on a pro rata basis based on provisions of the partnership agreement. Distributions are treated as distributed earnings in the computation of earnings per common unit even though cash distributions are not necessarily derived from current or prior period earnings.

The following table provides a reconciliation of net income (loss) and the allocation of net income (loss) to the common units, the subordinated units, the general partner units and IDRs for purposes of computing basic and diluted net income (loss) per unit (in millions, except per unit data).
21

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
  Limited Partner Units
  Total Common Units Subordinated Units General Partner Units IDR
Three Months Ended September 30, 2020
Net loss $ (67)
Declared distributions 346  315  —  6  25 
Assumed allocation of undistributed net loss (1) $ (413) (347) (58) (8) — 
Assumed allocation of net loss $ (32) $ (58) $ (2) $ 25 
Weighted average units outstanding 414.8  69.2 
Basic and diluted net loss per unit $ (0.08) $ (0.84)
Three Months Ended September 30, 2019
Net income $ 110 
Declared distributions 323  217  84  6  16 
Assumed allocation of undistributed net loss (1) $ (213) (151) (58) (4) — 
Assumed allocation of net income $ 66  $ 26  $ 2  $ 16 
Weighted average units outstanding 348.6  135.4 
Basic and diluted net income per unit $ 0.19  $ 0.19 
Nine Months Ended September 30, 2020
Net income $ 774 
Declared distributions 1,024  763  174  20  67 
Assumed allocation of undistributed net loss (1) $ (250) (188) (57) (5) — 
Assumed allocation of net income $ 575  $ 117  $ 15  $ 67 
Weighted average units outstanding 370.9  113.1 
Basic and diluted net income per unit $ 1.55  $ 1.03 
Nine Months Ended September 30, 2019
Net income $ 727 
Declared distributions 949  638  248  19  44 
Assumed allocation of undistributed net loss (1) $ (222) (157) (61) (4) — 
Assumed allocation of net income $ 481  $ 187  $ 15  $ 44 
Weighted average units outstanding 348.6  135.4 
Basic and diluted net income per unit $ 1.38  $ 1.38 
(1)Under our partnership agreement, the IDRs participate in net income only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in undistributed net income.


22

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
NOTE 14—CUSTOMER CONCENTRATION
  
The following table shows customers with revenues of 10% or greater of total revenues from external customers and customers with accounts receivable, net balances of 10% or greater of total accounts receivable, net from external customers:
Percentage of Total Revenues from External Customers Percentage of Accounts Receivable, Net from External Customers
Three Months Ended September 30, Nine Months Ended September 30, September 30, December 31,
2020 2019 2020 2019 2020 2019
Customer A * 24% 22% 28% 16% 21%
Customer B 14% 18% 15% 19% 20% 13%
Customer C 26% 22% 18% 20% 12% 22%
Customer D 22% 19% 18% 21% 33% 13%
Customer E * * * * — 13%
Customer F * * 12% * 11% 14%
* Less than 10%

NOTE 15—SUPPLEMENTAL CASH FLOW INFORMATION
 
The following table provides supplemental disclosure of cash flow information (in millions):
Nine Months Ended September 30,
2020 2019
Cash paid during the period for interest, net of amounts capitalized $ 636  $ 624 

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $223 million and $298 million as of September 30, 2020 and 2019, respectively.

23

ITEM 2.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Information Regarding Forward-Looking Statements
This quarterly report contains certain statements that are, or may be deemed to be, “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical or present facts or conditions, included herein or incorporated herein by reference are “forward-looking statements.” Included among “forward-looking statements” are, among other things:
•statements regarding our ability to pay distributions to our unitholders; 
•statements regarding our expected receipt of cash distributions from SPLNG, SPL or CTPL; 
•statements that we expect to commence or complete construction of our proposed LNG terminals, liquefaction facilities, pipeline facilities or other projects, or any expansions or portions thereof, by certain dates, or at all;
•statements regarding future levels of domestic and international natural gas production, supply or consumption or future levels of LNG imports into or exports from North America and other countries worldwide or purchases of natural gas, regardless of the source of such information, or the transportation or other infrastructure or demand for and prices related to natural gas, LNG or other hydrocarbon products;
•statements regarding any financing transactions or arrangements, or our ability to enter into such transactions;
•statements relating to the construction of our Trains, including statements concerning the engagement of any EPC contractor or other contractor and the anticipated terms and provisions of any agreement with any EPC or other contractor, and anticipated costs related thereto;
•statements regarding any SPA or other agreement to be entered into or performed substantially in the future, including any revenues anticipated to be received and the anticipated timing thereof, and statements regarding the amounts of total LNG regasification, natural gas liquefaction or storage capacities that are, or may become, subject to contracts;
•statements regarding counterparties to our commercial contracts, construction contracts, and other contracts;
•statements regarding our planned development and construction of additional Trains, including the financing of such Trains;
•statements that our Trains, when completed, will have certain characteristics, including amounts of liquefaction capacities;
•statements regarding our business strategy, our strengths, our business and operation plans or any other plans, forecasts, projections, or objectives, including anticipated revenues, capital expenditures, maintenance and operating costs and cash flows, any or all of which are subject to change;
•statements regarding legislative, governmental, regulatory, administrative or other public body actions, approvals, requirements, permits, applications, filings, investigations, proceedings or decisions;
•statements regarding the outbreak of COVID-19 and its impact on our business and operating results, including any customers not taking delivery of LNG cargoes, the ongoing credit worthiness of our contractual counterparties, any disruptions in our operations or construction of our Trains and the health and safety of Cheniere’s employees, and on our customers, the global economy and the demand for LNG; and
•any other statements that relate to non-historical or future information.
All of these types of statements, other than statements of historical or present facts or conditions, are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “achieve,” “anticipate,” “believe,” “contemplate,” “continue,” “estimate,” “expect,” “intend,” “plan,” “potential,” “predict,” “project,” “pursue,” “target,” the negative of such terms or other comparable terminology. The forward-looking statements contained in this quarterly report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe that such estimates are reasonable, they are inherently uncertain and involve
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a number of risks and uncertainties beyond our control. In addition, assumptions may prove to be inaccurate. We caution that the forward-looking statements contained in this quarterly report are not guarantees of future performance and that such statements may not be realized or the forward-looking statements or events may not occur. Actual results may differ materially from those anticipated or implied in forward-looking statements as a result of a variety of factors described in this quarterly report and in the other reports and other information that we file with the SEC, including those discussed under “Risk Factors” in our annual report on Form 10-K for the fiscal year ended December 31, 2019 and our quarterly report on Form 10-Q for the quarterly period ended March 31, 2020. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. These forward-looking statements speak only as of the date made, and other than as required by law, we undertake no obligation to update or revise any forward-looking statement or provide reasons why actual results may differ, whether as a result of new information, future events or otherwise.

Introduction
 
The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our Consolidated Financial Statements and the accompanying notes. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future. Our discussion and analysis includes the following subjects: 
•Overview of Business 
•Overview of Significant Events
•Impact of COVID-19 and Market Environment
•Liquidity and Capital Resources 
•Results of Operations 
•Off-Balance Sheet Arrangements 
•Summary of Critical Accounting Estimates
•Recent Accounting Standards
 
Overview of Business
 
We are a publicly traded Delaware limited partnership formed by Cheniere in 2006. We provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We aspire to conduct our business in a safe and responsible manner, delivering a reliable, competitive and integrated source of LNG to our customers.

The Sabine Pass LNG terminal is located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. Through our subsidiary, SPL, we are currently operating five natural gas liquefaction Trains and are constructing one additional Train for a total production capacity of approximately 30 mtpa of LNG (the “Liquefaction Project”) at the Sabine Pass LNG terminal, one of the largest LNG production facilities in the world. Through our subsidiary, SPLNG, we own and operate regasification facilities at the Sabine Pass LNG terminal, which includes pre-existing infrastructure of five LNG storage tanks with aggregate capacity of approximately 17 Bcfe, two existing marine berths and one under construction that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4 Bcf/d. We also own a 94-mile pipeline through our subsidiary, CTPL, that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines.

Overview of Significant Events

Our significant events since January 1, 2020 and through the filing date of this Form 10-Q include the following:  
Strategic
•In August 2020, SPL entered into an arrangement with subsidiaries of Cheniere to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers in the event operational conditions impact operations at either the Sabine Pass or Corpus Christi liquefaction facilities. The purchase price for such cargoes would be (i)
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115% of the applicable natural gas feedstock purchase price or (ii) a free-on-board U.S. Gulf Coast LNG market price, whichever is greater.
Operational
•As of October 31, 2020, more than 1,075 cumulative LNG cargoes totaling approximately 75 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.
Financial
•In July 2020, the board of directors of our general partner confirmed and approved that, following the distribution with respect to the three months ended June 30, 2020, the financial tests required for conversion of our subordinated units were met under the terms of our partnership agreement. Accordingly, effective August 17, 2020, the first business day following the payment of the distribution, all of our subordinated units were automatically converted into common units on a one-for-one basis and the subordination period was terminated.
•In May 2020, SPL issued an aggregate principal amount of $2.0 billion of 4.500% Senior Secured Notes due 2030 (the “2030 SPL Senior Notes”). Net proceeds of the offering, along with cash on hand, were used to redeem all of SPL’s outstanding 5.625% Senior Secured Notes due 2021 (the “2021 SPL Senior Notes”).
•In March 2020, SPL entered into a $1.2 billion Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement (the “2020 SPL Working Capital Facility”), which refinanced its previous working capital facility, reduced the interest rate and extended the maturity date to March 2025.

Impact of COVID-19 and Market Environment

The business environment in which we operate has been impacted by the recent downturn in the energy market as well as the outbreak of COVID-19 and its progression into a pandemic in March 2020. As a result of these developments, our growth estimates for LNG in 2020 have moderated from previous expectations. Annual LNG demand grew by approximately 13% in 2019 to approximately 360 mtpa. In a report published in the month of April 2020, IHS Markit projected LNG demand in 2020 to reach 363 mtpa, down from a pre-COVID-19 estimate of approximately 377 mtpa. This implies a year-over-year rate of growth of below 1% in 2020 compared to an implied pre-COVID-19 year-over-year growth estimate of approximately 5%. While worldwide demand increased by approximately 3% during the nine months ended September 30, 2020 compared to the comparable period of 2019, we continue to be cautiously optimistic on the outlook. Global economic indicators point to a start of a recovery in some parts of the world but risks from second waves of infections and re-instatement of lockdowns could exert bearish pressures on the market. LNG importers had to cope with strict virus containment measures throughout the first and second quarters of 2020, which negatively impacted gas and LNG demand and resulted in many buyers having to resort to extraordinary measures to manage LNG supply purchases and contractual commitments. Some of these measures included cargo deferrals and cancellations. As the market started to rebalance and storage inventories started to normalize, prices today have recovered from their second quarter lows. As an example, the Dutch Title Transfer Facility (“TTF”), a virtual trading point for natural gas in the Netherlands, settled October at $4.23/MMBtu, which is $3.09/MMBtu higher than the June 2020 settlement. The Japan Korea Marker (“JKM”), an LNG benchmark price assessment for spot physical cargoes delivered ex-ship into certain key markets in Asia, settled October at $4.31/MMBtu, which is $2.25/MMBtu higher than its July price posting. The number of LNG cargoes for which customers have notified us that they will not take delivery have reduced from this summer, a sign that the market is continuing to adjust and rebalance towards equilibrium. We do not expect these events to have a material adverse impact on our forecasted financial results for 2020, due to the highly contracted nature of our business and the fact that customers continue to be obligated to pay fixed fees for cargoes in relation to which they have exercised their contractual right to cancel. As such, during the three and nine months ended September 30, 2020, we recognized $109 million and $513 million, respectively, in revenues associated with LNG cargoes for which customers have notified us that they will not take delivery, of which $21 million would have otherwise been recognized subsequent to September 30, 2020, if the cargoes were lifted pursuant to the delivery schedules with the customers. LNG revenues during the three months ended September 30, 2020 excluded $244 million in prior period cancellations that would have otherwise been recognized during the quarter if the cargoes were lifted pursuant to the delivery schedules with the customers. We experienced decreased revenues during the three months ended September 30, 2020 because we recognized accelerated revenues associated with LNG cargoes that were scheduled for delivery during the current quarter in the prior quarter, when the customers notified us that they will not take delivery of such cargoes.
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In addition, in response to the COVID-19 pandemic, Cheniere has modified certain business and workforce practices to protect the safety and welfare of its employees who continue to work at its facilities and offices worldwide, as well as implemented certain mitigation efforts to ensure business continuity. In March 2020, Cheniere began consulting with a medical advisor, and implemented social distancing through revised shift schedules, work from home policies and designated remote work locations where appropriate, restricted non-essential business travel and began requiring self-screening for employees and contractors. In April 2020, Cheniere began providing temporary housing for its workforce for our facilities, implemented temperature testing, incorporated medical and social workers to support employees, enforced prior self-isolation and screening for temporary housing and implemented marine operations with zero contact during loading activities. These measures have resulted in increased costs. While response measures continue to evolve and in most cases have moderated or ceased, we expect Cheniere to incur incremental operating costs associated with business continuity and protection of its workforce until the risks associated with the pandemic diminish. We have incurred approximately $1 million and $36 million of such costs during the three and nine months ended September 30, 2020, respectively.

