CQP 2013 Form 10Q 3rd Qtr

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


T	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2013


£	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File No. 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 800 Houston, Texas	77002
(Address of principal executive offices)	(Zip Code)

(713) 375-5000

(Registrant's telephone number, including area code)

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 x No £

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No £

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):



Large accelerated filer £	Accelerated filer T
Non-accelerated filer £	Smaller reporting company £
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes £ No T

As of October 16, 2013, the issuer had 57,078,848 common units, 145,333,334 Class B units and 135,383,831 subordinated units outstanding.

CHENIERE ENERGY PARTNERS, L.P.

TABLE OF CONTENTS



Part I. Financial Information

Item 1.	Consolidated Financial Statements	1
	Consolidated Balance Sheets	1
	Consolidated Statements of Operations	2
	Consolidated Statements of Comprehensive Loss	3
	Consolidated Statements of Partners' and Owners' Equity	4
	Consolidated Statements of Cash Flows	5
	Notes to Consolidated Financial Statements	6

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	26

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	39

Item 4.	Controls and Procedures	40

Part II. Other Information

Item 1.	Legal Proceedings	40

Item 5.	Other Information	40

Item 6.	Exhibits	41

PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)



	September 30,			December 31,
	2013			2012 (1)
ASSETS	(unaudited)
Current assets
Cash and cash equivalents	$	339,895		$	419,292
Restricted cash and cash equivalents	210,076			92,519
Accounts and interest receivable	21,214			44
Advances to affiliate	25,737			4,987
LNG inventory	14,158			2,625
Prepaid expenses and other	7,884			7,084
Other—affiliate	4,255			6,572
Total current assets	623,219			533,123
Non-current restricted cash and cash equivalents	828,360			272,425
Property, plant and equipment, net	5,642,872			3,219,592
Debt issuance costs, net	340,856			220,949
Non-current derivative assets	64,309			—
Advances under long-term contracts	12,528			—
Other	58,574			19,698
Total assets	$	7,570,718		$	4,265,787

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	4,739		$	73,760
Accrued liabilities	141,788			47,848
Due to affiliates	52,474			7,562
Deferred revenue	26,585			26,540
Other	8,292			126
Total current liabilities	233,878			155,836

Long-term debt, net of discount	5,574,195			2,167,113
Deferred revenue	18,500			21,500
Deferred revenue—affiliate	17,173			14,720
Non-current derivative liabilities	—			26,424
Other non-current liabilities	1,209			216
Commitments and contingencies

Partners' equity
Creole Trail Pipeline Business equity	—			517,170
Common unitholders' interest (57.1 million units and 39.5 million units issued and outstanding at September 30, 2013 and December 31, 2012, respectively)	754,551			448,412
Class B unitholders' interest (145.3 million units and 133.3 million units issued and outstanding at September 30, 2013 and December 31, 2012, respectively)	(38,216		)	(37,342		)
Subordinated unitholders' interest (135.4 million units issued and outstanding at September 30, 2013 and December 31, 2012)	975,124			949,482
General partner's interest (2% interest with 6.9 million units and 6.3 million units issued and outstanding at September 30, 2013 and December 31, 2012, respectively)	34,304			29,496
Accumulated other comprehensive loss	—			(27,240		)
Total partners’ equity	1,725,763			1,879,978
Total liabilities and partners’ equity	$	7,570,718		$	4,265,787

(1) Retrospectively adjusted as discussed in Note 2.

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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(unaudited)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012 (1)			2013			2012 (1)
Revenues
Revenues	$	66,646		$	62,429		$	199,052		$	190,160
Revenues—affiliate	800			3,929			2,140			6,973
Total revenues	67,446			66,358			201,192			197,133

Expenses
Operating and maintenance expense	23,553			6,395			52,751			20,063
Operating and maintenance expense—affiliate	6,314			7,711			23,534			14,486
Depreciation expense	14,491			14,489			43,150			43,135
Development expense	1,355			4,229			8,157			35,369
Development expense—affiliate	133			102			1,195			2,365
General and administrative expense	2,718			4,737			8,521			9,235
General and administrative expense—affiliate	42,239			36,871			101,998			48,745
Total expenses	90,803			74,534			239,306			173,398

Income (loss) from operations	(23,357		)	(8,176		)	(38,114		)	23,735

Other income (expense)
Interest expense, net	(52,528		)	(43,626		)	(134,806		)	(130,554		)
Loss on early extinguishment of debt	—			—			(80,510		)	—
Derivative gain (loss), net	(22,335		)	287			55,706			(288		)
Other	111			145			873			289
Total other expense	(74,752		)	(43,194		)	(158,737		)	(130,553		)
Net loss	(98,109		)	(51,370		)	(196,851		)	(106,818		)
Net income (loss) attributable to the Creole Trail Pipeline Business	244			(8,948		)	(18,150		)	(20,203		)
Net loss attributable to partners	$	(98,353	)	$	(42,422	)	$	(178,701	)	$	(86,615	)

Basic and diluted net income (loss) per common unit	$	(0.20	)	$	0.04		$	(0.01	)	$	0.36

Weighted average number of common units outstanding used for basic and diluted net income per common unit calculation	57,079			31,997			53,277			31,449

(1) Retrospectively adjusted as discussed in Note 2.

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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(in thousands)

(unaudited)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012 (1)			2013			2012 (1)
Net loss	$	(98,109	)	$	(51,370	)	$	(196,851	)	$	(106,818	)
Other comprehensive income
Interest rate cash flow hedges
Loss on settlements retained in other comprehensive income	—			—			(30		)	—
Change in fair value of interest rate cash flow hedges	—			(29,676		)	21,297			(29,676		)
Losses reclassified into earnings as a result of discontinuance of cash flow hedge accounting							5,973
Total other comprehensive income	—			(29,676		)	27,240			(29,676		)
Comprehensive loss	$	(98,109	)	$	(81,046	)	$	(169,611	)	$	(136,494	)

(1) Retrospectively adjusted as discussed in Note 2.

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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ AND

OWNERS’ EQUITY

(in thousands)

(unaudited)



	Common Unitholders' Interest				Class B Unitholders' Interest				Subordinated Unitholder's Interest				General Partner's Interest				Accumulated Other Comprehensive Loss			Creole Trail Pipeline Business Equity			Total Partners' Equity
	Units	Amount			Units	Amount			Units	Amount			Units	Amount			Accumulated Other Comprehensive Loss			Creole Trail Pipeline Business Equity			Total Partners' Equity
Balance at December 31, 2012 (1)	39,488	$	448,412		133,333	$	(37,342	)	135,384	$	949,482		6,290	$	29,496		$	(27,240	)	$	517,170		$	1,879,978
Net loss	—	(48,741		)	—	—			—	(123,855		)	—	(6,105		)	—			(18,150		)	(196,851		)
Contributions to Creole Trail Pipeline Business from Cheniere, net	—	—			—	—			—	—			—	—			—			20,896			20,896
Acquisition of Creole Trail Pipeline Business	—	—			—	—			—	—			—	—			—			(519,916		)	(519,916		)
Excess of acquired assets over the purchase price		2,022			—	—			—	22,880			—	1,124			—			—			26,026
Issuance of Class B units associated with acquisition of Creole Trail Pipeline Business	—	—			12,000	179,126			—	—			—	—			—			—			179,126
Sale of common and general partner units	17,590	364,775			—	—			—	—			604	11,122			—			—			375,897
Distributions	—	(65,300		)	—	—			—	—			—	(1,333		)	—			—			(66,633		)
Interest rate cash flow hedges	—	—			—	—			—	—			—	—			27,240			—			27,240
Beneficial conversion feature of Class B units	—	53,383			—	(180,000		)	—	126,617			—	—			—			—			—
Balance at September 30, 2013	57,078	$	754,551		145,333	$	(38,216	)	135,384	$	975,124		6,894	$	34,304		$	—		$	—		$	1,725,763

(1) Retrospectively adjusted as discussed in Note 2.

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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)



	Nine Months Ended
	September 30,
	2013			2012 (1)
Cash flows from operating activities
Net loss	$	(196,851	)	$	(106,818	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation	43,150			43,135
Use of restricted cash and cash equivalents for certain operating activities	147,982			36,676
Release of (investment in) restricted cash and cash equivalents	(35,627		)	(41,197		)
Non-cash LNG inventory write-downs	27,851			9,237
Amortization of debt discount	5,208			3,521
Amortization of debt issuance costs	3,383			8,373
Non-cash derivative (gain) loss, net	(55,049		)	300
Loss on early extinguishment of debt	80,510			—
Other	705			3,736
Changes in operating assets and liabilities:
Accounts and interest receivable	(21,171		)	(24,619		)
Accounts receivable—affiliate	(1,614		)	(855		)
Accounts payable and accrued liabilities	38,655			41,463
Due to affiliates	33,556			29,218
Deferred revenue	(2,955		)	(3,104		)
Advances to affiliate	(20,281		)	(3,627		)
LNG inventory	(33,248		)	(9,519		)
Other	(34,376		)	(4,003		)
Other—affiliate	4,081			3,143
Net cash used in operating activities	(16,091		)	(14,940		)

Cash flows from investing activities
LNG terminal costs, net	(2,449,360		)	(876,593		)
Use of restricted cash and cash equivalents for the acquisition of property, plant and equipment	2,457,823			887,902
Purchase of Creole Trail Pipeline Business, net	(313,892		)	—
Advances under long-term contracts	(12,528		)	(15,009		)
Other	(5,120		)	(2,382		)
Net cash used in investing activities	(323,077		)	(6,082		)
	.
Cash flows from financing activities
Proceeds from Sabine Pass Liquefaction Senior Notes, net	3,012,500			—
Proceeds from CTPL Credit Facility, net	391,978			—
Proceeds from 2013 Liquefaction Credit Facilities	100,000			—
Proceeds from sale of partnership common and general partner units, net	375,897			240,114
Proceeds from sale of Class B units	—			1,387,560
Contributions to Creole Trail Pipeline Business from Cheniere, net	20,896			9,608
Investment in restricted cash and cash equivalents	(3,243,670		)	(1,177,753		)
Debt issuance and deferred financing costs	(231,198		)	(210,126		)
Proceeds from (repayment of) 2012 Liquefaction Credit Facility	(100,000		)	100,000
Distributions to owners	(66,632		)	(40,696		)
Net cash provided by financing activities	259,771			308,707

Net increase (decrease) in cash and cash equivalents	(79,397		)	287,685
Cash and cash equivalents—beginning of period	$	419,292		81,415
Cash and cash equivalents—end of period	$	339,895		$	369,100

(1) Retrospectively adjusted as discussed in Note 2.

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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

Cheniere Energy Partners, L.P. ("Cheniere Partners") is a publicly-traded Delaware limited partnership formed on November 21, 2006 by Cheniere Energy, Inc. ("Cheniere"). Unless the context requires otherwise, references to "Cheniere Partners", "we", "us" and "our" refer to Cheniere Partners and its subsidiaries.

We were formed to own and operate the Sabine Pass liquefied natural gas ("LNG") terminal located on the Sabine Pass deep water shipping channel less than four miles from the Gulf Coast. The Sabine Pass LNG terminal has regasification facilities owned by our wholly owned subsidiary, Sabine Pass LNG, L.P. ("Sabine Pass LNG"), that includes existing infrastructure of five LNG storage tanks with capacity of approximately 16.9 Bcfe, two docks that can accommodate vessels with capacity of up to 265,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. Approximately one-half of the receiving capacity at the Sabine Pass LNG terminal is contracted to two multinational energy companies.

We are developing natural gas liquefaction facilities (the "Liquefaction Project") at the Sabine Pass LNG terminal adjacent to the existing regasification facilities through a wholly owned subsidiary, Sabine Pass Liquefaction, LLC ("Sabine Pass Liquefaction"). We plan to construct up to six Trains, which are in various stages of development. Each Train is expected to have nominal production capacity of approximately 4.5 million tonnes per annum ("mtpa") of LNG.