Liquidity and Capital Resources
 
The following table provides a summary of our liquidity position at September 30, 2020 and December 31, 2019 (in millions):
September 30, December 31,
2020 2019
Cash and cash equivalents $ 1,254  $ 1,781 
Restricted cash designated for the following purposes:
Liquefaction Project 157  181 
Available commitments under the following credit facilities:
$1.2 billion Amended and Restated SPL Working Capital Facility (“2015 SPL Working Capital Facility”) —  786 
2020 SPL Working Capital Facility 787  — 
CQP Credit Facilities executed in 2019 (“2019 CQP Credit Facilities”) 750  750 

CQP Senior Notes

The $1.5 billion of 5.250% Senior Notes due 2025 (the “2025 CQP Senior Notes”), $1.1 billion of 5.625% Senior Notes due 2026 (the “2026 CQP Senior Notes”) and $1.5 billion of 4.500% Senior Notes due 2029 (the “2029 CQP Senior Notes”) (collectively, the “CQP Senior Notes”), are jointly and severally guaranteed by each of our subsidiaries other than SPL and, subject to certain conditions governing its guarantee, Sabine Pass LP (each a “Guarantor” and collectively, the “CQP Guarantors”). The CQP Senior Notes are governed by the same base indenture (the “CQP Base Indenture”). The 2025 CQP Senior Notes are further governed by the First Supplemental Indenture, the 2026 CQP Senior Notes are further governed by the Second Supplemental Indenture and the 2029 CQP Senior Notes are further governed by the Third Supplemental Indenture. The indentures governing the CQP Senior Notes contain terms and events of default and certain covenants that, among other things, limit our ability and the CQP Guarantors’ ability to incur liens and sell assets, enter into transactions with affiliates, enter into sale-leaseback transactions and consolidate, merge or sell, lease or otherwise dispose of all or substantially all of the applicable entity’s properties or assets.

At any time prior to October 1, 2020 for the 2025 CQP Senior Notes, October 1, 2021 for the 2026 CQP Senior Notes and October 1, 2024 for the 2029 CQP Senior Notes, we may redeem all or a part of the applicable CQP Senior Notes at a redemption price equal to 100% of the aggregate principal amount of the CQP Senior Notes redeemed, plus the “applicable premium” set forth in the respective indentures governing the CQP Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. In addition, at any time prior to October 1, 2020 for the 2025 CQP Senior Notes, October 1, 2021 for the 2026 CQP Senior Notes and October 1, 2024 for the 2029 CQP Senior Notes, we may redeem up to 35% of the aggregate principal amount of the CQP Senior Notes with an amount of cash not greater than the net cash proceeds from certain equity offerings at a redemption price equal to 105.250% of the aggregate principal amount of the 2025 CQP Senior Notes, 105.625% of the aggregate principal amount of the 2026 CQP Senior Notes and 104.5% of the aggregate principal amount of the 2029 CQP Senior Notes redeemed, plus accrued and unpaid interest, if any, to the date of redemption. We also may at any time on or after October 1, 2020 through the maturity date of October 1, 2025 for the 2025 CQP Senior Notes, October 1, 2021 through the maturity date of October 1, 2026 for the 2026 CQP Senior Notes and October 1, 2024 through the maturity date of October 1,
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2029 for the 2029 CQP Senior Notes, redeem the CQP Senior Notes, in whole or in part, at the redemption prices set forth in the respective indentures governing the CQP Senior Notes.

The CQP Senior Notes are our senior obligations, ranking equally in right of payment with our other existing and future unsubordinated debt and senior to any of our future subordinated debt. In the event that the aggregate amount of our secured indebtedness and the secured indebtedness of the CQP Guarantors (other than the CQP Senior Notes or any other series of notes issued under the CQP Base Indenture) outstanding at any one time exceeds the greater of (1) $1.5 billion and (2) 10% of net tangible assets, the CQP Senior Notes will be secured to the same extent as such obligations under the 2019 CQP Credit Facilities. The obligations under the 2019 CQP Credit Facilities are secured on a first-priority basis (subject to permitted encumbrances) with liens on substantially all our existing and future tangible and intangible assets and our rights and the rights of the CQP Guarantors and equity interests in the CQP Guarantors (except, in each case, for certain excluded properties set forth in the 2019 CQP Credit Facilities). The liens securing the CQP Senior Notes, if applicable, will be shared equally and ratably (subject to permitted liens) with the holders of other senior secured obligations, which include the 2019 CQP Credit Facilities obligations and any future additional senior secured debt obligations.

The CQP Guarantors’ guarantees are full and unconditional, subject to certain release provisions including (1) the sale, disposition or transfer (by merger, consolidation or otherwise) of the capital stock or all or substantially all of the assets of the CQP Guarantors, (2) upon the liquidation or dissolution of a Guarantor, (3) following the release of a Guarantor from its guarantee obligations and (4) upon the legal defeasance or satisfaction and discharge of obligations under the indenture governing the CQP Senior Notes. In the event of a default in payment of the principal or interest by us, whether at maturity of the CQP Senior Notes or by declaration of acceleration, call for redemption or otherwise, legal proceedings may be instituted against the CQP Guarantors to enforce the guarantee.

The rights of holders of the CQP Senior Notes against the CQP Guarantors may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. Each guarantee contains a provision intended to limit the Guarantor’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its guarantee to be a fraudulent conveyance or transfer under U.S. federal or state law. However, there can be no assurance as to what standard a court will apply in making a determination of the maximum liability of the CQP Guarantors. Moreover, this provision may not be effective to protect the guarantee from being voided under fraudulent conveyance laws. There is a possibility that the entire guarantee may be set aside, in which case the entire liability may be extinguished.

The following tables include summarized financial information of Cheniere Partners (“Parent Issuer”), and the CQP Guarantors (together with the Parent Issuer, the “Obligor Group”) on a combined basis. Investments in and equity in the earnings of SPL and, subject to certain conditions governing its guarantee, Sabine Pass LP (collectively with SPL, the “Non-Guarantors”), which are not currently members of the Obligor Group, have been excluded. Intercompany balances and transactions between entities in the Obligor Group have been eliminated. Although the creditors of the Obligor Group have no claim against the Non-Guarantors, the Obligor Group may gain access to the assets of the Non-Guarantors upon bankruptcy, liquidation or reorganization of the Non-Guarantors due to its investment in these entities. However, such claims to the assets of the Non-Guarantors would be subordinated to the any claims by the Non-Guarantors’ creditors, including trade creditors. See Sabine Pass LNG Terminal—SPL Senior Notes for additional detail on restrictions of Non-Guarantor debt.
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Summarized Balance Sheets (in millions) September 30, December 31,
2020 2019
ASSETS
Current assets
Cash and cash equivalents $ 1,254  $ 1,781 
Accounts receivable from Non-Guarantors 36  43 
Other current assets 41  33 
Current assets—affiliate 114  145 
Total current assets 1,445  2,002 
Property, plant and equipment, net 2,508  2,533 
Other non-current assets, net 120  122 
Total assets $ 4,073  $ 4,657 
LIABILITIES
Current liabilities
Due to affiliates $ 125  $ 158 
Deferred revenue from Non-Guarantors 21  21 
Deferred revenue—affiliate —  1 
Other current liabilities 168  111 
Other current liabilities from Non-Guarantors —  — 
Total current liabilities 314  291 
Long-term debt, net 4,059  4,055 
Other non-current liabilities 86  83 
Non-current liabilities—affiliate 18  20 
Total liabilities $ 4,477  $ 4,449 

Summarized Statement of Income (in millions) Nine Months Ended September 30, 2020
Revenues $ 230 
Revenues from Non-Guarantors 389 
Total revenues 619 
Operating costs and expenses 132 
Operating costs and expenses—affiliate 149 
Total operating costs and expenses 281 
Income from operations 338 
Net income 176 

2019 CQP Credit Facilities

In May 2019, we entered into the 2019 CQP Credit Facilities, which consisted of the $750 million term loan (“CQP Term Facility”), which was prepaid and terminated upon issuance of the 2029 CQP Senior Notes in September 2019, and the $750 million revolving credit facility (“CQP Revolving Facility”). Borrowings under the 2019 CQP Credit Facilities will be used to fund the development and construction of Train 6 of the Liquefaction Project and for general corporate purposes, subject to a sublimit, and the 2019 CQP Credit Facilities are also available for the issuance of letters of credit. As of both September 30, 2020 and December 31, 2019, we had $750 million of available commitments and no letters of credit issued or loans outstanding under the 2019 CQP Credit Facilities.

The 2019 CQP Credit Facilities mature on May 29, 2024. Any outstanding balance may be repaid, in whole or in part, at any time without premium or penalty, except for interest rate breakage costs. The 2019 CQP Credit Facilities contain conditions precedent for extensions of credit, as well as customary affirmative and negative covenants, and limit our ability to
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make restricted payments, including distributions, to once per fiscal quarter and one true-up per fiscal quarter as long as certain conditions are satisfied.

The 2019 CQP Credit Facilities are unconditionally guaranteed and secured by a first priority lien (subject to permitted encumbrances) on substantially all of our and the CQP Guarantors’ existing and future tangible and intangible assets and rights and equity interests in the CQP Guarantors (except, in each case, for certain excluded properties set forth in the 2019 CQP Credit Facilities).

Sabine Pass LNG Terminal 

Liquefaction Facilities

The Liquefaction Project is one of the largest LNG production facilities in the world. We are currently operating five Trains and two marine berths at the Liquefaction Project, and are constructing one additional Train. We have received authorization from the FERC to site, construct and operate Trains 1 through 6, as well as for the construction of a third marine berth. We have achieved substantial completion of the first five Trains of the Liquefaction Project and commenced commercial operating activities for each Train at various times starting in May 2016. The following table summarizes the project completion and construction status of Train 6 of the Liquefaction Project as of September 30, 2020:
Train 6
Overall project completion percentage 70.9%
Completion percentage of:
Engineering 97.8%
Procurement 98.2%
Subcontract work 48.0%
Construction 34.6%
Date of expected substantial completion 2H 2022

The following orders have been issued by the DOE authorizing the export of domestically produced LNG by vessel from the Sabine Pass LNG terminal:
•Trains 1 through 4—FTA countries and non-FTA countries through December 31, 2050, in an amount up to a combined total of the equivalent of 16 mtpa (approximately 803 Bcf/yr of natural gas).
•Trains 1 through 4—FTA countries and non-FTA countries through December 31, 2050, in an amount up to a combined total of the equivalent of approximately 203 Bcf/yr of natural gas (approximately 4 mtpa).
•Trains 5 and 6—FTA countries and non-FTA countries through December 31, 2050, in an amount up to a combined total of 503.3 Bcf/yr of natural gas (approximately 10 mtpa).
The DOE issued an order authorizing SPL to export domestically produced LNG by vessel from the Sabine Pass LNG terminal to FTA countries and non-FTA countries over a two-year period commencing January 2020, in an aggregate amount up to the equivalent of 600 Bcf of natural gas (however, exports under this order, when combined with exports under the orders above, may not exceed 1,509 Bcf/yr).