In May 2013, we acquired Cheniere's ownership interests in Cheniere Creole Trail Pipeline, L.P. ("CTPL") and Cheniere Pipeline GP Interests, LLC (collectively, the "Creole Trail Pipeline Business"), thereby providing us with ownership of a 94-mile pipeline interconnecting the Sabine Pass LNG terminal with a number of large interstate pipelines (the "Creole Trail Pipeline"). We acquired the Creole Trail Pipeline Business for $480.0 million and reimbursed Cheniere $13.9 million for certain expenditures incurred prior to the closing date. Concurrent with the Creole Trail Pipeline Business acquisition closing, we issued 12.0 million Class B units to Cheniere at a price of $15.00 per Class B unit for aggregate consideration of $180.0 million pursuant to a unit purchase agreement with Cheniere Class B Units Holdings, LLC, a wholly owned subsidiary of Cheniere. As a result of the two transactions, we paid Cheniere net cash of $313.9 million. See Note 2—"Basis of Presentation".

NOTE 2—BASIS OF PRESENTATION

The accompanying unaudited Consolidated Financial Statements of Cheniere Energy Partners, L.P. have been prepared in accordance with generally accepted accounting principles in the United States ("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. In our opinion, all adjustments, consisting only of normal recurring adjustments necessary for a fair presentation, have been included.

These consolidated financial statements include our accounts and the assets, liabilities and operations of the Creole Trail Pipeline Business. The effect of including the prior results of the Creole Trail Pipeline Business is reported as net loss attributable to Creole Trail Pipeline Business in our Consolidated Statement of Operations and Creole Trail Pipeline Business equity in our Consolidated Balance Sheets and Consolidated Statements of Partners' and Owners' Equity. This purchase has been accounted for as a transfer of net assets between entities under common control.

We recognize transfers of net assets between entities under common control at Cheniere's historical basis in the net assets sold. In addition, transfers of net assets between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information. The difference between the purchase price and Cheniere's basis in the net assets sold, if any, is recognized as an adjustment to partners' equity.

Subsequent to the Creole Trail Pipeline Business acquisition, we control CTPL's operating and financial decisions and policies and have consolidated CTPL in our financial statements. Our consolidated financial statements and all other financial information included in this report have been retrospectively adjusted to assume that our acquisition of the Creole Trail Pipeline Business from Cheniere had occurred at the date when the Creole Trail Pipeline Business met the accounting requirements for entities under common control (the date of our inception since both we and the Creole Trail Pipeline Business were formed by Cheniere). Net income (loss) attributable to the Creole Trail Pipeline Business for periods prior to the acquisition is not allocated to the common units for purposes of calculating net income (loss) per common unit.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Results of operations for the three and nine months ended September 30, 2013 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2013.

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.

Certain reclassifications have been made to prior period information to conform to the current presentation. The reclassifications had no effect on our overall consolidated financial position, results of operations or cash flows. For further information, refer to the consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, 2012, as amended by Amendment No. 1 on Form 10-K/A.

NOTE 3—RESTRICTED CASH AND CASH EQUIVALENTS

Restricted cash and cash equivalents consist of funds that are contractually restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets.

Certain amounts that are designated as restricted cash and cash equivalents are contractually restricted as to usage or withdrawal for a certain amount of time. Prior to being restricted and after the restriction is lifted such amounts flow though cash and cash equivalents. For these amounts, we have presented increases and decreases as "Investments in (releases of) restricted cash and cash equivalents" in our Consolidated Statement of Cash Flows.

Certain other amounts that are designated as restricted cash and cash equivalents are contractually restricted as to usage or withdrawal and will not become available to us as cash and cash equivalents. For these amounts, we have presented increases and decreases as "Investments in (uses of) of restricted cash and cash equivalents" in our Consolidated Statement of Cash Flows. These amounts that represent non-cash transactions within our Consolidated Statement of Cash Flows present the effect of sources and uses of restricted cash and cash equivalents as they relate to the changes to assets and liabilities in our Consolidated Balance Sheets. This presentation does not impact the total amount of operating, investing or financing cash flows related to these items, however , they are presented on a gross basis within each of those categories so as to reconcile the change in non-cash activity that occurs on the balance sheet from period to period.

Restricted cash and cash equivalents include the following:

Sabine Pass LNG Senior Notes Debt Service Reserve

Sabine Pass LNG has consummated private offerings of an aggregate principal amount of $1,665.5 million, before discount, of Senior Secured Notes due 2016 (the "2016 Notes") and $420.0 million of Senior Secured Notes due 2020 (the "2020 Notes"). See Note 7—"Long-Term Debt". Collectively, the 2016 Notes and the 2020 Notes are referred to as the "Sabine Pass LNG Senior Notes." Under the indentures governing the Sabine Pass LNG Senior Notes (the "Sabine Pass LNG Indentures"), except for permitted tax distributions, Sabine Pass LNG may not make distributions until certain conditions are satisfied, including that there must be on deposit in an interest payment account an amount equal to one-sixth of the semi-annual interest payment multiplied by the number of elapsed months since the last semi-annual interest payment and there must be on deposit in a permanent debt service reserve fund an amount equal to one semi-annual interest payment. Distributions are permitted only after satisfying the foregoing funding requirements, a fixed charge coverage ratio test of 2:1 and other conditions specified in the Sabine Pass LNG Indentures.

As of September 30, 2013 and December 31, 2012, we classified $53.0 million and $17.4 million, respectively, as current restricted cash and cash equivalents for the payment of interest due within twelve months. As of September 30, 2013 and December 31, 2012, we classified the permanent debt service reserve fund of $76.1 million as non-current restricted cash and cash equivalents. These cash accounts are controlled by a collateral trustee, and, therefore, are shown as restricted cash and cash equivalents on our Consolidated Balance Sheets.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Liquefaction Reserve

In July 2012, Sabine Pass Liquefaction closed on a $3.6 billion senior secured credit facility (the "2012 Liquefaction Credit Facility"). In February and April 2013, Sabine Pass Liquefaction entered into $2.0 billion, before premium, of Senior Secured Notes due in 2021 (the "2021 Sabine Pass Liquefaction Senior Notes") and $1.0 billion of Senior Secured Notes due in 2023 (the "2023 Sabine Pass Liquefaction Senior Notes" and collectively with the 2021 Sabine Pass Liquefaction Senior Notes, the "Sabine Pass Liquefaction Senior Notes"). In May 2013, Sabine Pass Liquefaction closed four credit facilities aggregating $5.9 billion (collectively the "2013 Liquefaction Credit Facilities"), which amended and restated the 2012 Liquefaction Credit Facility. See Note 7—"Long-Term Debt". Under the terms and conditions of the 2012 Liquefaction Credit Facility and the 2013 Liquefaction Credit Facilities, Sabine Pass Liquefaction is required to deposit all cash received into collateral accounts controlled by a collateral trustee. Therefore, all of Sabine Pass Liquefaction's cash and cash equivalents are shown as restricted cash and cash equivalents on our Consolidated Balance Sheets. As of September 30, 2013 and December 31, 2012, we classified $133.5 million and $75.1 million, respectively, as current restricted cash and cash equivalents held by Sabine Pass Liquefaction for the payment of current liabilities related to the Liquefaction Project, and $665.1 million and $196.3 million, respectively, as non-current restricted cash and cash equivalents held by Sabine Pass Liquefaction for future Liquefaction Project construction costs.

CTPL Reserve

In May 2013, CTPL entered into a $400.0 million term loan facility (the "CTPL Credit Facility"). As of September 30, 2013, we classified $23.5 million and $87.2 million as current and non-current restricted cash and cash equivalents, respectively, held by CTPL because such funds may only be used for modifications of the Creole Trail Pipeline in order to enable bi-directional natural gas flow and for the payment of interest during construction of such modifications.

NOTE 4—PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consists of LNG terminal costs and fixed assets, as follows (in thousands):



	September 30,			December 31,
	2013			2012
LNG terminal costs
LNG terminal	$	2,224,364		$	2,224,230
LNG terminal construction-in-process	3,694,355			1,228,647
LNG site and related costs, net	150			156
Accumulated depreciation	(276,960		)	(234,349		)
Total LNG terminal costs, net	5,641,909			3,218,684

Fixed assets
Computer and office equipment	474			368
Vehicles	884			704
Machinery and equipment	1,490			1,473
Other	837			760
Accumulated depreciation	(2,722		)	(2,397		)
Total fixed assets, net	963			908

Property, plant and equipment, net	$	5,642,872		$	3,219,592

Depreciation expense related to the Sabine Pass LNG terminal totaled $14.4 million for each of the three months ended September 30, 2013 and 2012. Depreciation expense related to the Sabine Pass LNG terminal totaled $42.8 million for the nine months ended September 30, 2013 and 2012.

In June 2012, we began capitalizing costs associated with Train 1 and Train 2 of the Liquefaction Project, and in May 2013, we began capitalizing costs associated with Train 3 and Train 4 of the Liquefaction Project. For the three months ended September 30, 2013 and 2012, we capitalized $30.2 million and $14.0 million of interest expense related to the construction of the Liquefaction Project, respectively. For the nine months ended September 30, 2013 and 2012, we capitalized $125.0 million and $14.0 million of interest expense related to the construction of the Liquefaction Project, respectively.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 5—FINANCIAL INSTRUMENTS

Derivative Instruments

The following table (in thousands) shows the fair value of our derivative assets and liabilities that are required to be measured at fair value on a recurring basis as of September 30, 2013 and December 31, 2012, which are classified as other current assets, other current liabilities, other non-current assets and other non-current liabilities in our Consolidated Balance Sheets.



	Fair Value Measurements as of
	September 30, 2013										December 31, 2012
	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
LNG Inventory Derivatives asset	$	—	$	219		$	—	$	219		$	—	$	232		$	—	$	232
Fuel Derivatives (liability)	—		(227		)	—		(227		)	—		(98		)	—		(98		)
Interest Rate Derivatives asset (liability)	—		56,039			—		56,039			—		(26,424		)	—		(26,424		)

The estimated fair values of our LNG Inventory Derivatives and Fuel Derivatives are the amount at which the instruments could be exchanged currently between willing parties. We value these derivatives using observable commodity price curves and other relevant data. We value our Interest Rate Derivatives using valuations based on the initial trade prices. Using an income-based approach, subsequent valuations are based on observable inputs to the valuation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data. 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 net settlement.

Commodity Derivatives

We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. For transactions in which we have elected the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated Statements of Operations until the period of delivery. For those instruments accounted for as derivatives, including our LNG Inventory Derivatives and certain of our Fuel Derivatives, changes in fair value are reported in earnings.

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 where our Fuel Derivatives or our LNG Inventory Derivatives are in an asset position. Except for the fuel hedges with our affiliate described below, our commodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. We are required by these financial institutions to use margin deposits as credit support for our commodity derivative activities. Collateral of $0.9 million deposited for such contracts, which has not been reflected in the derivative fair value tables, is included in the other current assets balance as of September 30, 2013 and December 31, 2012.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

During the second quarter of 2013, Sabine Pass LNG began to enter into forward contracts under its master service agreement with Cheniere Marketing, LLC ("Cheniere Marketing"), a wholly owned subsidiary of Cheniere, to hedge the exposure to price risk attributable to future purchases of natural gas to be utilized as fuel to operate the Sabine Pass LNG terminal. Sabine Pass LNG elected to account for these physical hedges of future fuel purchases as normal purchase normal sale transactions, exempt from fair value accounting. Sabine Pass LNG had not posted collateral with Cheniere Marketing for such forward contracts as of September 30, 2013.

The following table (in thousands) shows the fair value and location of our LNG Inventory Derivatives and Fuel Derivatives on our Consolidated Balance Sheets:



		Fair Value Measurements as of
	Balance Sheet Location	September 30, 2013			December 31, 2012
LNG Inventory Derivatives asset	Prepaid expenses and other	$	219		$	232
Fuel Derivatives liability	Prepaid expenses and other	(227		)	(98		)

The following table (in thousands) shows the changes in the fair value and settlements of our LNG Inventory Derivatives recorded in revenues on our Consolidated Statements of Operations during the three and nine months ended September 30, 2013 and 2012:



	Three Months Ended September 30,					Nine Months Ended September 30,
	2013		2012			2013			2012
LNG Inventory Derivatives gain (loss)	$	—	$	(228	)	$	(442	)	$	697

The following table (in thousands) shows the changes in the fair value and settlements of our Fuel Derivatives and LNG Inventory Derivatives recorded in derivative gain (loss), net on our Consolidated Statements of Operations during the three and nine months ended September 30, 2013 and 2012:



	Three Months Ended September 30,					Nine Months Ended September 30,
	2013			2012		2013			2012
LNG Inventory Derivatives gain	$	201		$	—	$	976		$	—
Fuel Derivatives gain (loss) (1)	(55		)	287		(3		)	(288		)

(1)Excludes settlements of hedges of the exposure to price risk attributable to future purchases of natural gas to be utilized

as fuel to operate the Sabine Pass LNG terminal for which Sabine Pass LNG has elected the normal purchase normal sale exemption from derivative accounting.

Interest Rate Derivatives

In August 2012 and June 2013, Sabine Pass Liquefaction entered into Interest Rate Derivatives to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the 2012 Liquefaction Credit Facility and the 2013 Liquefaction Credit Facilities, respectively. The Interest Rate Derivatives hedge a portion of the expected outstanding borrowings over the term of the 2013 Liquefaction Credit Facilities.

Sabine Pass Liquefaction designated the Interest Rate Derivatives entered into in August 2012 as hedging instruments which was required in order to qualify for cash flow hedge accounting. As a result of this cash flow hedge designation, we recognized the Interest Rate Derivatives entered into in August 2012 as an asset or liability at fair value, and reflected changes in fair value through other comprehensive income in our Consolidated Statements of Comprehensive Loss. Any hedge ineffectiveness associated with the Interest Rate Derivatives entered into in August 2012 was recorded immediately as derivative gain (loss) in our Consolidated Statements of Operations. The realized gain (loss) on the Interest Rate Derivatives entered into in August 2012 was recorded as an (increase) decrease in interest expense on our Consolidated Statements of Operations to the extent not capitalized as part of the Liquefaction Project. The effective portion of the gains or losses on our Interest Rate Derivatives entered into in August 2012 recorded in other comprehensive income would have been reclassified to earnings as interest payments on the 2012 Liquefaction Credit Facility impact earnings. In addition, amounts recorded in other comprehensive income are also reclassified into earnings if it becomes probable that the hedged forecasted transaction will not occur.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Sabine Pass Liquefaction did not elect to designate the Interest Rate Derivatives entered into in June 2013 as cash flow hedging instruments, and changes in fair value are recorded as derivative gain (loss) within the Consolidated Statements of Operations.

During the first quarter of 2013, we determined that it was no longer probable that the forecasted variable interest payments on the 2012 Liquefaction Credit Facility would occur in the time period originally specified based on the continued development of our financing strategy for the Liquefaction Project, and, in particular, the Sabine Pass Liquefaction Senior Notes described in Note 8—"Long-Term Debt". As a result, all of the Interest Rate Derivatives entered into in August 2012 were no longer effective hedges, and the remaining portion of hedge relationships that were designated cash flow hedges as of December 31, 2012, were de-designated as of February 1, 2013. For de-designated cash flow hedges, changes in fair value prior to their de-designation date are recorded as other comprehensive income (loss) within the Consolidated Balance Sheets, and changes in fair value subsequent to their de-designation date are recorded as derivative gain (loss) within the Consolidated Statements of Operations.

In June 2013, we concluded that the hedged forecasted transactions associated with the Interest Rate Derivatives entered into in connection with the 2012 Liquefaction Credit Facility had become probable of not occurring based on the issuances of the Sabine Pass Liquefaction Senior Notes, the closing of the 2013 Liquefaction Credit Facilities, the additional Interest Rate Derivatives executed in June 2013, and our intention to continue to issue fixed rate debt to refinance drawn portions of the 2013 Liquefaction Credit Facilities. As a result, the amount remaining in accumulated other comprehensive income ("AOCI") pertaining to the previously designated Interest Rate Derivatives was reclassified out of AOCI and into income. We have presented the reclassification of unrealized losses from AOCI into income and the changes in fair value and settlements subsequent to the reclassification date separate from interest expense as derivative gain (loss), net in our Consolidated Statements of Operations.

At September 30, 2013, Sabine Pass Liquefaction had the following Interest Rate Derivatives outstanding:

Initial Notional Amount

Maximum Notional Amount

Effective Date

Maturity Date

Weighted Average Fixed Interest Rate Paid

Variable Interest Rate Received

Interest Rate Derivatives - Not Designated

20.0

million

2.9

billion

August 14, 2012

July 31, 2019

1.98%

One-month LIBOR

Interest Rate Derivatives - Not Designated

—

671.0

million

June 5, 2013

May 28, 2020

2.05%

One-month LIBOR

The following table (in thousands) shows the fair value of our Interest Rate Derivatives:



		Fair Value Measurements as of
	Balance Sheet Location	September 30, 2013		December 31, 2012
Interest Rate Derivatives - Not Designated	Non-current derivative assets	$	64,309	$	—
Interest Rate Derivatives - Designated	Non-current derivative liabilities	—		21,290
Interest Rate Derivatives - Not Designated	Other current liabilities	8,270		—
Interest Rate Derivatives - Not Designated	Non-current derivative liabilities	—		5,134

The following table (in thousands) details the effect of our Interest Rate Derivatives included in OCI and AOCI for the three months ended September 30, 2013 and 2012:



	Gain (Loss) in Other Comprehensive Income					Gain (Loss) Reclassified from AOCI into Interest Expense (Effective Portion)				Losses Reclassified into Earnings as a Result of Discontinuance of Cash Flow Hedge Accounting
	2013		2012			2013		2012		2013		2012
Interest Rate Derivatives - Designated	$	—	$	(29,676	)	$	—	$	—	$	—	$	—

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following table (in thousands) details the effect of our Interest Rate Derivatives included in OCI and AOCI for the nine months ended September 30, 2013 and 2012:



	Gain (Loss) in Other Comprehensive Income						Gain (Loss) Reclassified from AOCI into Interest Expense (Effective Portion)				Losses Reclassified into Earnings as a Result of Discontinuance of Cash Flow Hedge Accounting
	2013			2012			2013		2012		2013			2012
Interest Rate Derivatives - Designated	$	21,297		$	(29,676	)	$	—	$	—	$	(5,806	)	$	—
Interest Rate Derivatives - Settlements	(30		)	—			—		—		(167		)	—

The following table (in thousands) shows the changes in the fair value of our Interest Rate Derivatives - Not Designated recorded in derivative gain (loss), net on our Consolidated Statements of Operations during the three and nine months ended September 30, 2013 and 2012:



	Three Months Ended September 30,					Nine Months Ended September 30,
	2013			2012		2013		2012
Interest Rate Derivatives - Not Designated gain (loss)	$	(22,481	)	$	—	$	60,707	$	—

Balance Sheet Presentation

Our commodity and interest rate derivatives are presented on a net basis on our Consolidated Balance Sheets as described above. The following table (in thousands) shows the fair value of our derivatives outstanding on a gross and net basis:



	Gross Amounts Recognized				Gross Amounts Offset in the Consolidated Balance Sheet			Net Amounts Presented in the Consolidated Balance Sheet			Gross Amounts Not Offset in the Consolidated Balance Sheet
Offsetting Derivative Assets (Liabilities)											Derivative Instrument		Cash Collateral Received (Paid)		Net Amount
As of September 30, 2013:
Fuel Derivatives	$	(227	)		$	(227	)	$	—		$	—	$	—	$	—
LNG Inventory Derivatives	219				—			219			—		—		219
Interest Rate Derivatives - Not Designated	64,309				—			64,309			—		—		64,309
Interest Rate Derivatives - Not Designated	(8,270		)		—			(8,270		)	—		—		(8,270		)
As of December 31, 2012:				—
Fuel Derivatives	(98		)		(98		)	—			—		—		—
LNG Inventory Derivatives	232				—			232			—		—		232
Interest Rate Derivatives - Designated	(21,290		)		—			(21,290		)	—		—		(21,290		)
Interest Rate Derivatives - Not Designated	(5,134		)		—			(5,134		)	—		—		(5,134		)

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Other Financial Instruments

The estimated fair value of our other financial instruments, including those financial instruments for which the fair value option was not elected, are set forth in the table below. The carrying amounts reported on our Consolidated Balance Sheets for cash and cash equivalents, restricted cash and cash equivalents, accounts receivable, interest receivable and accounts payable approximate fair value due to their short-term nature.

Other Financial Instruments (in thousands):



	September 30, 2013				December 31, 2012
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
2016 Notes, net of discount (1)	$	1,650,634	$	1,811,570	$	1,647,113	$	1,824,177
2020 Notes (1)	420,000		425,250		420,000		437,850
2021 Sabine Pass Liquefaction Senior Notes (1)	2,011,897		1,951,540		—		—
2023 Sabine Pass Liquefaction Senior Notes (1)	1,000,000		952,500		—		—
2012 Liquefaction Credit Facility (2)	—		—		100,000		100,000
2013 Liquefaction Credit Facilities (2)	100,000		100,000		—		—
CTPL Credit Facility (3)	391,665		400,000		—		—


(1)	The Level 2 estimated fair value was based on quotations obtained from broker-dealers who make markets in these and similar instruments based on the closing trading prices on September 30, 2013 and December 31, 2012, as applicable.


(2)	The Level 3 estimated fair value approximates the carrying amount because the interest rates are variable and reflective of market rates and Sabine Pass Liquefaction has the ability to call this debt at anytime without penalty.


(3)	The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and CTPL has the ability to call this debt at anytime without penalty.

NOTE 6—ACCRUED LIABILITIES

As of September 30, 2013 and December 31, 2012, accrued liabilities (including amounts due to affiliates) consisted of the following (in thousands):



	September 30,		December 31,
	2013		2012
Interest and related debt fees	$	97,758	$	16,327
Affiliate	51,419		5,744
LNG liquefaction costs	33,589		26,131
LNG terminal costs	1,650		977
Other	8,791		4,413
Total accrued liabilities (including affiliate)	$	193,207	$	53,592

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 7—LONG-TERM DEBT

As of September 30, 2013 and December 31, 2012, our long-term debt consisted of the following (in thousands):



	September 30,			December 31,
	2013			2012
Long-term debt
2016 Notes	$	1,665,500		$	1,665,500
2020 Notes	420,000			420,000
2021 Sabine Pass Liquefaction Senior Notes	2,000,000			—
2023 Sabine Pass Liquefaction Senior Notes	1,000,000			—
2012 Liquefaction Credit Facility	—			100,000
2013 Liquefaction Credit Facilities	100,000			—
CTPL Credit Facility	400,000			—
Total long-term debt	5,585,500			2,185,500
Long-term debt premium (discount)
2016 Notes	(14,866		)	(18,387		)
2021 Sabine Pass Liquefaction Senior Notes	11,897			—
CTPL Credit Facility	(8,336		)	—
Total long-term debt, net	$	5,574,195		$	2,167,113

Sabine Pass LNG Senior Notes

As of September 30, 2013 and December 31, 2012, Sabine Pass LNG had an aggregate principal amount of $1,665.5 million, before discount, of the 2016 Notes and $420.0 million of the 2020 Notes outstanding. Borrowings under the 2016 Notes and 2020 Notes bear interest at a fixed rate of 7.50% and 6.50%, respectively. The terms of the 2016 Notes and the 2020 Notes are substantially similar. Interest on the 2016 Notes is payable semi-annually in arrears on May 30 and November 30 of each year. Interest on the 2020 Notes is payable semi-annually in arrears on May 1 and November 1 of each year. Subject to permitted liens, the Sabine Pass LNG Senior Notes are secured on a first-priority basis by a security interest in all of Sabine Pass LNG's equity interests and substantially all of its operating assets.