An application was filed in September 2019 seeking authorization to make additional exports from the Liquefaction Project to FTA countries for a 25-year term and to non-FTA countries for a 20-year term in an amount up to the equivalent of approximately 153 Bcf/yr of natural gas, for a total Liquefaction Project export capacity of approximately 1,662 Bcf/yr. The terms of the authorizations are requested to commence on the date of first commercial export from the Liquefaction Project of the volumes contemplated in the application. In April 2020, the DOE issued an order authorizing SPL to export to FTA countries related to this application, for which the term was subsequently extended through December 31, 2050, but has not yet issued an order authorizing SPL to export to non-FTA countries for the corresponding LNG volume. A corresponding application for authorization to increase the total LNG production capacity of the Liquefaction Project from the currently authorized level to approximately 1,662 Bcf/yr was also submitted to the FERC and is currently pending.
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Customers

SPL has entered into fixed price long-term SPAs generally with terms of 20 years (plus extension rights) and with a weighted average remaining contract length of approximately 17 years (plus extension rights) with eight third parties for Trains 1 through 6 of the Liquefaction Project to make available an aggregate amount of LNG that is approximately 75% of the total production capacity from these Trains, potentially increasing up to approximately 85% after giving effect to an SPA that Cheniere has committed to provide to us by the end of 2020. Under these SPAs, the customers will purchase LNG from SPL on a free on board (“FOB”) basis for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG generally equal to approximately 115% of Henry Hub. The customers may elect to cancel or suspend deliveries of LNG cargoes, with advance notice as governed by each respective SPA, in which case the customers would still be required to pay the fixed fee with respect to the contracted volumes that are not delivered as a result of such cancellation or suspension. We refer to the fee component that is applicable regardless of a cancellation or suspension of LNG cargo deliveries under the SPAs as the fixed fee component of the price under SPL’s SPAs. We refer to the fee component that is applicable only in connection with LNG cargo deliveries as the variable fee component of the price under SPL’s SPAs. The variable fees under SPL’s SPAs were generally sized at the time of entry into each SPA with the intent to cover the costs of gas purchases and transportation and liquefaction fuel to produce the LNG to be sold under each such SPA. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train.

In aggregate, the annual fixed fee portion to be paid by the third-party SPA customers is approximately $2.9 billion for Trains 1 through 5. After giving effect to an SPA that Cheniere has committed to provide to SPL, the annual fixed fee portion to be paid by the third-party SPA customers would increase to at least $3.3 billion, which is expected to occur upon the date of first commercial delivery of Train 6.

In addition, Cheniere Marketing has agreements with SPL to purchase: (1) at Cheniere Marketing’s option, any LNG produced by SPL in excess of that required for other customers and (2) up to 43 cargoes scheduled for delivery in 2020 at a price of 115% of Henry Hub plus $1.67 per MMBtu.

Natural Gas Transportation, Storage and Supply

To ensure SPL is able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, it has entered into transportation precedent and other agreements to secure firm pipeline transportation capacity with CTPL and third-party pipeline companies. SPL has entered into firm storage services agreements with third parties to assist in managing variability in natural gas needs for the Liquefaction Project. SPL has also entered into enabling agreements and long-term natural gas supply contracts with third parties in order to secure natural gas feedstock for the Liquefaction Project. As of September 30, 2020, SPL had secured up to approximately 5,051 TBtu of natural gas feedstock through long-term and short-term natural gas supply contracts with remaining terms that range up to 10 years, a portion of which is subject to conditions precedent.

Construction

SPL entered into lump sum turnkey contracts with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of Trains 1 through 6 of the Liquefaction Project, under which Bechtel charges a lump sum for all work performed and generally bears project cost, schedule and performance risks unless certain specified events occur, in which case Bechtel may cause SPL to enter into a change order, or SPL agrees with Bechtel to a change order.

The total contract price of the EPC contract for Train 6 of the Liquefaction Project is approximately $2.5 billion, including estimated costs for the third marine berth that is currently under construction. As of September 30, 2020, we have incurred $1.8 billion under this contract.

Regasification Facilities

The Sabine Pass LNG terminal has operational regasification capacity of approximately 4 Bcf/d and aggregate LNG storage capacity of approximately 17 Bcfe. Approximately 2 Bcf/d of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term third-party TUAs, under which SPLNG’s customers are required to pay fixed monthly fees, whether or not they use the LNG terminal.  Each of Total Gas & Power North America, Inc. (“Total”) and
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Chevron U.S.A. Inc. (“Chevron”) has reserved approximately 1 Bcf/d of regasification capacity and is obligated to make monthly capacity payments to SPLNG aggregating approximately $125 million annually, prior to inflation adjustments, for 20 years that commenced in 2009. Total S.A. has guaranteed Total’s obligations under its TUA up to $2.5 billion, subject to certain exceptions, and Chevron Corporation has guaranteed Chevron’s obligations under its TUA up to 80% of the fees payable by Chevron.

The remaining approximately 2 Bcf/d of capacity has been reserved under a TUA by SPL. SPL is obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million annually, prior to inflation adjustments, continuing until at least May 2036. SPL entered into a partial TUA assignment agreement with Total, whereby upon substantial completion of Train 5 of the Liquefaction Project, SPL gained access to substantially all of Total’s capacity and other services provided under Total’s TUA with SPLNG. This agreement provides SPL with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity, permit SPL to more flexibly manage its LNG storage capacity and accommodate the development of Train 6. Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA. During each of the three months ended September 30, 2020 and 2019, SPL recorded $32 million as operating and maintenance expense under this partial TUA assignment agreement. During the nine months ended September 30, 2020 and 2019, SPL recorded $97 million and $72 million, respectively, as operating and maintenance expense under this partial TUA assignment agreement.

Under each of these TUAs, SPLNG is entitled to retain 2% of the LNG delivered to the Sabine Pass LNG terminal.

Capital Resources

We currently expect that SPL’s capital resources requirements with respect to the Liquefaction Project will be financed through project debt and borrowings, cash flows under the SPAs and equity contributions from us. We believe that with the net proceeds of borrowings, available commitments under the 2020 SPL Working Capital Facility, 2019 CQP Credit Facilities, cash flows from operations and equity contributions from us, SPL will have adequate financial resources available to meet its currently anticipated capital, operating and debt service requirements with respect to Trains 1 through 6 of the Liquefaction Project. Additionally, SPLNG generates cash flows from the TUAs, as discussed above.

The following table provides a summary of our capital resources from borrowings and available commitments for the Sabine Pass LNG Terminal, excluding equity contributions to our subsidiaries and cash flows from operations (as described in Sources and Uses of Cash), at September 30, 2020 and December 31, 2019 (in millions):
September 30, December 31,
  2020 2019
Senior notes (1) $ 17,750  $ 17,750 
Credit facilities outstanding balance (2) —  — 
Letters of credit issued (3) 413  414 
Available commitments under credit facilities (3) 1,537  1,536 
Total capital resources from borrowings and available commitments (4) $ 19,700  $ 19,700 
(1)    Includes SPL’s 2021 SPL Senior Notes, 6.25% Senior Secured Notes due 2022, 5.625% Senior Secured Notes due 2023, 5.75% Senior Secured Notes due 2024, 5.625% Senior Secured Notes due 2025, 5.875% Senior Secured Notes due 2026 (the “2026 SPL Senior Notes”), 5.00% Senior Secured Notes due 2027 (the “2027 SPL Senior Notes”), 4.200% Senior Secured Notes due 2028 (the “2028 SPL Senior Notes”), 2030 SPL Senior Notes and 5.00% Senior Secured Notes due 2037 (the “2037 SPL Senior Notes”) (collectively, the “SPL Senior Notes”) and our CQP Senior Notes.
(2)         Includes outstanding balances under the 2015 SPL Working Capital Facility, 2020 SPL Working Capital Facility and 2019 CQP Credit Facilities, inclusive of any portion of the 2020 SPL Working Capital Facility and 2019 CQP Credit Facilities that may be used for general corporate purposes.
(3)        Consists of 2015 SPL Working Capital Facility, 2020 SPL Working Capital Facility and 2019 CQP Credit Facilities.
(4)        Does not include equity contributions that may be available from Cheniere’s borrowings and available cash and cash equivalents.

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For additional information regarding our debt agreements related to the Sabine Pass LNG Terminal, see Note 11—Debt of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the fiscal year ended December 31, 2019.

SPL Senior Notes

The SPL Senior Notes are governed by a common indenture (the “SPL Indenture”) and the terms of the 2037 SPL Senior Notes are governed by a separate indenture (the “2037 SPL Senior Notes Indenture”). Both the SPL Indenture and the 2037 SPL Senior Notes Indenture contain terms and events of default and certain covenants that, among other things, limit SPL’s ability and the ability of SPL’s restricted subsidiaries to incur additional indebtedness or issue preferred stock, make certain investments or pay dividends or distributions on capital stock or subordinated indebtedness or purchase, redeem or retire capital stock, sell or transfer assets, including capital stock of SPL’s restricted subsidiaries, restrict dividends or other payments by restricted subsidiaries, incur liens, enter into transactions with affiliates, dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of SPL’s assets and enter into certain LNG sales contracts. Subject to permitted liens, the SPL Senior Notes are secured on a pari passu first-priority basis by a security interest in all of the membership interests in SPL and substantially all of SPL’s assets. SPL may not make any distributions until, among other requirements, deposits are made into debt service reserve accounts as required and a debt service coverage ratio test of 1.25:1.00 is satisfied.

At any time prior to three months before the respective dates of maturity for each series of the SPL Senior Notes (except for the 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes, 2030 SPL Senior Notes and 2037 SPL Senior Notes, in which case the time period is six months before the respective dates of maturity), SPL may redeem all or part of such series of the SPL Senior Notes at a redemption price equal to the ‘make-whole’ price (except for the 2037 SPL Senior Notes, in which case the redemption price is equal to the “optional redemption” price) set forth in the respective indentures governing the SPL Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. SPL may also, at any time within three months of the respective maturity dates for each series of the SPL Senior Notes (except for the 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes, 2030 SPL Senior Notes and 2037 SPL Senior Notes, in which case the time period is within six months of the respective dates of maturity), redeem all or part of such series of the SPL Senior Notes at a redemption price equal to 100% of the principal amount of such series of the SPL Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.
Both the 2037 SPL Senior Notes Indenture and the SPL Indenture include restrictive covenants. SPL may incur additional indebtedness in the future, including by issuing additional notes, and such indebtedness could be at higher interest rates and have different maturity dates and more restrictive covenants than the current outstanding indebtedness of SPL, including the SPL Senior Notes and the 2020 SPL Working Capital Facility. Under the 2037 SPL Senior Notes Indenture and the SPL Indenture, SPL may not make any distributions until, among other requirements, deposits are made into debt service reserve accounts as required and a debt service reserve ratio test of 1.25:1.00 is satisfied. Semi-annual principal payments for the 2037 SPL Senior Notes are due on March 15 and September 15 of each year beginning September 15, 2025 and are fully amortizing according to a fixed sculpted amortization schedule.

2015 SPL Working Capital Facility

In March 2020, SPL terminated the remaining commitments under the 2015 SPL Working Capital Facility. As of December 31, 2019, SPL had $786 million of available commitments, $414 million aggregate amount of issued letters of credit and no outstanding borrowings under the 2015 SPL Working Capital Facility.

2020 SPL Working Capital Facility

In March 2020, SPL entered into the 2020 SPL Working Capital Facility with aggregate commitments of $1.2 billion, which replaced the 2015 SPL Working Capital Facility. The 2020 SPL Working Capital Facility is intended to be used for loans to SPL, swing line loans to SPL and the issuance of letters of credit on behalf of SPL, primarily for (1) the refinancing of the 2015 SPL Working Capital Facility, (2) fees and expenses related to the 2020 SPL Working Capital Facility, (3) SPL and its future subsidiaries’ gas purchase obligations and (4) SPL and certain of its future subsidiaries’ general corporate purposes. SPL may, from time to time, request increases in the commitments under the 2020 SPL Working Capital Facility of up to $800 million. As of September 30, 2020, SPL had $787 million of available commitments, $413 million aggregate amount of issued letters of credit and no outstanding borrowings under the 2020 SPL Working Capital Facility.

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The 2020 SPL Working Capital Facility matures on March 19, 2025, but may be extended with consent of the lenders. The 2020 SPL Working Capital Facility provides for mandatory prepayments under customary circumstances.

The 2020 SPL Working Capital Facility contains customary conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. SPL is restricted from making certain distributions under agreements governing its indebtedness generally until, among other requirements, satisfaction of a 12-month forward-looking and backward-looking 1.25:1.00 debt service reserve ratio test. The obligations of SPL under the 2020 SPL Working Capital Facility are secured by substantially all of the assets of SPL as well as a pledge of all of the membership interests in SPL and certain future subsidiaries of SPL on a pari passu basis by a first priority lien with the SPL Senior Notes.