Sabine Pass LNG may redeem some or all of its 2016 Notes at any time, and from time to time, at the redemption prices specified in the indenture governing the 2016 Notes, plus accrued and unpaid interest, if any, to the date of redemption. Sabine Pass LNG may redeem all or part of its 2020 Notes at any time on or after November 1, 2016, at fixed redemption prices specified in the indenture governing the 2020 Notes, plus accrued and unpaid interest, if any, to the date of redemption. Sabine Pass LNG may also, at its option, redeem all or part of the 2020 Notes at any time prior to November 1, 2016, at a "make-whole" price set forth in the indenture governing the 2020 Notes, plus accrued and unpaid interest, if any, to the date of redemption. At any time before November 1, 2015, Sabine Pass LNG may redeem up to 35% of the aggregate principal amount of the 2020 Notes at a redemption price of 106.5% of the principal amount of the 2020 Notes to be redeemed, plus accrued and unpaid interest, if any, to the redemption date, in an amount not to exceed the net proceeds of one or more completed equity offerings as long as Sabine Pass LNG redeems the 2020 Notes within 180 days of the closing date for such equity offering and at least 65% of the aggregate principal amount of the 2020 Notes originally issued remains outstanding after the redemption.

Under the Sabine Pass LNG Indentures, except for permitted tax distributions, Sabine Pass LNG may not make distributions until certain conditions are satisfied: there must be on deposit in an interest payment account an amount equal to one-sixth of the semi-annual interest payment multiplied by the number of elapsed months since the last semi-annual interest payment, and there must be on deposit in a permanent debt service reserve fund an amount equal to one semi-annual interest payment. Distributions are permitted only after satisfying the foregoing funding requirements, a fixed charge coverage ratio test of 2:1 and other conditions specified in the Sabine Pass LNG Indentures. During the three months ended September 30, 2013 and 2012, Sabine Pass LNG made distributions of $93.0 million and $36.2 million, respectively, after satisfying all the applicable conditions in the Sabine Pass LNG Indentures. During the nine months ended September 30, 2013 and 2012, Sabine Pass LNG made distributions of $242.1 million and $182.9 million, respectively, after satisfying all the applicable conditions in the Sabine Pass LNG Indentures.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Sabine Pass Liquefaction Senior Notes

The terms of the 2021 Sabine Pass Liquefaction Senior Notes and the 2023 Sabine Pass Liquefaction Senior Notes are governed by a common indenture (the "Indenture"). The Indenture contains customary terms and events of default and certain covenants that, among other things, limit Sabine Pass Liquefaction's ability and the ability of Sabine Pass Liquefaction'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 Sabine Pass Liquefaction's restricted subsidiaries, restrict dividends or other payments by restricted subsidiaries, incur liens, enter into transactions with affiliates, consolidate, merge, sell or lease all or substantially all of Sabine Pass Liquefaction's assets and enter into certain LNG sales contracts. Subject to permitted liens, the Sabine Pass Liquefaction Senior Notes are secured on a pari passu first-priority basis by a security interest in all of the membership interests in Sabine Pass Liquefaction and substantially all of Sabine Pass Liquefaction's assets. Sabine Pass Liquefaction may not make any distributions until, among other requirements, substantial completion of Train 1 and Train 2 has occurred, deposits are made into debt service reserve accounts and a debt service coverage ratio for the prior 12-month period and a projected debt service coverage ratio for the upcoming 12-month period of 1.25:1.00 are satisfied.

At any time prior to November 1, 2020, with respect to the 2021 Sabine Pass Liquefaction Senior Notes, or January 15, 2023, with respect to the 2023 Sabine Pass Liquefaction Senior Notes, Sabine Pass Liquefaction may redeem all or a part of the Sabine Pass Liquefaction Senior Notes, at a redemption price equal to the "make-whole" price set forth in the Indenture, plus accrued and unpaid interest, if any, to the date of redemption. Sabine Pass Liquefaction also may at any time on or after November 1, 2020, with respect to the 2021 Sabine Pass Liquefaction Senior Notes, or January 15, 2023, with respect to the 2023 Sabine Pass Liquefaction Senior Notes, redeem the Sabine Pass Liquefaction Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the Sabine Pass Liquefaction Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.

In connection with the issuances of the Sabine Pass Liquefaction Senior Notes, Sabine Pass Liquefaction also entered into registration rights agreements (the "Liquefaction Registration Rights Agreements"). Under the Liquefaction Registration Rights Agreements, Sabine Pass Liquefaction has agreed to use commercially reasonable efforts to file with the SEC and cause to become effective registration statements relating to an offer to exchange the Sabine Pass Liquefaction Senior Notes for a like aggregate principal amount of SEC-registered notes with terms identical in all material respects to the 2021 Sabine Pass Liquefaction Senior Notes and 2023 Sabine Pass Liquefaction Senior Notes (other than with respect to restrictions on transfer or to any increase in annual interest rate) within 360 days after February 1, 2013 for $1.5 billion of the 2021 Sabine Pass Liquefaction Senior Notes and within 295 days after April 16, 2013 for $500.0 million of the 2021 Sabine Pass Liquefaction Senior Notes and all of the 2023 Sabine Pass Liquefaction Senior Notes. Under specified circumstances, Sabine Pass Liquefaction may be required to file a shelf registration statement to cover resales of the Sabine Pass Liquefaction Senior Notes. If Sabine Pass Liquefaction fails to satisfy these obligations, Sabine Pass Liquefaction may be required to pay additional interest to holders of the Sabine Pass Liquefaction Senior Notes under certain circumstances.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

2013 Liquefaction Credit Facilities

In May 2013, Sabine Pass Liquefaction closed the 2013 Liquefaction Credit Facilities aggregating $5.9 billion. The 2013 Liquefaction Credit Facilities are being used to fund a portion of the costs of developing, constructing and placing into operation the first four LNG Trains of the Liquefaction Project. The 2013 Liquefaction Credit Facilities will mature on the earlier of May 28, 2020 or the second anniversary of the completion date of the first four LNG Trains of the Liquefaction Project, as defined in the 2013 Liquefaction Credit Facilities. Borrowings under the 2013 Liquefaction Credit Facilities may be refinanced, in whole or in part, at any time without premium or penalty, except for interest rate hedging and interest rate breakage costs. Sabine Pass Liquefaction made a $100.0 million borrowing under the 2013 Liquefaction Credit Facilities in June 2013 after meeting the required conditions precedent.

Borrowings under the 2013 Liquefaction Credit Facilities bear interest at a variable rate per annum equal to, at Sabine Pass Liquefaction's election, the London Interbank Offered Rate ("LIBOR") or the base rate, plus the applicable margin. The applicable margins for LIBOR loans prior to, and after, the completion of Train 4 range from 2.3% to 3.0% and 2.3% to 3.25%, respectively, depending on the applicable 2013 Liquefaction Credit Facility. Interest on LIBOR loans is due and payable at the end of each LIBOR period. The 2013 Liquefaction Credit Facilities required Sabine Pass Liquefaction to pay certain up-front fees to the agents and lenders in the aggregate amount of approximately $144.0 million and provide for a commitment fee calculated at a rate per annum equal to 40% of the applicable margin for LIBOR loans, multiplied by the average daily amount of the undrawn commitment. Annual administrative fees must also be paid to the agent and the trustee. The principal of loans made under the 2013 Liquefaction Credit Facilities must be repaid in quarterly installments, commencing upon the earlier of the last day of the first calendar quarter ending at least three months following the completion of Train 4 of the Liquefaction Project and September 30, 2018. Scheduled repayments are based upon an 18-year amortization profile, with the remaining balance due upon the maturity of the 2013 Liquefaction Credit Facilities.

Under the terms and conditions of the 2013 Liquefaction Credit Facilities, all cash held by Sabine Pass Liquefaction is controlled by a collateral agent. These funds can only be released by the collateral agent upon satisfaction of certain terms and conditions related to the use of proceeds, and are classified as restricted on our Consolidated Balance Sheets.

The 2013 Liquefaction Credit Facilities contain conditions precedent for the second borrowing and any subsequent borrowings, as well as customary affirmative and negative covenants. The obligations of Sabine Pass Liquefaction under the 2013 Liquefaction Credit Facilities are secured by substantially all of the assets of Sabine Pass Liquefaction as well as all of the membership interests in Sabine Pass Liquefaction on a pari passu basis with the Sabine Pass Liquefaction Senior Notes.

Under the terms of the 2013 Liquefaction Credit Facilities, Sabine Pass Liquefaction is required to hedge not less than 75% of the variable interest rate exposure of its projected outstanding borrowings, calculated on a weighted average basis in comparison to its anticipated draw of principal. See Note 5— "Financial Instruments".

2012 Liquefaction Credit Facility

In July 2012, Sabine Pass Liquefaction entered into the $3.6 billion 2012 Liquefaction Credit Facility with a syndicate of lenders. The 2012 Liquefaction Credit Facility was intended to be used to fund a portion of the costs of developing, constructing and placing into operation Train 1 and Train 2 of the Liquefaction Project. In May 2013, the 2012 Liquefaction Credit Facility was amended and restated with the 2013 Liquefaction Credit Facilities and $100.0 million of outstanding borrowings under the 2012 Liquefaction Credit Facility were repaid in full.

The 2012 Liquefaction Credit Facility had a maturity date of the earlier of July 31, 2019 or the second anniversary of the completion date of Train 1 and Train 2 of the Liquefaction Project, as defined in the 2012 Liquefaction Credit Facility. Borrowings under the 2012 Liquefaction Credit Facility could have been refinanced, in whole or in part, at any time without premium or penalty, except for interest rate hedging and interest rate breakage costs. Sabine Pass Liquefaction made a $100.0 million borrowing under the 2012 Liquefaction Credit Facility in August 2012 after meeting the required conditions precedent.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Borrowings under the 2012 Liquefaction Credit Facility bore interest at a variable rate equal to, at Sabine Pass Liquefaction's election, LIBOR or the base rate, plus the applicable margin. The applicable margin for LIBOR loans was 3.50% during construction and 3.75% during operations. Interest on LIBOR loans was due and payable at the end of each LIBOR period. The 2012 Liquefaction Credit Facility required Sabine Pass Liquefaction to pay certain up-front fees to the agents and lenders in the aggregate amount of approximately $178 million and provided for a commitment fee calculated at a rate per annum equal to 40% of the applicable margin for LIBOR loans, multiplied by the average daily amount of the undrawn commitment. Annual administrative fees were also required to be paid to the agent and the trustee. The principal of loans made under the 2012 Liquefaction Credit Facility had to be repaid in quarterly installments, commencing with the last day of the first calendar quarter ending at least three months following the completion of Train 1 and Train 2 of the Liquefaction Project. Scheduled repayments were based upon an 18-year amortization profile, with the remaining balance due upon the maturity of the 2012 Liquefaction Credit Facility.

Under the terms and conditions of the 2012 Liquefaction Credit Facility, all cash held by Sabine Pass Liquefaction was controlled by the collateral agent. These funds could only be released by the collateral agent upon satisfaction of certain terms and conditions related to the use of proceeds, and the cash balance of $100.0 million held in these accounts as of December 31, 2012 was classified as restricted on our Consolidated Balance Sheets.

The 2012 Liquefaction Credit Facility contained conditions precedent for the second borrowing and any subsequent borrowings, as well as customary affirmative and negative covenants. The obligations of Sabine Pass Liquefaction under the 2012 Liquefaction Credit Facility were secured by substantially all of the assets of Sabine Pass Liquefaction as well as all of the membership interests in Sabine Pass Liquefaction, and a security interest in Cheniere Partners' rights under its Unit Purchase Agreement with Blackstone CQP Holdco LP ("Blackstone"), dated May 14, 2012, on a pari passu basis with the Sabine Pass Liquefaction Senior Notes.