Restrictive Debt Covenants

As of September 30, 2020, we and SPL were in compliance with all covenants related to our respective debt agreements.

LIBOR

The use of LIBOR is expected to be phased out by the end of 2021. It is currently unclear whether LIBOR will be utilized beyond that date or whether it will be replaced by a particular rate. We intend to continue working with our lenders to pursue any amendments to our debt agreements that are currently subject to LIBOR and will continue to monitor, assess and plan for the phase out of LIBOR.

Sources and Uses of Cash

The following table summarizes the sources and uses of our cash, cash equivalents and restricted cash for the nine months ended September 30, 2020 and 2019 (in millions). The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussion of these items follows the table.
Nine Months Ended September 30,
2020 2019
Operating cash flows $ 1,333  $ 977 
Investing cash flows (795) (1,157)
Financing cash flows (1,089) 531 
Net increase (decrease) in cash, cash equivalents and restricted cash (551) 351 
Cash, cash equivalents and restricted cash—beginning of period 1,962  1,541 
Cash, cash equivalents and restricted cash—end of period $ 1,411  $ 1,892 

Operating Cash Flows

Our operating cash net inflows during the nine months ended September 30, 2020 and 2019 were $1,333 million and $977 million, respectively. The $356 million increase in operating cash inflows in 2020 compared to 2019 was primarily related to decreased operating costs and expenses.

Investing Cash Flows

Investing cash net outflows during the nine months ended September 30, 2020 and 2019 were $795 million and $1,157 million, respectively, and were primarily used to fund the construction costs for the Liquefaction Project. These costs are capitalized as construction-in-process until achievement of substantial completion.

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Financing Cash Flows

Financing cash net outflows of $1,089 million during the nine months ended September 30, 2020 was primarily a result of:
•issuance of an aggregate principal amount of $2.0 billion of the 2030 SPL Senior Notes, which was used to redeem all of the outstanding 2021 SPL Senior Notes;
•$39 million of debt extinguishment costs related to the redemption of the 2021 SPL Senior Notes;
•$34 million of debt issuance costs related to up-front fees paid upon closing of the 2030 SPL Senior Notes and the 2020 SPL Working Capital Facility; and
•$1,011 million of distributions to unitholders.

Financing cash net inflows of $531 million during the nine months ended September 30, 2019 was primarily a result of:
•$730 million of borrowings and repayments under the 2019 CQP Credit Facilities;
•issuance of an aggregate principal amount of $1.5 billion of the 2029 CQP Senior Notes, which was used to prepay the outstanding balance of the term loan under the 2019 CQP Credit Facilities;
•$33 million of debt issuance costs related to the up-front fees paid upon the issuance of the 2019 CQP Credit Facilities and 2029 CQP Senior Notes; and
•$935 million of distributions to unitholders.

Cash Distributions to Unitholders
 
Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement). Our available cash is our cash on hand at the end of a quarter less the amount of any reserves established by our general partner. All distributions paid to date have been made from accumulated operating surplus. The following provides a summary of distributions paid by us during the three and nine months ended September 30, 2020 and 2019:
Total Distribution (in millions)
Date Paid Period Covered by Distribution Distribution Per Common Unit Distribution Per Subordinated Unit Common Units Subordinated Units General Partner Units Incentive Distribution Rights
August 14, 2020 April 1 - June 30, 2020 $ 0.645  $ 0.645  $ 225  $ 88  $ 7  $ 22 
May 15, 2020 January 1 - March 31, 2020 0.64  0.64  223  86  7  20 
February 14, 2020 October 1- December 31, 2019 0.63  0.63  220  85  6  18 
August 14, 2019 April 1 - June 30, 2019 0.61  0.61  213  83  6  15 
May 15, 2019 January 1 - March 31, 2019 0.60  0.60  209  81  6  13 
February 14, 2019 October 1 - December 31, 2018 0.59  0.59  206  80  6  12 

On October 27, 2020, we declared a $0.650 distribution per common unit and the related distribution to our general partner and incentive distribution right holders to be paid on November 13, 2020 to unitholders of record as of November 6, 2020 for the period from July 1, 2020 to September 30, 2020.

The subordinated units will receive distributions only to the extent we have available cash above the initial quarterly distributions requirement for our common unitholders and general partner along with certain reserves. Such available cash could be generated through new business development. In July 2020, the board of directors of our general partner confirmed and approved that, following the distribution with respect to the three months ended June 30, 2020, the financial tests required for conversion of our subordinated units were met under the terms of our partnership agreement. Accordingly, effective August 17, 2020, the first business day following the payment of the distribution, all of our subordinated units were automatically converted into common units on a one-for-one basis and the subordination period was terminated.

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Results of Operations

The following charts summarize the number of Trains that were in operation during the year ended December 31, 2019 and the nine months ended September 30, 2020 and total revenues and total LNG volumes loaded (including both operational and commissioning volumes) during the nine months ended September 30, 2020 and 2019:
CQP-20200930_G2.JPG
CQP-20200930_G3.JPG CQP-20200930_G4.JPG
(1)
The nine months ended September 30, 2020 excludes 11 TBtu that was loaded at our affiliate’s facility.
Our consolidated net loss was $67 million, or $(0.08) per common unit (basic and diluted), for the three months ended September 30, 2020, compared to net income of $110 million, or $0.19 per common unit (basic and diluted), for the three months ended September 30, 2019. This $177 million decrease in net income was primarily attributable to the impact of prior period elections by our long-term SPA customers to exercise their contractual right to not take delivery of LNG cargoes that were scheduled to be delivered this quarter.

Our consolidated net income was $774 million, or $1.55 per common unit (basic and diluted), for the nine months ended September 30, 2020, compared to $727 million, or $1.38 per common unit (basic and diluted), for the nine months ended September 30, 2019. This $47 million increase in net income was primarily a result of increased margins due to lower pricing of natural gas feedstock and additional LNG volume available to be sold from an additional Train that has reached substantial completion between the periods, a portion of which the customers elected not to take delivery but were required to pay a fixed fee with respect to the contracted volumes, partially offset by increases in (1) interest expense, net of capitalized interest, (2)
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loss on modification or extinguishment of debt incurred in conjunction with the refinancing of the 2021 SPL Senior Notes and (3) depreciation and amortization expense.

We enter into derivative instruments to manage our exposure to commodity-related marketing and price risk. Derivative instruments are reported at fair value on our Consolidated Financial Statements. In some cases, the underlying transactions economically hedged receive accrual accounting treatment, whereby revenues and expenses are recognized only upon delivery, receipt or realization of the underlying transaction. Because the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, use of derivative instruments may increase the volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors.

Revenues
Three Months Ended September 30, Nine Months Ended September 30,
(in millions, except volumes) 2020 2019 Change 2020 2019 Change
LNG revenues $ 807  $ 1,140  $ (333) $ 3,588  $ 3,678  $ (90)
LNG revenues—affiliate 103  257  (154) 352  1,017  (665)
Regasification revenues 67  66  1  202  199  3 
Other revenues 5  13  (8) 28  36  (8)
Total revenues $ 982  $ 1,476  $ (494) $ 4,170  $ 4,930  $ (760)
LNG volumes recognized as revenues (in TBtu) 132  277  (145) 666  845  (179)

Total revenues decreased during the three and nine months ended September 30, 2020 from the three and nine months ended September 30, 2019, primarily as a result of decreased volumes recognized as revenues between the periods due to LNG cargoes for which customers have notified us that they will not take delivery, although these decreases were partially offset by the revenues associated with LNG cargoes for which customers have notified us that they will not take delivery. LNG revenues during the three and nine months ended September 30, 2020 included $109 million and $513 million, respectively, in such revenues, of which $21 million would have otherwise been recognized subsequent to September 30, 2020, if the cargoes were lifted pursuant to the delivery schedules with the customers. LNG revenues during the three months ended September 30, 2020 excluded $244 million in prior period cancellations that would have otherwise been recognized during the quarter if the cargoes were lifted pursuant to the delivery schedules with the customers. LNG revenues—affiliate also decreased during the three and nine months ended September 30, 2020 from the three and nine months ended September 30, 2019 due to less sales made to Cheniere Marketing at lower pricing. We experienced decreased revenues during the three months ended September 30, 2020 because we recognized accelerated revenues associated with LNG cargoes that were scheduled for delivery during the current quarter in the prior quarter, when the customers notified us that they will not take delivery of such cargoes. We expect our LNG revenues to increase in the future upon Train 6 of the Liquefaction Project becoming operational.

Prior to substantial completion of a Train, amounts received from the sale of commissioning cargoes from that Train are offset against LNG terminal construction-in-process, because these amounts are earned or loaded during the testing phase for the construction of that Train. During the nine months ended September 30, 2019, we realized offsets to LNG terminal costs of $48 million corresponding to 10 TBtu of LNG that were related to the sale of commissioning cargoes. We did not realize any offsets to LNG terminal costs during the three and nine months ended September 30, 2020 and the three months ended September 30, 2019.
Also included in LNG revenues are sales of unutilized natural gas procured for the liquefaction process and gains and losses from derivative instruments, which include the realized value associated with a portion of derivative instruments that settle through physical delivery. We recognized revenues of $130 million and $35 million during the three months ended September 30, 2020 and 2019, respectively, and $211 million and $114 million during the nine months ended September 30, 2020 and 2019, respectively, related to these transactions.

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Operating costs and expenses
Three Months Ended September 30, Nine Months Ended September 30,
(in millions) 2020 2019 Change 2020 2019 Change
Cost of sales $ 454  $ 742  $ (288) $ 1,551  $ 2,501  $ (950)
Cost of sales—affiliate 33  6  27  38  6  32 
Operating and maintenance expense 146  172  (26) 463  472  (9)
Operating and maintenance expense—affiliate 34  34  —  115  100  15 
General and administrative expense 2  3  (1) 12  9  3 
General and administrative expense—affiliate 24  34  (10) 73  82  (9)
Depreciation and amortization expense 137  138  (1) 413  390  23 
Impairment expense and loss on disposal of assets —  1  (1) 5  6  (1)
Total operating costs and expenses $ 830  $ 1,130  $ (300) $ 2,670  $ 3,566  $ (896)

Our total operating costs and expenses decreased during the three and nine months ended September 30, 2020 from the three and nine months ended September 30, 2019, primarily as a result of decreased cost of sales from lower volumes and pricing of natural gas feedstock.
Cost of sales includes costs incurred directly for the production and delivery of LNG from the Liquefaction Project, to the extent those costs are not utilized for the commissioning process. Cost of sales decreased during the three months ended September 30, 2020 from the three months ended September 30, 2019, due to the decrease in the volumes of natural gas feedstock during the periods, whereas the decrease during the nine months ended September 30, 2020 from the nine months ended September 30, 2019 was primarily due to decreases in both the pricing and volumes of natural gas feedstock between the periods. Partially offsetting these decreases were increases in costs associated with a portion of derivative instruments that settle through physical delivery and increased losses from commodity derivatives to secure natural gas feedstock for the Liquefaction Project, primarily due to an unfavorable shift in long-term forward prices relative to our hedged position. Cost of sales—affiliate increased during the three and nine months ended September 30, 2020 from the three and nine months ended September 30, 2019 for the cost of cargoes procured from our affiliate to fulfill our commitments to our long-term customers during operational interruption, such as the one we experienced during the shutdown of the Liquefaction Project during Hurricane Laura in September 2020.

Operating and maintenance expense (including affiliate) primarily includes costs associated with operating and maintaining the Liquefaction Project. Operating and maintenance expense (including affiliates) decreased during the three months ended September 30, 2020 from the three months ended September 30, 2019 due to a decrease in third-party service and maintenance contract costs and other operating costs, as the three months ended September 30, 2019 included cost of turnaround and related activities at the Liquefaction Project that did not recur in the comparable period of 2020. Operating and maintenance expense (including affiliates) increased during the nine months ended September 30, 2020 from the nine months ended September 30, 2019 due to an increase in TUA reservation charges due to Total under the partial TUA assignment agreement and increased natural gas transportation and storage capacity demand charges paid to third parties from operating Train 5 of the Liquefaction Project following its substantial completion, partially offset by the decreased costs associated with turnaround and related activities. Additionally, operating and maintenance expense (including affiliates) during the three and nine months ended September 30, 2020 includes costs incurred in response to the COVID-19 pandemic, as further described earlier in Impact of COVID-19 and Market Environment. Operating and maintenance expense (including affiliates) also includes payroll and benefit costs of operations personnel, insurance and regulatory costs and other operating costs.

Depreciation and amortization expense increased during the nine months ended September 30, 2020 from the nine months ended September 30, 2019, as the assets related to Train 5 of the Liquefaction Project began depreciating upon reaching substantial completion in March 2019.

Other expense (income)
Three Months Ended September 30, Nine Months Ended September 30,
(in millions) 2020 2019 Change 2020 2019 Change
Interest expense, net of capitalized interest $ 221  $ 231  $ (10) $ 691  $ 648  $ 43 
Loss on modification or extinguishment of debt —  13  (13) 43  13  30 
Other income, net (2) (8) 6  (8) (24) 16 
Total other expense $ 219  $ 236  $ (17) $ 726  $ 637  $ 89 
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Interest expense, net of capitalized interest, decreased during the three months ended September 30, 2020 compared to the three months ended September 30, 2019, primarily due to an increase in the portion of total interest costs that was eligible for capitalization as the construction of Train 6 commenced in May 2019. Interest expense, net of capitalized interest, increased during the nine months ended September 30, 2020 from the three and nine months ended September 30, 2019 due to higher interest costs as a result of the issuance of the 2029 CQP Senior Notes in September 2019. During the three months ended September 30, 2020, this increase was partially offset by an increase in the portion of total interest costs that was eligible for capitalization. During both the three months ended September 30, 2020 and 2019, we incurred $246 million of total interest cost, of which we capitalized $25 million and $15 million, respectively, which was primarily related to interest costs incurred to construct the remaining assets of the Liquefaction Project. During the nine months ended September 30, 2020 and 2019, we incurred $759 million and $718 million of total interest cost, respectively, of which we capitalized $68 million and $70 million, respectively, which was primarily related to interest costs incurred to construct the remaining assets of the Liquefaction Project.

Loss on modification or extinguishment of debt decreased during the three months ended September 30, 2020 from the comparable periods in 2019. The loss on modification or extinguishment of debt in 2019 was related to the termination of $750 million of commitments under the 2019 CQP Credit Facilities in connection with the issuance of the 2029 CQP Senior Notes. Loss on modification or extinguishment of debt increased during the nine months ended September 30, 2020 from the comparable period in 2019, due to the recognition of $43 million of debt extinguishment costs relating to the payment of early redemption fees and write off of unamortized debt premiums and issuance costs associated with the redemption of the 2021 SPL Senior Notes.

Off-Balance Sheet Arrangements
 
As of September 30, 2020, we had no transactions that met the definition of off-balance sheet arrangements that may have a current or future material effect on our consolidated financial position or operating results. 
Summary of Critical Accounting Estimates
  
The preparation of our Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. There have been no significant changes to our critical accounting estimates from those disclosed in our annual report on Form 10-K for the fiscal year ended December 31, 2019.
 
Recent Accounting Standards 

For descriptions of recently issued accounting standards, see Note 1—Nature of Operations and Basis of Presentation of our Notes to Consolidated Financial Statements.

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 

Marketing and Trading Commodity Price Risk

We have entered into commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project (“Liquefaction Supply Derivatives”). In order to test the sensitivity of the fair value of the Liquefaction Supply Derivatives to changes in underlying commodity prices, management modeled a 10% change in the commodity price for natural gas for each delivery location as follows (in millions):
September 30, 2020 December 31, 2019
Fair Value Change in Fair Value Fair Value Change in Fair Value
Liquefaction Supply Derivatives $ (12) $ 5  $ 24  $ 1 

See Note 7—Derivative Instruments for additional details about our derivative instruments.

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ITEM 4.     CONTROLS AND PROCEDURES
 
We maintain a set of disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports filed by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. As of the end of the period covered by this report, we evaluated, under the supervision and with the participation of our general partner’s management, including our general partner’s Chief Executive Officer and Chief Financial Officer, the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act. Based on that evaluation, our general partner’s Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective.

During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II.     OTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS

We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. There have been no material changes to the legal proceedings disclosed in our annual report on Form 10-K for the fiscal year ended December 31, 2019.

ITEM 1A.    RISK FACTORS

There have been no material changes from the risk factors disclosed in our annual report on Form 10-K for the fiscal year ended December 31, 2019, except for the updates presented in our quarterly report on Form 10-Q for the quarterly period ended March 31, 2020.

ITEM 6.     EXHIBITS
Exhibit No. Description
4.1*
10.1*
Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between SPL and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00023 Third Berth Vapor Fence Provisional Sum Scope Removal and Closeout, dated June 22, 2020, (ii) the Change Order CO-00024 Train 6 Thermowell Upgrades, dated June 22, 2020, (iii) the Change Order CO-00025 Third Berth Bubble Curtain, dated June 22, 2020, (iv) the Change Order CO-00026 Third Berth Fuel Provisional Sum Closure Change Order, dated July 14, 2020, (v) the Change Order CO-00027 Third Berth Currency Provisional Sum Closure Change Order, dated July 20, 2020, (vi) the Change Order CO-00028 Train 6 Hot Oil WHRU PSV Bypass, dated August 11, 2020 and (vii) the Change Order CO-00029 Change in Law IMO 2020 Regulatory Change – Low Sulphur Emissions on Marine Vessels, dated August 25, 2020
22.1
31.1*
31.2*
32.1**
32.2**
101.INS* XBRL Instance Document
101.SCH* XBRL Taxonomy Extension Schema Document
101.CAL* XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF* XBRL Taxonomy Extension Definition Linkbase Document
101.LAB* XBRL Taxonomy Extension Labels Linkbase Document
101.PRE* XBRL Taxonomy Extension Presentation Linkbase Document
104* Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
* Filed herewith.
** Furnished herewith.
41


SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
CHENIERE ENERGY PARTNERS, L.P.
By: Cheniere Energy Partners GP, LLC,
its general partner
Date: November 5, 2020 By: /s/ Zach Davis
Zach Davis
Senior Vice President and Chief Financial Officer
  (on behalf of the registrant and
as principal financial officer)
Date: November 5, 2020 By: /s/ Leonard E. Travis
Leonard E. Travis
Senior Vice President and Chief Accounting Officer
  (on behalf of the registrant and
as principal accounting officer)

42

Exhibit 4.1





CHENIERE ENERGY PARTNERS, L.P.,

as Partnership

and

any Subsidiary Guarantors party hereto
and

THE BANK OF NEW YORK MELLON,
as Trustee


FOURTH SUPPLEMENTAL INDENTURE
Dated as of November 5, 2020


Supplement to

the First Supplemental Indenture
Dated as of September 18, 2017
in connection with the 5.250% Senior Notes due 2025,

the Second Supplemental Indenture
Dated as of September 11, 2018
in connection with the 5.625% Senior Notes due 2026

and

the Third Supplemental Indenture
Dated as of September 12, 2019
in connection with the 4.500% Senior Notes due 2029

to

the Indenture Dated as of September 18, 2017



THIS FOURTH SUPPLEMENTAL INDENTURE (this “Fourth Supplemental Indenture”), dated as of November 5, 2020 (the “Effective Date”), is among Cheniere Energy Partners, L.P., a Delaware limited partnership (the “Partnership”), any Subsidiary Guarantors party hereto, and The Bank of New York Mellon, as trustee (the “Trustee”).

RECITALS
WHEREAS, the Partnership and the Subsidiary Guarantors have executed and delivered to the Trustee an Indenture, dated as of September 18, 2017 (the “Base Indenture”), as supplemented by (i) a First Supplemental Indenture, dated as of September 18, 2017 (the “First Supplemental Indenture” and, together with the Base Indenture, the “2025 Notes Indenture”) pursuant to which the Partnership has duly issued 5.250% Senior Notes due 2025 (the “2025 Notes”) in the aggregate principal amount of $1,500,000,000, (ii) a Second Supplemental Indenture, dated as of September 11, 2018 (the “Second Supplemental Indenture” and, together with the Base Indenture, the “2026 Notes Indenture”) pursuant to which the Partnership has duly issued 5.625% Senior Notes due 2026 (the “2026 Notes”) in the aggregate principal amount of $1,100,000,000 and (iii) a Third Supplemental Indenture, dated as of September 12, 2019 (the “Third Supplemental Indenture” and, together with the Base Indenture, the “2029 Notes Indenture”) pursuant to which the Partnership has duly issued 4.500% Senior Notes due 2029 (the “2029 Notes”, and together with the 2025 Notes and the 2026 Notes, the “Notes”) in the aggregate principal amount of $1,500,000,000. The 2025 Notes Indenture, together with the 2026 Notes Indenture and the 2029 Notes Indenture is hereinafter referred to as the “Indentures”.

WHEREAS, (i) pursuant to Section 9.01(a) of the Base Indenture, the Partnership and the Trustee may amend or supplement certain terms of the Indentures or the Notes to cure any ambiguity, omission, defect or inconsistency without the consent of the Holders and (ii) pursuant to Section 9.01(j) of the Base Indenture, the Partnership and the Trustee may amend or supplement certain terms of the Indentures or the Notes to conform the text of the Indentures or the Notes to any provision of the “Description of Notes” contained in the offering memoranda describing the issuances of the Notes;

WHEREAS, the Partnership’s ability to redeem the notes subject to satisfaction of one or more conditions precedent (the “conditional call provision”) contained in the “Description of Notes” of each of (i) the offering memorandum dated September 12, 2017 describing the issuance of the 2025 Notes (the “2025 Description of Notes”), (ii) the offering memorandum dated September 12, 2017 describing the issuance of the 2026 Notes (the “2026 Description of Notes”) and (iii) the offering memorandum dated September 12, 2017 describing the issuance of the 2029 Notes (the “2029 Description of Notes”) was unintentionally omitted from each of the First Supplemental Indenture, the Second Supplemental Indenture and the Third Supplemental Indenture, respectively, and the Partnership desires to enter into this Fourth Supplemental Indenture to supplement each of the First Supplemental Indenture, the Second Supplemental Indenture and the Third Supplemental Indenture (i) to cure any ambiguity and omission as to the Partnership’s ability to redeem the notes subject to satisfaction of one or more conditions precedent; and (ii) to conform the text of each of the First Supplemental Indenture, the Second Supplemental Indenture and the Third Supplemental Indenture to the 2025 Description of Notes,
2

the 2026 Description of Notes and the 2029 Description of Notes, respectively, in each case by adding the conditional call provision;

WHEREAS, pursuant to Section 9.01 of the Base Indenture, the Partnership has requested and hereby requests that the Trustee join in the execution of this Fourth Supplemental Indenture and the Trustee is authorized to execute this Fourth Supplemental Indenture;

WHEREAS, the execution and delivery of this Fourth Supplemental Indenture have been duly authorized by the parties hereto, and all conditions and requirements necessary to make this Fourth Supplemental Indenture a valid and binding agreement of the Partnership and the Subsidiary Guarantors enforceable in accordance with its terms have been duly performed and complied with; and

WHEREAS, the Partnership has heretofore delivered or is delivering contemporaneously herewith to the Trustee (i) a copy of the Board Resolution (as defined in the Base Indenture) authorizing the execution of this Fourth Supplemental Indenture, (ii) the Officers’ Certificate and the Opinion of Counsel described in Sections 9.01, 9.06, 12.04 and 12.05 of the Base Indenture, and (iii) a written request to execute this Fourth Supplemental Indenture.

NOW, THEREFORE, in consideration of the premises, agreements and obligations set for herein and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree, for the equal and proportionate benefit of all Holders of the Notes, as follows:
3

ARTICLE I
RELATION TO INDENTURE; DEFINITIONS

Section 1.1 Relation to Base Indenture.

With respect to each of the 2025 Notes, the 2026 Notes and the 2029 Notes, this Fourth Supplemental Indenture constitutes an integral part of each of the First Supplemental Indenture, the Second Supplemental Indenture and Third Supplemental Indenture, respectively.

Section 1.2 Generally.

The rules of interpretation set forth in the Indentures shall be applied hereto as if set forth in full herein.

Section 1.3 Definition of Certain Terms.

Capitalized terms used herein and not otherwise defined herein shall have the respective meanings ascribed thereto in the Indentures.

ARTICLE II
AMENDMENTS TO THE INDENTURE

Section 2.1 Effectiveness of Fourth Supplemental Indenture.