Under the terms of the 2012 Liquefaction Credit Facility, Sabine Pass Liquefaction was required to hedge not less than 75% of the variable interest rate exposure of its projected outstanding borrowings, calculated on a weighted average basis in comparison to its anticipated draw of principal. See Note 5— "Financial Instruments".

In February 2013, Sabine Pass Liquefaction issued the 2021 Sabine Pass Liquefaction Senior Notes to refinance a portion of the 2012 Liquefaction Credit Facility, and a portion of available commitments pursuant to the 2012 Liquefaction Credit Facility was suspended. In April 2013, Sabine Pass Liquefaction issued an aggregate principal amount of $500.0 million of additional 2021 Sabine Pass Liquefaction Senior Notes and $1.0 billion of 2023 Sabine Pass Liquefaction Senior Notes, and as a result, approximately$1.4 billion of commitments under the 2012 Liquefaction Credit Facility were terminated. The termination of these commitments in April 2013 and the amendment and restatement of the 2012 Liquefaction Credit Facility with the 2013 Liquefaction Credit Facilities in May 2013 resulted in a write-off of debt issuance costs associated with the 2012 Liquefaction Credit Facility of zero and $80.5 million in the three and nine months ended September 30, 2013, respectively.

CTPL Credit Facility

In May 2013, CTPL entered into the CTPL Credit Facility, which will be used to fund modifications to the Creole Trail Pipeline and for general business purposes. CTPL incurred $10.0 million of direct lender fees that were recorded as a debt discount. The CTPL Credit Facility matures in 2017 when the full amount of the outstanding principal obligations must be repaid. CTPL's loans may be repaid, in whole or in part, at any time without premium or penalty. As of September 30, 2013, CTPL had borrowed the full amount of $400.0 million available under the CTPL Credit Facility.

Borrowings under the CTPL Credit Facility bear interest at a variable rate per annum equal to, at CTPL's election, LIBOR or the base rate, plus the applicable margin. The applicable margin for LIBOR loans is 3.25%. Interest on LIBOR loans is due and payable at the end of each LIBOR period.

Under the terms and conditions of the CTPL Credit Facility, all cash reserved to pay interest during construction is controlled by a collateral agent. These funds can only be released by the collateral agent upon satisfaction of certain terms and conditions, and are classified as restricted on our Consolidated Balance Sheets. CTPL is also required to pay annual fees to the administrative and collateral agents.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The CTPL Credit Facility contains customary affirmative and negative covenants. The obligations of CTPL under the CTPL Credit Facility are secured by a first priority lien on substantially all of the personal property of CTPL and all of the general partner and limited partner interests in CTPL.

Cheniere Partners has guaranteed (i) the obligations of CTPL under the CTPL Credit Facility if the maturity of the CTPL loans is accelerated following the termination by Sabine Pass Liquefaction of a transportation precedent agreement in limited circumstances and (ii) the obligations of Cheniere Energy Investments, LLC ("Cheniere Investments"), Cheniere Partners' wholly owned subsidiary, in connection with its obligations under an equity contribution agreement (a) to pay operating expenses of CTPL until CTPL receives revenues under a service agreement with Sabine Pass Liquefaction and (b) to fund interest payments on the CTPL loans after the funds in an interest reserve account have been exhausted.

NOTE 8—DESCRIPTION OF EQUITY INTERESTS

The common units, Class B units and subordinated 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.

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, 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. The higher percentages range from 15% up to 50%.

The common units have the right to receive initial quarterly distributions of $0.425, plus any arrearages thereon, before any distribution is made to the holders of the subordinated units. Subordinated units will convert into common units on a one-for-one basis when we meet financial tests specified in the partnership agreement. Although common and subordinated unitholders are not obligated to fund losses of the partnership, their capital accounts, which would be considered in allocating the net assets of the partnership were it to be liquidated, continue to share in losses.

During 2012, Blackstone and Cheniere completed their purchases of newly created Cheniere Partners Class B units ("Class B units") for total consideration of $1.5 billion and $500.0 million, respectively. Proceeds from the financings are being used to fund a portion of the costs of developing, constructing and placing into service the Liquefaction Project. In May 2013, Cheniere purchased an additional 12.0 million Class B units for consideration of $180.0 million in connection with Cheniere Partners' acquisition of the Creole Trail Pipeline Business described in Note 1—"Organization and Nature of Operations". The Class B units are subject to conversion, mandatorily or at the option of the holders of the Class B units under specified circumstances, into a number of common units based on the then-applicable conversion value of the Class B units. On a quarterly basis beginning on the initial purchase of the Class B units, and ending on the conversion date of the Class B units, the conversion value of the Class B units increases at a compounded rate of 3.5% per quarter, subject to an additional upward adjustment for certain equity and debt financings. The Class B units are not entitled to cash distributions except in the event of our liquidation, our merger, consolidation or other combination with another person or the sale of all or substantially all of our assets. The holders of Class B units have a preference over the holders of the subordinated units in the event of our liquidation, our merger, consolidation or other combination with another person or the sale of all or substantially all of our assets. The Class B units will mandatorily convert into common units on the first business day following the record date with respect to Cheniere Partners' first distribution (the "Mandatory Conversion Date") after the earlier of the substantial completion date of Train 3 or August 9, 2017, although if a notice to proceed is given to Bechtel for Train 3 prior to August 9, 2017, the Mandatory Conversion Date will be the substantial completion date of Train 3. The notice to proceed was given to Bechtel on May 28, 2013. We currently expect the substantial completion date of Train 3 to occur before March 31, 2017. If the Class B units are not mandatorily converted by July 2019, the holders of the Class B units have the option to convert the Class B units into common units at that time.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 9—RELATED PARTY TRANSACTIONS

As of September 30, 2013 and December 31, 2012, we had $25.7 million and $5.0 million of advances to affiliates, respectively. In addition, we have entered into the following related party transactions:

LNG Terminal Capacity Agreements

Terminal Use Agreement

Sabine Pass Liquefaction obtained approximately 2.0 Bcf/d of regasification capacity under a terminal use agreement ("TUA") with Sabine Pass LNG as a result of an assignment in July 2012 by Cheniere Energy Investments, LLC ("Cheniere Investments"), our wholly owned subsidiary, of its rights, title and interest under its TUA with Sabine Pass LNG. Sabine Pass Liquefaction is obligated to make monthly capacity payments to Sabine Pass LNG aggregating approximately $250 million per year, continuing until at least 20 years after Sabine Pass Liquefaction delivers its first commercial cargo at the Liquefaction Project, which may occur as early as late 2015.

In connection with Sabine Pass Liquefaction's TUA, Sabine Pass Liquefaction is required to pay for a portion of the cost to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal. During the three and nine months ended September 30, 2013, we recorded $14.4 million and $27.3 million, respectively, as operating and maintenance expense related to this obligation.

Cheniere Investments, Sabine Pass Liquefaction and Sabine Pass LNG entered into a terminal use rights assignment and agreement ("TURA") pursuant to which Cheniere Investments has the right to use Sabine Pass Liquefaction's reserved capacity under the TUA and has the obligation to make the monthly capacity payments required by the TUA to Sabine Pass LNG. However, the revenue earned by Sabine Pass LNG from the capacity payments made under the TUA and the loss incurred by Cheniere Investments under the TURA are eliminated upon consolidation of our financial statements. We have guaranteed the obligations of Sabine Pass Liquefaction under its TUA and the obligations of Cheniere Investments under the TURA.

In an effort to utilize Cheniere Investments’ reserved capacity under its TURA during construction of the Liquefaction Project, Cheniere Marketing has entered into an amended and restated variable capacity rights agreement with Cheniere Investments ("amended and restated VCRA") pursuant to which Cheniere Marketing is obligated to pay Cheniere Investments 80% of the expected gross margin of each cargo of LNG that Cheniere Marketing arranges for delivery to the Sabine Pass LNG terminal. During the term of the amended and restated VCRA, Cheniere Marketing is responsible for the payment of taxes and new regulatory costs paid by Cheniere Investments under the TURA. We recorded zero and $3.2 million revenues—affiliate from Cheniere Marketing in the three months ended September 30, 2013 and 2012, respectively, related to the amended and restated VCRA. We recorded zero and $4.9 million of revenues—affiliate from Cheniere Marketing in the nine months ended September 30, 2013 and 2012, respectively, related to the amended and restated VCRA.

LNG Sale and Purchase Agreement ("SPA")

Cheniere Marketing has entered into an SPA with Sabine Pass Liquefaction to purchase, at Cheniere Marketing's option, up to 104,000,000 MMBtu of LNG per annum produced from Train 1 through Train 4. Sabine Pass Liquefaction has the right each year during the term to reduce the annual contract quantity based on its assessment of how much LNG it can produce in excess of that required for other customers. Cheniere Marketing may purchase incremental LNG volumes at a price of 115% of Henry Hub plus: up to $3.00 per MMBtu for the most profitable 36,000,000 MMBtu of cargoes sold each year by Cheniere Marketing; and then 20% of net profits of the remaining 68,000,000 MMBtu sold each year by Cheniere Marketing.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

LNG Lease Agreement

In September 2011, Cheniere Investments entered into an agreement in the form of a lease (the "LNG Lease Agreement") with Cheniere Marketing that enables Cheniere Investments to supply the Sabine Pass LNG terminal with LNG to maintain proper LNG inventory levels and temperature. The LNG Lease Agreement also enables Cheniere Investments to hedge the exposure to variability in expected future cash flows of the LNG inventory. Under the terms of the LNG Lease Agreement, Cheniere Marketing funds all activities related to the purchase and hedging of the LNG, and Cheniere Investments reimburses Cheniere Marketing for all costs and assumes full price risk associated with these activities.

As a result of Cheniere Investments assuming full price risk associated with the LNG Lease Agreement, LNG inventory purchased by Cheniere Marketing under this arrangement is classified as LNG inventory—affiliate on our Consolidated Balance Sheets, and is recorded at cost and subject to lower-of-cost-or-market ("LCM") adjustments at the end of each period. LNG inventory—affiliate cost is determined using the average cost method. Recoveries of losses resulting from interim period LCM adjustments are made due to market price recoveries on the same LNG inventory—affiliate in the same fiscal year and are recognized as gains in later interim periods with such gains not exceeding previously recognized losses. Gains or losses on the sale of LNG inventory—affiliate and LCM adjustments are recorded as revenues on our Consolidated Statements of Operations. As of September 30, 2013, we had 75,000 MMBtu of LNG inventory—affiliate recorded at $0.2 million on our Consolidated Balance Sheets, and as of December 31, 2012, we had 1,369,000 MMBtu of LNG inventory—affiliate recorded at $4.4 million on our Consolidated Balance Sheets. During the three months ended September 30, 2013 and 2012, we recognized a gain of zero and $0.1 million, respectively, as a result of LCM adjustments to our LNG inventory—affiliate. During the nine months ended September 30, 2013 and 2012, we recognized a loss of zero and $0.5 million, respectively, as a result of LCM adjustments to our LNG inventory—affiliate.

Cheniere Marketing has entered into financial derivatives, on our behalf, to hedge the exposure to variability in expected future cash flows attributable to the future sale of our LNG inventory under the LNG Lease Agreement. The fair value of these derivative instruments at September 30, 2013 and December 31, 2012 was a derivative asset of zero and $0.2 million, respectively, and was classified as other current assets on our Consolidated Balance Sheets. Changes in the fair value of these derivative instruments are classified as revenues on our Consolidated Statements of Operations. We recorded revenues and losses of zero and losses of $0.2 million related to LNG inventory—affiliate derivatives in the three months ended September 30, 2013 and 2012, respectively. We recorded losses of $0.4 million and revenues of $0.7 million related to LNG inventory—affiliate derivatives in the nine months ended September 30, 2013 and 2012, respectively.

Service Agreements

During the three months ended September 30, 2013 and 2012, we recorded general and administrative expense—affiliate of $40.6 million and $32.2 million, respectively, under the service agreements described below. During the nine months ended September 30, 2013 and 2012, we recorded general and administrative expense—affiliate of $88.2 million and $42.0 million, respectively, under the service agreements described below.