This Fourth Supplemental Indenture shall become effective as of the date hereof.

Section 2.2 Amendments to Paragraph 5 of Exhibits A-1 and A-2 of each of the First Supplemental Indenture, the Second Supplemental Indenture and the Third Supplemental Indenture.

(a)The following paragraph shall be added to the end of numbered paragraph 5 in each of Exhibits A-1 and A-2 of the First Supplemental Indenture, the Second Supplemental Indenture and the Third Supplemental Indenture:

“In addition, any redemption pursuant to this paragraph 5 may, at the         Partnership’s discretion, be subject to one or more conditions precedent. If such redemption is subject to the satisfaction of one or more conditions precedent, the related notice shall describe each such condition, and if applicable, shall state that, in the Partnership’s discretion, the redemption date may be delayed until such time as any or all such conditions shall be satisfied or waived (including to a date later than 60 days after the date on which such notice was mailed or delivered electronically), or such redemption may not occur and such notice may be rescinded in the event that any or all such conditions shall not have been satisfied or waived by the redemption date, or by the redemption date as so delayed, or such notice may be rescinded at any time in the Partnership’s discretion if in the good faith judgment of the Partnership any or all of such conditions will not be satisfied or waived.”
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MISCELLANEOUS PROVISIONS

Section 3.1 Ratification of Indenture.

The Indentures, as supplemented by this Fourth Supplemental Indenture, are in all respects ratified and confirmed, and this Fourth Supplemental Indenture shall be deemed part of each of the First Supplemental Indenture, the Second Supplemental Indenture and Third Supplemental Indenture in the manner and to the extent herein and therein provided.

Section 3.2 Trustee Not Responsible for Recitals.

The recitals and statements contained herein shall be taken as the statements of the Partnership, and the Trustee assumes no responsibility for the correctness of the same. The Trustee makes no representations as to the validity, adequacy or sufficiency of this Fourth Supplemental Indenture.

Section 3.3 Headings.

The headings of the Articles and Sections of this Fourth Supplemental Indenture have been inserted for convenience of reference only, are not to be considered a part hereof and shall in no way modify or restrict any of the terms or provisions hereof.

Section 3.4 Counterpart Originals.

This Fourth Supplemental Indenture may be executed in any number of counterparts, each of which shall be an original, but such counterparts shall together constitute but one and the same instrument. The exchange of copies of this Fourth Supplemental Indenture and of signature pages that are executed by manual signatures that are scanned, photocopied or faxed or by other electronic signing created on an electronic platform (such as DocuSign) or by digital signing (such as Adobe Sign), in each case that is approved by the Trustee, shall constitute effective execution and delivery of this Fourth Supplemental Indenture for all purposes. Signatures of the parties hereto that are executed by manual signatures that are scanned, photocopied or faxed or by other electronic signing created on an electronic platform (such as DocuSign) or by digital signing (such as Adobe Sign), in each case that is approved by the Trustee, shall be deemed to be their original signatures for all purposes of this Fourth Supplemental Indenture as to the parties hereto and may be used in lieu of the original.

Anything in this Fourth Supplemental Indenture to the contrary notwithstanding, for the purposes of the transactions contemplated by this Fourth Supplemental Indenture and any document to be signed in connection with the Indentures or this Fourth Supplemental Indenture (including amendments, waivers, consents and other modifications, Officer’s Certificates, Partnership Orders and Opinions of Counsel and other issuance, authentication and delivery documents) or the transactions contemplated hereby may be signed by manual signatures that are scanned, photocopied or faxed or other electronic signatures created on an electronic platform (such as DocuSign) or by digital signature (such as Adobe Sign), in each case that is approved by the Trustee, and contract formations on electronic platforms approved by the Trustee, and the keeping of records in electronic form, are hereby authorized, and each shall be of the same legal
5

effect, validity or enforceability as a manually executed signature in ink or the use of a paper-based recordkeeping system, as the case may be.

Section 3.5 Severability.

In case any provision in this Fourth Supplemental Indenture shall be invalid, illegal or unenforceable, the validity, legality and enforceability of the remaining provisions shall not in any way be affected or impaired thereby.

Section 3.6 Successors and Assigns.

This Fourth Supplemental Indenture shall inure to the benefit of and be binding upon the parties hereto and each of their respective successors and permitted assigns. Without limiting the generality of the foregoing, this Fourth Supplemental Indenture shall inure to benefit of all Holders from time to time. Nothing expressed or mentioned in this Fourth Supplemental Indenture is intended to or shall be construed to give any Person, other than the parties hereto, their respective successor and assigns, and the Holders, any legal or equitable right, remedy or claim under or in respect of this Fourth Supplemental Indenture or any provision herein contained.

Section 3.7 Governing Law.

THIS FOURTH SUPPLEMENTAL INDENTURE SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.
Section 3.8 Trust Indenture Act Controls.

Upon registration of any of the Notes in accordance with a Registration Rights Agreement, if any provision of this Fourth Supplemental Indenture limits, qualifies, or conflicts with another provision that is required to be included in any of the Indentures related to such Note by the TIA, the required provision shall control.

[signature pages follow]
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IN WITNESS WHEREOF, the parties hereto have caused this Fourth Supplemental Indenture to be duly executed as of the day and year first above written.

CHENIERE ENERGY PARTNERS, L.P.
By its general partner, CHENIERE ENERGY
PARTNERS GP, LLC
/s/ Zach Davis
Name: Zach Davis
Title:
Senior Vice President and Chief
Financial Officer
CHENIERE ENERGY INVESTMENTS, LLC
/s/ Zach Davis
Name: Zach Davis
Title:
President and Chief Financial Officer
SABINE PASS LNG-GP, LLC
/s/ Zach Davis
Name: Zach Davis
Title:
Chief Financial Officer
SABINE PASS LNG, L.P.
By its general partner, SABINE PASS LNG-
GP, LLC
/s/ Zach Davis
Name: Zach Davis
Title:
Chief Financial Officer
[SIGNATURE PAGE TO FOURTH SUPPLEMENTAL INDENTURE]

SABINE PASS TUG SERVICES, LLC
/s/ Zach Davis
Name: Zach Davis
Title:
Chief Financial Officer
CHENIERE PIPELINE GP INTERESTS, LLC
/s/ Zach Davis
Name: Zach Davis
Title:
President and Chief Financial Officer
CHENIERE CREOLE TRAIL PIPELINE, L.P.
/s/ Zach Davis
Name: Zach Davis
Title:
Chief Financial Officer

[SIGNATURE PAGE TO FOURTH SUPPLEMENTAL INDENTURE]

THE BANK OF NEW YORK MELLON,
as Trustee
/s/ Francine J. Kincaid
Name: Francine J. Kincaid
Title:
Vice President
[SIGNATURE PAGE TO FOURTH SUPPLEMENTAL INDENTURE]

Exhibit 10.1
CHANGE ORDER
Third Berth Vapor Fence Provisional Sum Scope Removal and Closeout
PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility

OWNER: Sabine Pass Liquefaction, LLC

CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc.

DATE OF AGREEMENT: November 7, 2018
CHANGE ORDER NUMBER: CO-00023

DATE OF CHANGE ORDER: June 22, 2020

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (Change Orders Requested by Owner), the Parties agree this Change Order removes the Vapor Fence Provisional Sum from Contractor’s Scope of Work as defined in Section 2.7 of Attachment EE-4 (Provisional Sums to be Adjusted during Project Execution for Subproject 6(b)) of the Agreement.

2.The original value of the Vapor Fence Provisional Sum specified in Article 2.7 of Schedule EE-4 of Attachment EE of the Agreement was Fifteen Million, Eight Hundred Sixty-One Thousand U.S. Dollars (U.S. $15,861,000). Actual costs for the Vapor Fence Provisional Sum was Zero U.S. Dollars (U.S. $0.00). By way of this Change Order, the Vapor Fence Provisional Sum and Contract Price will be decreased by Sixteen Million, Eight Hundred Twelve Thousand, Six Hundred Sixty U.S. Dollars (U.S. $16,812,660), which reflects the closure of the Vapor Fence Provisional Sum and credit for the six percent (6%) fee.

3.Schedule C-3 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit A of this Change Order.

Adjustment to Contract Price Applicable to Subproject 6(a)
1. The original Contract Price Applicable to Subproject 6(a) was................................................................. $ 2,016,892,573 
2. Net change for Contract Price Applicable to Subproject 6(a) by previously authorized Change Orders (#00001-00008, 00010-00013, 00015, 00017-00018, and 00021-00022) $ (17,997,214)
3. The Contract Price Applicable to Subproject 6(a) prior to this Change Order was................................... $ 1,998,895,359 
4. The Contract Price Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of.................................................................................................................................................... $ — 
5. The Provisional Sum Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of.................................................................................................................................................... $ — 
6. The Contract Price Applicable to Subproject 6(a) including this Change Order will be................... $ 1,998,895,359 
Adjustment to Contract Price Applicable to Subproject 6(b)
7. The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was $ 457,696,000 
8. Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders (#00014, 00016, and 00019-00020) $ 20,551,502 
9. The Contract Price Applicable to Subproject 6(b) prior to this Change Order was.................................. $ 478,247,502 
10. The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order................... $ — 
11. The Provisional Sum Applicable to Subproject 6(b) will be decreased by this Change Order................ $ (16,812,660)
12. The new Contract Price Applicable to Subproject 6(b) including this Change Order will be................... $ 461,434,842 


Adjustment to Contract Price
13. The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7) $ 2,474,588,573 
14. The Contract Price prior to this Change Order was (add lines 3 and 9).................................................... $ 2,477,142,861 
15. The Contract Price will be decreased by this Change Order in the amount of (add lines 4, 5, 10 and 11)......... $ (16,812,660)
16. The new Contract Price including this Change Order will be (add lines 14 and 15) $ 2,460,330,201 

Adjustment to dates in Project Schedule for Subproject 6(a)
The following dates are modified: N/A
Adjustment to other Changed Criteria for Subproject 6(a): N/A
Adjustment to Payment Schedule for Subproject 6(a): N/A
Adjustment to Minimum Acceptance Criteria for Subproject 6(a): N/A
Adjustment to Performance Guarantees for Subproject 6(a): N/A
Adjustment to Design Basis for Subproject 6(a): N/A
Other adjustments to liability or obligations of Contractor or Owner under the Agreement for Subproject 6(a): N/A

Adjustment to dates in Project Schedule for Subproject 6(b)
The following dates are modified: N/A
Adjustment to other Changed Criteria for Subproject 6(b): N/A
Adjustment to Payment Schedule for Subproject 6(b): Yes; see Exhibit A
Adjustment to Design Basis for Subproject 6(b): N/A
Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A
Select either A or B:
[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ MDR Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.




/s/ David Craft /s/ Maurissa D. Rogers
Owner Contractor
David Craft Maurissa D. Rogers
Name Name
SVP E&C Sr Project Manager, PVP
Title Title
June 24, 2020 June 22, 2020
Date of Signing Date of Signing



CHANGE ORDER
Train 6 Thermowell Upgrades
PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility

OWNER: Sabine Pass Liquefaction, LLC

CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc.

DATE OF AGREEMENT: November 7, 2018
CHANGE ORDER NUMBER: CO-00024

DATE OF CHANGE ORDER: June 22, 2020

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (Change Orders Requested by Owner), the Parties agree this Change Order includes Contractor’s engineering and procurement costs to upgrade seventy-eight (78) Thermowells for Train 6 to accommodate an increased design flow of 861 MMSCFD in accordance with the recommendations of the debottlenecking study.

2.The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

3.Schedule C-3 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit B of this Change Order.

Adjustment to Contract Price Applicable to Subproject 6(a)
1. The original Contract Price Applicable to Subproject 6(a) was................................................................. $ 2,016,892,573 
2. Net change for Contract Price Applicable to Subproject 6(a) by previously authorized Change Orders (#01-08, 10-13, 15, 17-18 & 21-22) $ (17,997,214)
3. The Contract Price Applicable to Subproject 6(a) prior to this Change Order was................................... $ 1,998,895,359 
4. The Contract Price Applicable to Subproject 6(a) will be increased by this Change Order in the amount of.................................................................................................................................................... $ 205,198 
5. The Provisional Sum Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of.................................................................................................................................................... $ — 
6. The Contract Price Applicable to Subproject 6(a) including this Change Order will be................... $ 1,999,100,557 
Adjustment to Contract Price Applicable to Subproject 6(b)
7. The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was $ 457,696,000 
8. Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders (#14, 16, 19-20 & 23) $ 3,738,842 
9. The Contract Price Applicable to Subproject 6(b) prior to this Change Order was.................................. $ 461,434,842 
10. The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order................... $ — 
11. The Provisional Sum Applicable to Subproject 6(b) will be unchanged by this Change Order................ $ — 
12. The new Contract Price Applicable to Subproject 6(b) including this Change Order will be................... $ 461,434,842 
Adjustment to Contract Price
13. The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7) $ 2,474,588,573 
14. The Contract Price prior to this Change Order was (add lines 3 and 9).................................................... $ 2,460,330,201 
15. The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11) $ 205,198 
16. The new Contract Price including this Change Order will be (add lines 14 and 15)................................ $ 2,460,535,399 



Adjustment to dates in Project Schedule for Subproject 6(a)
The following dates are modified : N/A
Adjustment to other Changed Criteria for Subproject 6(a): N/A
Adjustment to Payment Schedule for Subproject 6(a): Yes; see Exhibit B
Adjustment to Minimum Acceptance Criteria for Subproject 6(a): N/A
Adjustment to Performance Guarantees for Subproject 6(a): N/A
Adjustment to Design Basis for Subproject 6(a): N/A
Other adjustments to liability or obligations of Contractor or Owner under the Agreement for Subproject 6(a): N/A
Adjustment to dates in Project Schedule for Subproject 6(b)
The following dates are modified: N/A
Adjustment to other Changed Criteria for Subproject 6(b): N/A
Adjustment to Payment Schedule for Subproject 6(b): N/A
Adjustment to Design Basis for Subproject 6(b): N/A
Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A
Select either A or B:
[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials:
/s/ MDR Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

/s/ David Craft /s/ Maurissa D. Rogers
Owner Contractor
David Craft Maurissa D. Rogers
Name Name
SVP E&C Sr Project Mgr, PVP
Title Title
June 24, 2020 June 22, 2020
Date of Signing Date of Signing



CHANGE ORDER
Third Berth Bubble Curtain
PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility

OWNER: Sabine Pass Liquefaction, LLC

CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc.

DATE OF AGREEMENT: November 7, 2018
CHANGE ORDER NUMBER: CO-00025

DATE OF CHANGE ORDER: June 22, 2020

The Agreement between the Parties listed above is changed as follows:
1.In accordance with Section 6.1 of the Agreement (Change Orders Requested by Owner), the Parties agree this Change Order includes Contractor’s engineering, procurement and construction costs to install a bubble curtain to mitigate noise levels during the marine steel piling program. Contractor is unable to quantify or guarantee the level of dBA reduction.

2.The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

3.Schedule C-3 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit B of this Change Order.

Adjustment to Contract Price Applicable to Subproject 6(a)
1. The original Contract Price Applicable to Subproject 6(a) was................................................................. $ 2,016,892,573 
2. Net change for Contract Price Applicable to Subproject 6(a) by previously authorized Change Orders (#01-08, 10-13, 15, 17-18, 21-22, & 24)) $ (17,792,016)
3. The Contract Price Applicable to Subproject 6(a) prior to this Change Order was................................... $ 1,999,100,557 
4. The Contract Price Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of.................................................................................................................................................... $ — 
5. The Provisional Sum Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of ................ $ — 
6. The Contract Price Applicable to Subproject 6(a) including this Change Order will be................... $ 1,999,100,557 
Adjustment to Contract Price Applicable to Subproject 6(b)
7. The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was................................................................ $ 457,696,000 
8. Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders (#14, 16, 19-20 & 23) $ 3,738,842 
9. The Contract Price Applicable to Subproject 6(b) prior to this Change Order was.................................. $ 461,434,842 
10. The Contract Price Applicable to Subproject 6(b) will be increased by this Change Order $ 2,991,140 
11. The Provisional Sum Applicable to Subproject 6(b) will be unchanged by this Change Order $ — 
12. The new Contract Price Applicable to Subproject 6(b) including this Change Order will be $ 464,425,982 
Adjustment to Contract Price
13. The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7) $ 2,474,588,573 
14. The Contract Price prior to this Change Order was (add lines 3 and 9).................................................... $ 2,460,535,399 
15. The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11) $ 2,991,140 
16. The new Contract Price including this Change Order will be (add lines 14 and 15)................................ $ 2,463,526,539 


Adjustment to dates in Project Schedule for Subproject 6(a)
The following dates are modified: N/A
Adjustment to other Changed Criteria for Subproject 6(a): N/A
Adjustment to Payment Schedule for Subproject 6(a): N/A
Adjustment to Minimum Acceptance Criteria for Subproject 6(a): N/A
Adjustment to Performance Guarantees for Subproject 6(a): N/A
Adjustment to Design Basis for Subproject 6(a): N/A
Other adjustments to liability or obligations of Contractor or Owner under the Agreement for Subproject 6(a): N/A
Adjustment to dates in Project Schedule for Subproject 6(b)
The following dates are modified: N/A
Adjustment to other Changed Criteria for Subproject 6(b): N/A
Adjustment to Payment Schedule for Subproject 6(b): Yes; see Exhibit B
Adjustment to Design Basis for Subproject 6(b): N/A
Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A
Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ MDR Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner
Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

/s/ David Craft /s/ Maurissa D. Rogers
Owner Contractor
David Craft Maurissa D. Rogers
Name Name
SVP E&C Sr Project Mgr, PVP
Title Title
June 24, 2020 June 22, 2020
Date of Signing Date of Signing



CHANGE ORDER
Third Berth Fuel Provisional Sum Closure Change Order
PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility

OWNER: Sabine Pass Liquefaction, LLC

CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc.

DATE OF AGREEMENT: November 7, 2018
CHANGE ORDER NUMBER: CO-00026

DATE OF CHANGE ORDER: July 14, 2020

The Agreement between the Parties listed above is changed as follows:
1.The Fuel Provisional Sum in Article 1.2 of Attachment EE, Schedule EE-3 of the Agreement prior to this Change Order was One Million, Five Hundred Seventy-Eight Thousand, Seventy-Four U.S. Dollars (U.S. $1,578,074). The Provisional Sum is hereby decreased by Three Hundred Fourteen Thousand, Five Hundred Seventy-Four U.S. Dollars (U.S. $314,574), and the final value as amended by this Change Order shall be One Million, Two Hundred Sixty-Three Thousand, Five Hundred U.S. Dollars (U.S. $1,263,500). This Change Order closes the Fuel Provisional Sum for Subproject 6(b) in accordance with Article 1.2 of Attachment EE, Schedule EE-3 of the Agreement.

2.Pursuant to instructions in Article 1.2 of Attachment EE, Schedule EE-3 of the Agreement, Exhibit A to this Change Order illustrates the calculation of the final fuel costs in the Agreement with respect to Subproject 6(b).

3.Schedules C-1 and C-2 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestones listed in Exhibit B of this Change Order.

4.Additionally, Exhibit C of this Change Order supersedes the Exhibit B (Payment Milestones Schedule) of Change Order No. 00020 to correct Milestone No. “TB2.02c020” to “TB3.01c020” in accordance with Schedule C-3 (Milestone Payment Schedule for Subproject 6(b)) of Attachment C of the Agreement.
Adjustment to Contract Price Applicable to Subproject 6(a)
1. The original Contract Price Applicable to Subproject 6(a) was................................................................. $ 2,016,892,573 
2. Net change for Contract Price Applicable to Subproject 6(a) by previously authorized Change Orders (#01-08, 10-13, 15, 17-18, 21-22, & 24) $ (17,792,016)
3. The Contract Price Applicable to Subproject 6(a) prior to this Change Order was................................... $ 1,999,100,557 
4. The Contract Price Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of.................................................................................................................................................... $ — 
5. The Provisional Sum Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of.................................................................................................................................................... $ — 
6. The Contract Price Applicable to Subproject 6(a) including this Change Order will be................... $ 1,999,100,557 
Adjustment to Contract Price Applicable to Subproject 6(b)
7. The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was $ 457,696,000 
8. Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders (#14, 16, 19-20, 23 & 25) $ 6,729,982 
9. The Contract Price Applicable to Subproject 6(b) prior to this Change Order was.................................. $ 464,425,982 
10. The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order................... $ — 
11. The Provisional Sum Applicable to Subproject 6(b) will be decreased by this Change Order................ $ (314,574)
12. The new Contract Price Applicable to Subproject 6(b) including this Change Order will be................... $ 464,111,408 


Adjustment to Contract Price
13. The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7) $ 2,474,588,573 
14. The Contract Price prior to this Change Order was (add lines 3 and 9).................................................... $ 2,463,526,539 
15. The Contract Price will be decreased by this Change Order in the amount of (add lines 4, 5, 10 and 11) $ (314,574)
16. The new Contract Price including this Change Order will be (add lines 14 and 15)................................ $ 2,463,211,965 
Adjustment to dates in Project Schedule for Subproject 6(a)
The following dates are modified: N/A
Adjustment to other Changed Criteria for Subproject 6(a): N/A
Adjustment to Payment Schedule for Subproject 6(a): N/A
Adjustment to Minimum Acceptance Criteria for Subproject 6(a): N/A
Adjustment to Performance Guarantees for Subproject 6(a): N/A
Adjustment to Design Basis for Subproject 6(a): N/A
Other adjustments to liability or obligations of Contractor or Owner under the Agreement for Subproject 6(a): N/A
Adjustment to dates in Project Schedule for Subproject 6(b)
The following dates are modified: N/A
Adjustment to other Changed Criteria for Subproject 6(b): N/A
Adjustment to Payment Schedule for Subproject 6(b): Yes; see Exhibit B and Exhibit C
Adjustment to Design Basis for Subproject 6(b): N/A
Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A
Select either A or B:
[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ MDR Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner
Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.


/s/ David Craft /s/ Maurissa D. Rogers
Owner Contractor
David Craft Maurissa D. Rogers
Name Name
SVP E&C Sr Project Mgr, PVP
Title Title
July 23, 2020 July 14, 2020
Date of Signing Date of Signing



CHANGE ORDER
Third Berth Currency Provisional Sum Closure Change Order
PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility

OWNER: Sabine Pass Liquefaction, LLC

CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc.

DATE OF AGREEMENT: November 7, 2018
CHANGE ORDER NUMBER: CO-00027

DATE OF CHANGE ORDER: July 20, 2020

The Agreement between the Parties listed above is changed as follows:
1.The Currency Provisional Sum in Article 1.1 of Attachment EE, Schedule EE-3 of the Agreement prior to this Change Order was Seven Million, One Hundred Seventy-Five Thousand, One Hundred Ninety-Six U.S. Dollars (U.S. $7,175,196). The Provisional Sum is hereby decreased by Three Hundred Three Thousand, Nine Hundred Fifty-Five U.S. Dollars (U.S. $303,955), and the final value as amended by this Change Order shall be Six Million, Eight Hundred Seventy-One Thousand, Two Hundred Forty-One U.S. Dollars (U.S. $6,871,241). This Change Order closes the Currency Provisional Sum for Subproject 6(b) in accordance with Article 1.1 of Attachment EE, Schedule EE-3 of the Agreement.

2.Pursuant to instructions in Article 1.1 of Attachment EE, Schedule EE-3 of the Agreement, Exhibit A to this Change Order illustrates the calculation of the final currency costs in the Agreement with respect to Subproject 6(b).

3.Exhibit C of this Change Order includes the detailed spot and forward trades used to calculate the final currency costs in the Agreement with respect to Subproject 6(b).