We anticipate that prior to December 31, 2013, our general partner, which currently performs services under operation and maintenance agreements with Sabine Pass Liquefaction, Sabine Pass LNG and CTPL, will assign its rights and obligations under these agreements to Cheniere Investments.

Cheniere Partners Services Agreement

We have entered into a services agreement with Cheniere LNG Terminals, LLC ("Cheniere Terminals"), a wholly owned subsidiary of Cheniere, pursuant to which we pay Cheniere Terminals a quarterly non-accountable overhead reimbursement charge of $2.8 million (adjusted for inflation) for the provision of various general and administrative services for our benefit. In addition, we reimburse Cheniere Terminals for all audit, tax, legal and finance fees incurred by Cheniere Terminals that are necessary to perform the services under the agreement.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Sabine Pass LNG O&M Agreement

Sabine Pass LNG has entered into a long-term operation and maintenance agreement (the "Sabine Pass LNG O&M Agreement") with a wholly owned subsidiary of Cheniere pursuant to which we receive all necessary services required to operate and maintain the Sabine Pass LNG receiving terminal. Sabine Pass LNG is required to pay a fixed monthly fee of $130,000 (indexed for inflation) under the agreement, and the counterparty is entitled to a bonus equal to 50% of the salary component of labor costs in certain circumstances to be agreed upon between Sabine Pass LNG and the counterparty at the beginning of each operating year. In addition, Sabine Pass LNG is required to reimburse the counterparty for its operating expenses, which consist primarily of labor expenses.

Sabine Pass LNG MSA

Sabine Pass LNG has entered into a long-term management services agreement (the "Sabine Pass LNG 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 Sabine Pass LNG O&M Agreement. Sabine Pass LNG is required to pay Cheniere Terminals a monthly fixed fee of $520,000 (indexed for inflation).

Sabine Pass Liquefaction O&M Agreement

In May 2012, Sabine Pass Liquefaction entered into an operation and maintenance agreement (the "Liquefaction O&M Agreement") with a wholly owned subsidiary of Cheniere and our general partner pursuant to which we receive all of the necessary services required to construct, operate and maintain the liquefaction facilities. Before the liquefaction facilities are operational, the services to be provided include, among other services, obtaining governmental approvals on behalf of Sabine Pass Liquefaction, preparing an operating plan for certain periods, obtaining insurance, preparing staffing plans and preparing status reports. After the liquefaction facilities are operational, the services include all necessary services required to operate and maintain the liquefaction facilities.

Before the liquefaction facilities are operational, in addition to reimbursement of operating expenses, Sabine Pass Liquefaction 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 liquefaction facilities are operational, Sabine Pass Liquefaction 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 such Train.

Sabine Pass Liquefaction MSA

In May 2012, Sabine Pass Liquefaction entered into a management services agreement (the "Liquefaction MSA") with a wholly owned subsidiary of Cheniere pursuant to which such subsidiary was appointed to manage the construction and operation of the liquefaction facilities, excluding those matters provided for under the Liquefaction O&M Agreement. The services to be provided include, among other services, exercising the day-to-day management of Sabine Pass Liquefaction's affairs and business, managing Sabine Pass Liquefaction's regulatory matters, managing bank and brokerage accounts and financial books and records of Sabine Pass Liquefaction's business and operations, and providing contract administration services for all contracts associated with the liquefaction facilities. Sabine Pass Liquefaction will pay a monthly fee equal to 2.4% of the capital expenditures incurred in the previous month. After substantial completion of each Train, Sabine Pass Liquefaction pays a fixed monthly fee of $541,667 for services with respect to such Train.

CTPL O&M Agreement

In May 2013, CTPL entered into an amended long-term operation and maintenance agreement (the "CTPL O&M Agreement") with a wholly owned subsidiary of Cheniere pursuant to which we receive all necessary services required to operate and maintain the Creole Trail Pipeline. CTPL is required to reimburse the counterparty for its operating expenses, which consist primarily of labor expenses.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

CTPL MSA

In May 2013, CTPL entered into a management services agreement (the "CTPL MSA") with a wholly owned subsidiary of Cheniere pursuant to which such subsidiary was appointed to manage the modification and operation of the Creole Trail Pipeline, excluding those matters provided for under the CTPL O&M Agreement. The services to be provided include, among other services, exercising the day-to-day management of CTPL's affairs and business, managing CTPL's regulatory matters, managing bank and brokerage accounts and financial books and records of CTPL's business and operations, and providing contract administration services for all contracts associated with the liquefaction facilities. CTPL pays a monthly fee equal to 3.0% of the capital expenditures to enable bi-directional natural gas flow on the Creole Trail Pipeline incurred in the previous month.

Agreement to Fund Sabine Pass LNG's Cooperative Endeavor Agreements

In July 2007, Sabine Pass LNG executed Cooperative Endeavor Agreements ("CEAs") with various Cameron Parish, Louisiana taxing authorities that allow them to collect certain annual property tax payments from Sabine Pass LNG in 2007 through 2016. This ten-year initiative represents an aggregate $25.0 million commitment and will make resources available to the Cameron Parish taxing authorities on an accelerated basis in order to aid in their reconstruction efforts following Hurricane Rita. In exchange for Sabine Pass LNG's payments of annual ad valorem taxes, Cameron Parish will grant Sabine Pass LNG a dollar for dollar credit against future ad valorem taxes to be levied against the Sabine Pass LNG terminal starting in 2019. In September 2007, Sabine Pass LNG modified its TUA with Cheniere Marketing, pursuant to which Cheniere Marketing would pay Sabine Pass LNG additional TUA revenues equal to any and all amounts payable under the CEAs in exchange for a similar amount of credits against future TUA payments it would owe Sabine Pass LNG under its TUA starting in 2019. In June 2010, Cheniere Marketing assigned its TUA to Cheniere Investments and concurrently entered into a VCRA, allowing Cheniere Marketing to utilize Cheniere Investments' capacity under the TUA after the assignment. In July 2012, Cheniere Investments entered into an amended and restated VCRA with Cheniere Marketing in order for Cheniere Investments to utilize the capacity rights granted under the TURA during construction of the Liquefaction Project.

On a consolidated basis, these advance tax payments were recorded to other assets, and payments from Cheniere Marketing that Sabine Pass LNG utilized to make the ad valorem tax payments were recorded as deferred revenue. As of September 30, 2013 we had $17.2 million of both other non-current assets and non-current deferred revenue—affiliate, and as of December 31, 2012, we had $14.7 million of both other non-current assets and non-current deferred revenue—affiliate in each case resulting from Sabine Pass LNG's ad valorem tax payments and the advance tax payments received from Cheniere Marketing, respectively.

Contracts for Sale and Purchase of Natural Gas and LNG

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

Sabine Pass LNG recorded $0.7 million of natural gas and LNG purchased from Cheniere Marketing under this agreement in the three months ended September 30, 2013 and 2012. Sabine Pass LNG recorded $2.5 million and $1.9 million of natural gas and LNG purchased from Cheniere Marketing under this agreement in the nine months ended September 30, 2013 and 2012, respectively.

Sabine Pass LNG recorded $5.7 million and $2.8 million of natural gas sold to Cheniere Marketing under this agreement in the three months ended September 30, 2013 and 2012, respectively. Sabine Pass LNG recorded $8.6 million and $2.8 million of natural gas sold to Cheniere Marketing under this agreement in the nine months ended September 30, 2013 and 2012, respectively.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Tug Boat Lease Sharing Agreement

In connection with its tug boat lease, Sabine Pass Tug Services, LLC, a wholly owned subsidiary of Sabine Pass LNG ("Tug Services"), entered into a tug sharing agreement with Cheniere Marketing to provide its LNG cargo vessels with tug boat and marine services at the Sabine Pass LNG terminal. Tug Services recorded revenues—affiliate from Cheniere Marketing of $0.7 million pursuant to this agreement in each of the three months ended September 30, 2013 and 2012. Tug Services recorded revenues—affiliate from Cheniere Marketing of $2.1 million pursuant to this agreement in each of the nine months ended September 30, 2013 and 2012.

NOTE 10—SUPPLEMENTAL CASH FLOW INFORMATION AND DISCLOSURES OF NON-CASH TRANSACTIONS

The following table provides supplemental disclosure of cash flow information (in thousands):



	Nine Months Ended September 30,
	2013		2012
Class B units issued in connection with the Creole Trail Pipeline Business acquisition	$	180,000	$	—
LNG terminal costs funded with accounts payable and accrued liabilities (including amounts due to affiliates)	88,420		52,830
Cash paid during the period for interest, net of amounts capitalized and deferred	56,428		77,140

NOTE 11—CASH DISTRIBUTIONS AND NET INCOME (LOSS) PER COMMON UNIT

Cash Distributions

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 operating surplus as defined in the partnership agreement. The following provides a summary of distributions paid by us during the nine months ended September 30, 2013:



						Total Distribution (in thousands)
Date Paid	Period Covered by Distribution	Distribution Per Common Unit		Distribution Per Subordinated Unit		Common Units		Class B Units	Subordinated Units	General Partner Units
February 14, 2013	October 1 - December 31, 2012	$	0.425	$	—	$	16,783	—	—	$	342
May 15, 2013	January 1 - March 31, 2013	0.425		—		24,259		—	—	495
August 15, 2013	April 1 - June 30, 2013	0.425		—		24,259		—	—	495

The subordinated units will receive distributions only to the extent we have available cash above the initial quarterly distribution requirement for our common unitholders and general partner and certain reserves.

In 2012, we issued and sold 133.3 million Class B units to Blackstone and Cheniere at a price of $15.00 per Class B unit, resulting in total gross proceeds of $2.0 billion. In connection with our purchase of the Creole Trail Pipeline Business in May 2013, we issued and sold 12.0 million Class B units to Cheniere at a price of $15.00 per Class B unit. The Class B units were issued at a discount to the market price of the common units into which they are convertible. This discount totaling $2,130.0 million represents a beneficial conversion feature and is reflected as an increase in common and subordinated unitholders’ equity and a decrease in Class B unitholders’ equity to reflect the fair value of the Class B units at issuance on our consolidated statement of partners’ and owners' equity (deficit). The beneficial conversion feature is considered a dividend that will be distributed ratably with respect to any Class B unit from its issuance date through its conversion date, resulting in an increase in Class B unitholders’ equity and a decrease in common and subordinated unitholders’ equity. We amortize the beneficial conversion feature assuming a conversion date of June 2017 and August 2017 for Cheniere’s and Blackstone’s Class B units, respectively, although actual conversion may occur prior to or after these assumed dates. We are amortizing the beneficial conversion feature over the original 60 month conversion schedule using the effective yield method with a weighted average effective yield of 943.1% per year and 958.0% per year for Cheniere’s and Blackstone’s Class B units, respectively. The impact of the beneficial conversion feature is also included in earnings per unit for the three and nine months ended September 30, 2013 and 2012.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following is a schedule by years, based on the capital structure as of September 30, 2013, of the anticipated impact to the capital accounts in connection with the amortization of the beneficial conversion feature (in thousands):



	Common Units			Class B Units		Subordinated Units
2013	$	—		$	—	$	—
2014	(2		)	6		(4		)
2015	(241		)	813		(572		)
2016	(32,023		)	107,979		(75,955		)
2017	(538,538		)	1,815,883		(1,277,345		)

The Class B units will mandatorily convert into common units on the first business day following the record date with respect to Cheniere Partners’ first distribution (the "Mandatory Conversion Date") after the earlier of the substantial completion date of Train 3 or August 9, 2017, although if a notice to proceed is given to Bechtel for Train 3 prior to August 9, 2017, the Mandatory Conversion Date will be the substantial completion date of Train 3. The notice to proceed was given to Bechtel on May 28, 2013. If the Class B units are not mandatorily converted by July 2019, the holders of the Class B units have the option to convert the Class B units into common units at that time.