4.Schedules C-1 and C-2 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestones listed in Exhibit B of this Change Order.
Adjustment to Contract Price Applicable to Subproject 6(a)
1. The original Contract Price Applicable to Subproject 6(a) was................................................................. $ 2,016,892,573 
2. Net change for Contract Price Applicable to Subproject 6(a) by previously authorized Change Orders (#01-08, 10-13, 15, 17-18, 21-22, & 24) $ (17,792,016)
3. The Contract Price Applicable to Subproject 6(a) prior to this Change Order was................................... $ 1,999,100,557 
4. The Contract Price Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of.................................................................................................................................................... $ — 
5. The Provisional Sum Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of.................................................................................................................................................... $ — 
6. The Contract Price Applicable to Subproject 6(a) including this Change Order will be................... $ 1,999,100,557 
Adjustment to Contract Price Applicable to Subproject 6(b)
7. The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was $ 457,696,000 
8. Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders (#14, 16, 19-20, 23, & 25-26) $ 6,415,408 
9. The Contract Price Applicable to Subproject 6(b) prior to this Change Order was.................................. $ 464,111,408 
10. The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order................... $ — 
11. The Provisional Sum Applicable to Subproject 6(b) will be unchanged by this Change Order................ $ (303,955)
12. The new Contract Price Applicable to Subproject 6(b) including this Change Order will be................... $ 463,807,453 


Adjustment to Contract Price
13. The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7) $ 2,474,588,573 
14. The Contract Price prior to this Change Order was (add lines 3 and 9).................................................... $ 2,463,211,965 
15. The Contract Price will be decreased by this Change Order in the amount of (add lines 4, 5, 10 and 11) $ (303,955)
16. The new Contract Price including this Change Order will be (add lines 14 and 15)................................ $ 2,462,908,010 
Adjustment to dates in Project Schedule for Subproject 6(a)
The following dates are modified: N/A
Adjustment to other Changed Criteria for Subproject 6(a): N/A
Adjustment to Payment Schedule for Subproject 6(a): N/A
Adjustment to Minimum Acceptance Criteria for Subproject 6(a): N/A
Adjustment to Performance Guarantees for Subproject 6(a): N/A
Adjustment to Design Basis for Subproject 6(a): N/A
Other adjustments to liability or obligations of Contractor or Owner under the Agreement for Subproject 6(a): N/A

Adjustment to dates in Project Schedule for Subproject 6(b)
The following dates are modified: N/A
Adjustment to other Changed Criteria for Subproject 6(b): N/A
Adjustment to Payment Schedule for Subproject 6(b): Yes; see Exhibit B
Adjustment to Design Basis for Subproject 6(b): N/A
Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A
Select either A or B

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ MDR Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner
Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.



/s/ David Craft /s/ Maurissa D. Rogers
Owner Contractor
David Craft Maurissa D. Rogers
Name Name
SVP E&C Sr Project Mgr, PVP
Title Title
July 30, 2020 July 20, 2020
Date of Signing Date of Signing



CHANGE ORDER

Train 6 Hot Oil WHRU PSV Bypass
PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility

OWNER: Sabine Pass Liquefaction, LLC

CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc.

DATE OF AGREEMENT: November 7, 2018
CHANGE ORDER NUMBER: CO-00028

DATE OF CHANGE ORDER: August 11, 2020

The Agreement between the Parties listed above is changed as follows:
1.In accordance with Section 6.1 of the Agreement (Change Orders Requested by Owner), the Parties agree this Change Order includes Contractor’s engineering, procurement and construction services to actuate the PSV bypass valves and automate their operation based on pressure measurements as reflected in the draft P&ID markups in Exhibit C of this Change Order, and based on the following Scope of Work:

1.1This Change Order is based on valve failure position being FO. Any other failure position other than FO is specifically excluded from this Change Order.

1.2Existing orbit manual valve on thermal oxidizer WHRU (VA-342263) is required to be in open position prior to installation of actuator. The ball valves on the ethylene WHRUs (VA-340198, VA-340113) can be in closed position (subject to confirmation during detailed design). Stroking of the valves will be required to confirm proper actuator operation during the installation phase.

1.3Existing orbit manual valve on thermal oxidizer WHRU (VA-342263) needs to be rotated 45 deg to accommodate clash-free installation of actuator, based on preliminary vendor data.

2.The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

3.Schedule C-3 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit B of this Change Order.
Adjustment to Contract Price Applicable to Subproject 6(a)
1. The original Contract Price Applicable to Subproject 6(a) was................................................................. $ 2,016,892,573 
2. Net change for Contract Price Applicable to Subproject 6(a) by previously authorized Change Orders (#01-08, 10-13, 15, 17-18, 21-22, & 24) $ (17,792,016)
3. The Contract Price Applicable to Subproject 6(a) prior to this Change Order was................................... $ 1,999,100,557 
4. The Contract Price Applicable to Subproject 6(a) will be increased by this Change Order in the amount of.................................................................................................................................................... $ 231,381 
5. The Provisional Sum Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of.................................................................................................................................................... $ — 
6. The new Contract Price Applicable to Subproject 6(a) including this Change Order will be................... $ 1,999,331,938 
Adjustment to Contract Price Applicable to Subproject 6(b)
7. The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was $ 457,696,000 
8. Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders (#14, 16, 19-20, 23, & 25-27) $ 6,111,453 
9. The Contract Price Applicable to Subproject 6(b) prior to this Change Order was.................................. $ 463,807,453 
10. The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order................... $ — 
11. The Provisional Sum Applicable to Subproject 6(b) will be unchanged by this Change Order................ $ — 
12. The Contract Price Applicable to Subproject 6(b) including this Change Order will be................... $ 463,807,453 


Adjustment to Contract Price
13. The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7) $ 2,474,588,573 
14. The Contract Price prior to this Change Order was (add lines 3 and 9).................................................... $ 2,462,908,010 
15. The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11) $ 231,381 
16. The new Contract Price including this Change Order will be (add lines 14 and 15)................................ $ 2,463,139,391 
Adjustment to dates in Project Schedule for Subproject 6(a)
The following dates are modified: N/A
Adjustment to other Changed Criteria for Subproject 6(a): N/A
Adjustment to Payment Schedule for Subproject 6(a): Yes; see Exhibit B
Adjustment to Minimum Acceptance Criteria for Subproject 6(a): N/A
Adjustment to Performance Guarantees for Subproject 6(a): N/A
Adjustment to Design Basis for Subproject 6(a): N/A
Other adjustments to liability or obligations of Contractor or Owner under the Agreement for Subproject 6(a): N/A
Adjustment to dates in Project Schedule for Subproject 6(b)
The following dates are modified: N/A
Adjustment to other Changed Criteria for Subproject 6(b): N/A
Adjustment to Payment Schedule for Subproject 6(b): N/A
Adjustment to Design Basis for Subproject 6(b): N/A
Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A
Select either A or B:
[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ MDR Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner
Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.



/s/ David Craft /s/ Maurissa D. Rogers
Owner Contractor
David Craft Maurissa D. Rogers
Name Name
SVP E&C Sr Project Mgr, PVP
Title Title
August 24, 2020 August 11, 2020
Date of Signing Date of Signing



CHANGE ORDER

Change in Law IMO 2020 Regulatory Change – Low Sulphur Emissions on Marine Vessels
PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility

OWNER: Sabine Pass Liquefaction, LLC

CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc.

DATE OF AGREEMENT: November 7, 2018
CHANGE ORDER NUMBER: CO-00029

DATE OF CHANGE ORDER: August 25, 2020

The Agreement between the Parties listed above is changed as follows:
1.In accordance with Section 6.2 of the Agreement (Change Orders Requested by Contractor), the Parties agree this Change Order includes Contractor’s incurred costs as a result of the Change in Law – International Maritime Organization ("IMO") enforcement of a new 0.5% global Sulphur cap on all shipping vessels effective January 1, 2020.

2.The summary cost breakdown for this Change Order is provided in Exhibit A of this Change Order.

3.The detailed cost breakdown for this Change Order is provided in Exhibit C of this Change Order.

4.Schedule C-3 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit B of this Change Order.
Adjustment to Contract Price Applicable to Subproject 6(a)
1. The original Contract Price Applicable to Subproject 6(a) was................................................................. $ 2,016,892,573 
2. Net change for Contract Price Applicable to Subproject 6(a) by previously authorized Change Orders (#01-08, 10-13, 15, 17-18, 21-22, 24, & 28) $ (17,560,635)
3. The Contract Price Applicable to Subproject 6(a) prior to this Change Order was................................... $ 1,999,331,938 
4. The Contract Price Applicable to Subproject 6(a) will be increased by this Change Order in the amount of.................................................................................................................................................... $ 718,581 
5. The Provisional Sum Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of.................................................................................................................................................... $ — 
6. The new Contract Price Applicable to Subproject 6(a) including this Change Order will be................... $ 2,000,050,519 
Adjustment to Contract Price Applicable to Subproject 6(b)
7. The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was $ 457,696,000 
8. Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders (#14, 16, 19-20, 23, & 25-27) $ 6,111,453 
9. The Contract Price Applicable to Subproject 6(b) prior to this Change Order was.................................. $ 463,807,453 
10. The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order................... $ — 
11. The Provisional Sum Applicable to Subproject 6(b) will be unchanged by this Change Order................ $ — 
12. The Contract Price Applicable to Subproject 6(b) including this Change Order will be................... $ 463,807,453 
Adjustment to Contract Price
13. The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7) $ 2,474,588,573 
14. The Contract Price prior to this Change Order was (add lines 3 and 9).................................................... $ 2,463,139,391 
15. The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11) $ 718,581 
16. The new Contract Price including this Change Order will be (add lines 14 and 15)................................ $ 2,463,857,972 


Adjustment to dates in Project Schedule for Subproject 6(a)
The following dates are modified: N/A
Adjustment to other Changed Criteria for Subproject 6(a): N/A
Adjustment to Payment Schedule for Subproject 6(a): Yes; see Exhibit B
Adjustment to Minimum Acceptance Criteria for Subproject 6(a): N/A
Adjustment to Performance Guarantees for Subproject 6(a): N/A
Adjustment to Design Basis for Subproject 6(a): N/A
Other adjustments to liability or obligations of Contractor or Owner under the Agreement for Subproject 6(a): N/A
Adjustment to dates in Project Schedule for Subproject 6(b)
The following dates are modified: N/A
Adjustment to other Changed Criteria for Subproject 6(b): N/A
Adjustment to Payment Schedule for Subproject 6(b): N/A
Adjustment to Design Basis for Subproject 6(b): N/A
Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A
Select either A or B:
[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ MDR Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner
Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

/s/ David Craft /s/ Maurissa D. Rogers
Owner Contractor
David Craft Maurissa D. Rogers
Name Name
SVP, Engineering and Construction Sr Project Mgr, PVP
Title Title
August 26, 2020 August 25, 2020
Date of Signing Date of Signing



Exhibit 31.1
CERTIFICATION BY CHIEF EXECUTIVE OFFICER
PURSUANT TO RULE 13a-14(a) AND 15d-14(a) UNDER THE EXCHANGE ACT
I, Jack A. Fusco, certify that:
1.    I have reviewed this quarterly report on Form 10-Q of Cheniere Energy Partners, L.P.;
2.    Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.    Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.    The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)    Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)    Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)    Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;
d)    Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.    The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a)    All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)    Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 5, 2020
/s/ Jack A. Fusco
Jack A. Fusco
Chief Executive Officer of
Cheniere Energy Partners GP, LLC, the general partner of
Cheniere Energy Partners, L.P.



Exhibit 31.2
CERTIFICATION BY CHIEF FINANCIAL OFFICER
PURSUANT TO RULE 13a-14(a) AND 15d-14(a) UNDER THE EXCHANGE ACT
I, Zach Davis, certify that:
1.    I have reviewed this quarterly report on Form 10-Q of Cheniere Energy Partners, L.P.;
2.    Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.    Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.    The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)    Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)    Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)    Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;
d)    Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.    The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a)    All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)    Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
 
Date: November 5, 2020
/s/ Zach Davis
Zach Davis
Chief Financial Officer of
Cheniere Energy Partners GP, LLC, the general partner of
Cheniere Energy Partners, L.P.



Exhibit 32.1
CERTIFICATION BY CHIEF EXECUTIVE OFFICER
PURSUANT TO 18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the quarterly report of Cheniere Energy Partners, L.P. (the “Partnership”) on Form 10-Q for the quarter ended September 30, 2020, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jack A. Fusco, Chief Executive Officer of Cheniere Energy Partners GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:
(1)    The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)    The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.
 
Date: November 5, 2020
/s/ Jack A. Fusco
Jack A. Fusco
Chief Executive Officer of
Cheniere Energy Partners GP, LLC, the general partner of
Cheniere Energy Partners, L.P.




Exhibit 32.2
CERTIFICATION BY CHIEF FINANCIAL OFFICER
PURSUANT TO 18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the quarterly report of Cheniere Energy Partners, L.P. (the “Partnership”) on Form 10-Q for the quarter ended September 30, 2020, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Zach Davis, Chief Financial Officer of Cheniere Energy Partners GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:
(1)    The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)    The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: November 5, 2020
/s/ Zach Davis
Zach Davis
Chief Financial Officer of
Cheniere Energy Partners GP, LLC, the general partner of
Cheniere Energy Partners, L.P.