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. 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 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.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Under our partnership agreement, the incentive distribution rights ("IDRs") participate in net income (loss) only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in undistributed net income (loss). We did not allocate earnings or losses to IDR holders for the purpose of the two class method earnings per unit calculation for any of the periods presented. The following table provides a reconciliation of net income (loss) and the allocation of net income (loss) to the common units and the subordinated units for purposes of computing net income (loss) per unit (in thousands, except per unit data):



				Limited Partner Units
	Total			Common Units			Class B Units		Subordinated Units			General Partner			Creole Trail Pipeline Business
Three Months Ended September 30, 2013
Net loss	$	(98,109	)
Declared distributions	24,754			24,259			—		—			495
Assumed allocation of undistributed net loss	$	(122,863	)	(35,780		)	—		(84,865		)	(2,462		)	244
Assumed allocation of net loss				$	(11,521	)	$	—	$	(84,865	)	$	(1,967	)	$	244

Weighted average units outstanding				57,079			—		135,384
Net loss per unit				$	(0.20	)	$	—	$	(0.63	)

Three Months Ended September 30, 2012
Net loss	$	(51,370	)
Declared distributions	17,125			16,783			—		—			342
Amortization of beneficial conversion feature of Class B units	—			(2,971		)	14,888		(11,917		)	—
Assumed allocation of undistributed net loss	$	(68,495	)	(12,467		)	—		(42,744		)	(4,336		)	(8,948		)
Assumed allocation of net income (loss)				$	1,345		$	14,888	$	(54,661	)	$	(3,994	)	$	(8,948	)

Weighted average units outstanding				31,997			54,710		135,384
Net income (loss) per unit				$	0.04		$	0.27	$	(0.40	)

Nine Months Ended September 30, 2013
Net loss	$	(196,851	)
Declared distributions	74,261			72,776			—		—			1,485
Assumed allocation of undistributed net loss	$	(271,112	)	(73,521		)	—		(174,382		)	(5,059		)	(18,150		)
Assumed allocation of net income (loss)				$	(745	)	$	—	$	(174,382	)	$	(3,574	)	$	(18,150	)

Weighted average units outstanding				53,277			—		135,384
Net income (loss) per unit				$	(0.01	)	$	—	$	(1.29	)

Nine Months Ended September 30, 2012
Net loss	$	(106,818	)
Declared distributions	44,376			43,488			—		—			888
Amortization of beneficial conversion feature of Class B units	—			(3,863		)	19,625		(15,762		)	—
Assumed allocation of undistributed net loss	$	(151,194	)	(28,278		)	—		(96,948		)	(5,765		)	(20,203		)
Assumed allocation of net income (loss)				$	11,347		$	19,625	$	(112,710	)	$	(4,877	)	$	(20,203	)

Weighted average units outstanding				31,449			19,181		135,384
Net income (loss) per unit				$	0.36		$	1.02	$	(0.83	)

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

OPERATION

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, and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements, other than statements of historical fact, 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 Sabine Pass LNG, L.P. ("Sabine Pass LNG"), Sabine Pass Liquefaction, LLC ("Sabine Pass Liquefaction") or Cheniere Creole Trail Pipeline, L.P. ("CTPL");


•	statements regarding future levels of domestic and international natural gas production, supply or consumption or future levels of liquefied natural gas ("LNG") imports into or exports from North America and other countries worldwide, regardless of the source of such information, or the transportation or demand for and prices related to natural gas, LNG or other hydrocarbon products;


•	statements regarding any financing transactions or arrangements, or ability to enter into such transactions;


•	statements relating to the construction of our natural gas liquefaction trains ("Trains"), including statements concerning the engagement of any engineering, procurement and construction ("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 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, 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 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 and capital expenditures, 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 our anticipated LNG and natural gas marketing activities; and


•	any other statements that relate to non-historical or future information.

These forward-looking statements are often identified by the use of terms and phrases such as "achieve," "anticipate," "believe," "contemplate," "develop," "estimate," "expect," "forecast," "plan," "potential," "project," "propose," "strategy" and similar terms and phrases, or by the use of future tense. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve assumptions, risks and uncertainties, and these expectations may prove to be incorrect. You should not place undue reliance on these forward-looking statements, which are made as of the date of this quarterly report and speak only as of the date of this quarterly report.

Our actual results could differ materially from those anticipated in these forward-looking statements as a result of a variety of factors, including those discussed under "Risk Factors" in our Annual Report on Form 10-K for the year ended December 31, 2012, as amended by Amendment No. 1 on Form 10-K/A and in our Current Report of Form 8-K filed with the SEC on May 29, 2013. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. Other than as required under the securities laws, we assume no obligation to update or revise these forward-looking statements or provide reasons why actual results may differ.

As used herein, the terms "Cheniere Partners," "we," "our" and "us" refer to Cheniere Energy Partners, L.P. and its wholly owned subsidiaries.

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 in "Consolidated Financial Statements." 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 include the following subjects:


•	Overview of Business


•	Overview of Significant Events


•	Liquidity and Capital Resources


•	Results of Operations


•	Off-Balance Sheet Arrangements


•	Summary of Critical Accounting Policies and Estimates


•	Recent Accounting Standards

Overview of Business

We are a Delaware limited partnership formed by Cheniere Energy, Inc. ("Cheniere"). Through our wholly owned subsidiary, Sabine Pass LNG, we own and operate the regasification facilities at the Sabine Pass LNG terminal located on the Sabine Pass deep water shipping channel less than four miles from the Gulf Coast. The Sabine Pass LNG terminal includes existing infrastructure of five LNG storage tanks with capacity of approximately 16.9 Bcfe, two docks that can accommodate vessels with capacity of up to 265,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. Approximately one-half of the receiving capacity at the Sabine Pass LNG terminal is contracted to two multinational energy companies. We are developing natural gas liquefaction facilities (the "Liquefaction Project") at the Sabine Pass LNG terminal adjacent to the existing regasification facilities through a wholly owned subsidiary, Sabine Pass Liquefaction. We plan to construct up to six Trains, which are in various stages of development. Each Train is expected to have nominal production capacity of approximately 4.5 million tonnes per annum ("mtpa") of LNG. We also own the 94-mile long Creole Trail Pipeline through our wholly owned subsidiary, CTPL, which interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines (the "Creole Trail Pipeline").

Overview of Significant Events

Our significant accomplishments since January 1, 2013 and through the filing date of this Form 10-Q include the following:

•

Sabine Pass Liquefaction issued an aggregate principal amount of $2.0 billion of 5.625% Senior Secured Notes due 2021 (the "2021 Sabine Pass Liquefaction Senior Notes") and an aggregate principal amount of $1.0 billion of 5.625% Senior Secured Notes due 2023 (the "2023 Sabine Pass Liquefaction Senior Notes"). Net proceeds from those offerings are intended to be used to pay a portion of the capital costs incurred in connection with the construction of the Liquefaction Project;


•	We sold 17.6 million common units to institutional investors for net proceeds, after deducting expenses, of $372.4 million, which includes the general partner's proportionate capital contribution of approximately $7.4 million. We used the proceeds from that offering to purchase the Creole Trail Pipeline Business;


•	Sabine Pass Liquefaction entered into four credit facilities totaling $5.9 billion (collectively, the "2013 Liquefaction Credit Facilities") to be used for costs associated with the construction of Train 1 through Train 4 of the Liquefaction Project;


•	Sabine Pass Liquefaction issued a notice to proceed to Bechtel Oil, Gas and Chemicals, Inc. ("Bechtel") under the lump sum turnkey contract for the engineering, procurement and construction of Train 3 and Train 4 (the "EPC Contract (Train 3 and Train 4)");


•	Sabine Pass Liquefaction entered into an LNG sale and purchase agreement ("SPA") with Centrica plc ("Centrica") that commences upon the date of first commercial delivery for Train 5 and includes an annual contract quantity of 91.25 million MMBtu of LNG with a fixed fee of $3.00 per MMBtu, equating to expected annual contracted cash flow from fixed fees of $274.0 million;

•

In May 2013, we completed the acquisition of 100% of the equity interests in Cheniere Pipeline GP Interests, LLC held by Cheniere Pipeline Company, and the limited partner interest in CTPL held by Grand Cheniere Pipeline, LLC ("the Creole Trail Pipeline Business") for $480.0 million and reimbursed Cheniere $13.9 million for certain expenditures incurred prior to the closing date. Concurrent with the Creole Trail Pipeline Business acquisition closing, we issued 12.0 million Class B units to Cheniere for aggregate consideration of $180.0 million pursuant to a unit purchase agreement with Cheniere Class B Units Holdings, LLC, a wholly owned subsidiary of Cheniere. As a result of the two transactions, we paid Cheniere net cash of $313.9 million;


•	CTPL entered into a $400.0 million term loan credit facility to fund capital expenditures on the Creole Trail Pipeline and for general business purposes; and


•	We entered into an equity distribution agreement with Mizuho Securities USA Inc., under which we may sell up to $500.0 million of common units through an at-the-market program.

Liquidity and Capital Resources

Cash and Cash Equivalents

As of September 30, 2013, we had $339.9 million of cash and cash equivalents and $1,038.4 million of restricted cash and cash equivalents.

Sabine Pass LNG Terminal

Regasification Facilities

The Sabine Pass LNG terminal has operational regasification capacity of approximately 4.0 Bcf/d and aggregate LNG storage capacity of approximately 16.9 Bcfe. Approximately 2.0 Bcf/d of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term third-party terminal use agreements ("TUAs"), under which Sabine Pass LNG’s customers are required to pay fixed monthly fees, whether or not they use the LNG terminal. Capacity reservation fee TUA payments are made by Sabine Pass LNG's third-party TUA customers as follows:

•

Total Gas & Power North America, Inc. ("Total") has reserved approximately 1.0 Bcf/d of regasification capacity and is obligated to make monthly capacity payments to Sabine Pass LNG aggregating approximately $125 million annually for 20 years that commenced April 1, 2009. Total, S.A. has guaranteed Total’s obligations under its TUA of approximately $2.5 billion, subject to certain exceptions; and


•	Chevron U.S.A. Inc. ("Chevron") has reserved approximately 1.0 Bcf/d of regasification capacity and is obligated to make monthly capacity payments to Sabine Pass LNG aggregating approximately $125 million annually for 20 years that commenced July 1, 2009. Chevron Corporation has guaranteed Chevron’s obligations under its TUA up to 80% of the fees payable by Chevron.

The remaining approximately 2.0 Bcf/d of capacity has been reserved under a TUA by Sabine Pass Liquefaction. Sabine Pass Liquefaction is obligated to make monthly capacity payments to Sabine Pass LNG aggregating approximately $250 million annually, continuing until at least 20 years after Sabine Pass Liquefaction delivers its first commercial cargo at Sabine Pass Liquefaction's facilities under construction, which may occur as early as late 2015. Cheniere Energy Investments, LLC ("Cheniere Investments"), our wholly owned subsidiary, Sabine Pass Liquefaction and Sabine Pass LNG entered into a terminal use rights assignment and agreement ("TURA") pursuant to which Cheniere Investments has the right to use Sabine Pass Liquefaction's reserved capacity under the TUA and has the obligation to make the monthly capacity payments required by the TUA to Sabine Pass LNG. In an effort to utilize Cheniere Investments’ reserved capacity under its TURA during construction of the Liquefaction Project, Cheniere Marketing, LLC ("Cheniere Marketing"), a wholly owned subsidiary of Cheniere, has entered into an amended and restated variable capacity rights agreement ("amended and restated VCRA") pursuant to which Cheniere Marketing is obligated to pay Cheniere Investments 80% of the expected gross margin of each cargo of LNG that Cheniere Marketing arranges for delivery to the Sabine Pass LNG terminal. The revenue earned by Sabine Pass LNG from the capacity payments made under the TUA and the loss incurred by Cheniere Investments under the TURA are eliminated upon consolidation of our financial statements. We have guaranteed the obligations of Sabine Pass Liquefaction under its TUA and the obligations of Cheniere Investments under the TURA.

In September 2012, Sabine Pass Liquefaction entered into a partial TUA assignment agreement with Total, whereby Sabine Pass Liquefaction will progressively gain access to Total's capacity and other services provided under Total's TUA with Sabine Pass LNG. This agreement will provide Sabine Pass Liquefaction with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to accommodate the development of Train 5 and Train 6, provide increased flexibility in managing LNG cargo loading and unloading activity starting with the commencement of commercial operations of Train 3, and permit Sabine Pass Liquefaction to more flexibly manage its LNG storage capacity with the commencement of Train 1. Notwithstanding any arrangements between Total and Sabine Pass Liquefaction, payments required to be made by Total to Sabine Pass LNG will continue to be made by Total to Sabine Pass LNG in accordance with its TUA.

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

Liquefaction Facilities

The Liquefaction Project is being developed at the Sabine Pass LNG terminal adjacent to the existing regasification facilities. We plan to construct up to six Trains, which are in various stages of development. In August 2012, we commenced construction of Train 1 and Train 2 and the related new facilities needed to treat, liquefy, store and export natural gas. In May 2013, we commenced construction of Train 3 and Train 4 and the related facilities. We are developing Train 5 and Train 6 and commenced the regulatory approval process for these Trains in February 2013. Trains 1 through 4 are being designed, constructed and commissioned by Bechtel using the ConocoPhillips Optimized Cascade® technology, a proven technology deployed in numerous LNG projects around the world. Sabine Pass Liquefaction has entered into a lump sum turnkey contract for the engineering, procurement and construction of Train 1 and Train 2 (the "EPC Contract (Train 1 and Train 2)") and the EPC Contract (Train 3 and Train 4) with Bechtel in November 2011 and December 2012, respectively, under which Bechtel charges a lump sum for all work performed and generally bears project cost risk.

We have received authorization from the Federal Energy Regulatory Commission (the "FERC") to site, construct and operate Train 1, Train 2, Train 3 and Train 4. We have also filed an application with the FERC for the approval to construct Train 5 and Train 6. The Department of Energy (the "DOE") has granted Sabine Pass Liquefaction an order authorizing the export of up to the equivalent of 16 mtpa (approximately 803 Bcf/yr) of LNG to all nations with which trade is permitted for a 20-year term beginning on the earlier of the date of first export from Train 1 or August 7, 2017. The DOE further issued two orders authorizing the export of an additional 189.3 Bcf/yr in total of domestically produced LNG from the Sabine Pass LNG terminal to FTA countries providing for national treatment for trade in natural gas for a 20-year term. One order authorized the export of 101 Bcf/yr of domestically produced LNG pursuant to the SPA with Total, beginning on the earlier of the date of first export from Train 5 or July 11, 2021; and the other order authorized the export of 88.3 Bcf/yr of domestically produced LNG pursuant to the SPA with Centrica, beginning on the earlier of the date of first export from Train 5 or July 12, 2021.

As of September 30, 2013, the overall project completion for Train 1 and Train 2 of the Liquefaction Project was approximately 45%, which is ahead of the contractual schedule. As of September 30, 2013, the overall project completion for Train 3 and Train 4 of the Liquefaction Project was approximately 10%, which is ahead of the contractual schedule. Based on our current construction schedule, we anticipate that Train 1 will produce LNG as early as late 2015, with commercial operations expected to commence in February 2016, and Train 2, Train 3 and Train 4 are expected to commence operations on a staggered basis thereafter.

Customers

Sabine Pass Liquefaction has entered into six fixed price, 20-year SPAs with third parties that in the aggregate equate to approximately 19.75 mtpa of LNG, which represents approximately 88% of the anticipated nominal production capacity of Train 1 through Train 5. Under the SPAs, the customers will purchase LNG from us on an FOB basis for a price consisting of a fixed fee plus 115% of Henry Hub per MMBtu of LNG. In certain circumstances, the customers may elect to cancel or suspend deliveries of LNG cargoes, in which case the customers would still be required to pay the fixed fee with respect to cargoes that are not delivered. A portion of the fixed fee will be subject to annual adjustment for inflation. 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 commences upon the start of operations of the specified Train.

To date, Sabine Pass Liquefaction has the following third-party SPAs:

•

BG Gulf Coast LNG, LLC ("BG") has entered into an SPA (the "BG SPA") that commences upon the date of first commercial delivery for Train 1 and includes an annual contract quantity of 182,500,000 MMBtu of LNG with a fixed fee of $2.25 per MMBtu and includes additional annual contract quantities of 36,500,000 MMBtu, 34,000,000 MMBtu, and 33,500,000 MMBtu upon the date of first commercial delivery for Train 2, Train 3 and Train 4, respectively, with a fixed fee of $3.00 per MMBtu. The total expected annual contracted cash flow from BG from fixed fees is approximately $723 million. In addition, Sabine Pass Liquefaction has agreed to make up to 500,000 MMBtu/d of LNG available to BG to the extent that Train 1 becomes commercially operable prior to the beginning of the first delivery window with a fixed fee of $2.25 per MMBtu, if produced. The obligations of BG are guaranteed by BG Energy Holdings Limited, a company organized under the laws of England and Wales.

•

Gas Natural Aprovisionamientos SDG S.A.("Gas Natural Fenosa") has entered into an SPA (the "Gas Natural Fenosa SPA") that commences upon the date of first commercial delivery for Train 2 and includes an annual contract quantity of 182,500,000 MMBtu of LNG with a fixed fee of $2.49 per MMBtu, equating to expected annual contracted cash flow from fixed fees of approximately $454 million. In addition, Sabine Pass Liquefaction has agreed to make up to 285,000 MMBtu/d of LNG available to Gas Natural Fenosa to the extent that Train 2 becomes commercially operable prior to the beginning of the first delivery window with a fixed fee of $2.49 per MMBtu, if produced. The obligations of Gas Natural Fenosa are guaranteed by Gas Natural SDG S.A., a company organized under the laws of Spain.

•

Korea Gas Corporation ("KOGAS") has entered into an SPA (the "KOGAS SPA") that commences upon the date of first commercial delivery for Train 3 and includes an annual contract quantity of 182,500,000 MMBtu of LNG with a fixed fee of $3.00 per MMBtu, equating to expected annual contracted cash flow from fixed fees of approximately $548 million. KOGAS is organized under the laws of the Republic of Korea.


•	GAIL (India) Limited ("GAIL") has entered into an SPA (the "GAIL SPA") that commences upon the date of first commercial delivery for Train 4 and includes an annual contract quantity of 182,500,000 MMBtu of LNG with a fixed fee of $3.00 per MMBtu, equating to expected annual contracted cash flow from fixed fees of approximately $548 million. GAIL is organized under the laws of India.

•

Total has entered into an SPA (the "Total SPA") that commences upon the date of first commercial delivery for Train 5 and includes an annual contract quantity of 104,750,000 MMBtu of LNG with a fixed fee of $3.00 per MMBtu, equating to expected annual contracted cash flow from fixed fees of approximately $314 million. The obligations of Total are guaranteed by Total S.A., a company organized under the laws of France.


•	Centrica has entered into an SPA (the "Centrica SPA") that commences upon the date of first commercial delivery for Train 5 and includes an annual contract quantity of 91,250,000 MMBtu of LNG with a fixed fee of $3.00 per MMBtu, equating to expected annual contracted cash flow from fixed fees of approximately $274 million. Centrica is organized under the laws of England and Wales.

In aggregate, the fixed fee portion to be paid by these customers is approximately $2.3 billion annually for Train 1 through Train 4, and $2.9 billion annually if we make a positive final investment decision with respect to Train 5, with the applicable fixed fees starting from the commencement of commercial operations for the applicable Train. These fixed fees equal approximately $411 million, $564 million, $650 million, $648 million and $588 million for each respective Train.

In addition, Cheniere Marketing has entered into an SPA with Sabine Pass Liquefaction to purchase, at Cheniere Marketing's option, up to 104,000,000 MMBtu/yr of LNG produced from Train 1 through Train 4. Sabine Pass Liquefaction has the right each year during the term to reduce the annual contract quantity based on its assessment of how much LNG it can produce in excess of that required for other customers. Cheniere Marketing may purchase incremental LNG volumes at a price of 115% of Henry Hub: plus up to $3.00 per MMBtu for the most profitable 36,000,000 MMBtu of cargoes sold each year by Cheniere Marketing; and then 20% of net profits of the remaining 68,000,000 MMBtu sold each year by Cheniere Marketing.

Construction

In November 2011, Sabine Pass Liquefaction entered into the EPC Contract (Train 1 and Train 2) with Bechtel. Sabine Pass Liquefaction issued a notice to proceed with construction under the EPC Contract (Train 1 and Train 2) in August 2012. In December 2012, Sabine Pass Liquefaction entered into the EPC Contract (Train 3 and Train 4) with Bechtel. Sabine Pass Liquefaction issued a notice to proceed with construction under the EPC Contract (Train 3 and Train 4) in May 2013. The Trains are in various stages of development, as described above.

The total contract price of the EPC Contract (Train 1 and Train 2) and the total contract price of the EPC Contract (Train 3 and Train 4) is approximately $4.0 billion and $3.8 billion, respectively, reflecting amounts incurred under change orders through September 30, 2013. Total expected capital costs for Train 1 through Train 4 are estimated to be between $9.0 billion and $10.0 billion before financing costs, and between $12.0 billion and $13.0 billion after financing costs, including in each case estimated owner's costs and contingencies. Sabine Pass Liquefaction's Trains will require significant amounts of capital to construct and operate and are subject to risks and delays in completion.

The liquefaction technology to be employed under the EPC Contracts is the ConocoPhillips Optimized Cascade® Process, which was first used at the ConocoPhillips Petroleum Kenai plant built by Bechtel in 1969 in Kenai, Alaska. Bechtel has since designed and/or constructed LNG facilities using the ConocoPhillips Optimized Cascade® technology in Angola, Australia, Egypt, Equatorial Guinea and Trinidad. The design and technology has been proven in over four decades of operation.

We currently expect that Sabine Pass Liquefaction's capital resources requirements with respect to Train 1 through Train 4 will be financed through borrowings, equity contributions from us and cash flows under the SPAs. We believe that with the net proceeds of borrowings and unfunded commitments under the 2013 Liquefaction Credit Facilities, Sabine Pass Liquefaction will have adequate financial resources available to complete Train 1 through Train 4 and to meet its currently anticipated capital, operating and debt service requirements. We currently project that Sabine Pass Liquefaction will generate cash flow by late 2015, when Train 1 is anticipated to achieve initial LNG production.

Pipeline Facilities

CTPL owns the Creole Trail Pipeline, a 94-mile pipeline interconnecting the Sabine Pass LNG terminal with a number of large interstate pipelines, including Natural Gas Pipeline Company of America, Transcontinental Gas Pipeline Corporation, Tennessee Gas Pipeline Company, Florida Gas Transmission Company, Texas Eastern Gas Transmission, and Trunkline Gas Company, as well as the intrastate pipeline system of Bridgeline Holdings, L.P. Sabine Pass Liquefaction has entered into transportation precedent agreements to secure firm pipeline transportation capacity with CTPL and two other pipeline companies.

CTPL will need to obtain the FERC's approval prior to making any modifications to the Creole Trail Pipeline as it is a regulated, interstate pipeline. An application for authorization to construct, own, operate and maintain certain new facilities in order to enable bi-directional natural gas flow on the Creole Trail Pipeline system was submitted to the FERC by CTPL in April 2012. In February 2013, the FERC approved the proposed project, and in October 2013, the FERC issued an order denying petitioner's request for rehearing and stay of the approval. In addition, in November 2013, CTPL received approval from the Louisiana Department of Environmental Quality for the proposed modifications to the Creole Trail Pipeline system. We estimate the capital costs to modify the Creole Trail Pipeline will be approximately $100 million. The modifications are expected to be in service in time for the commissioning and testing of Train 1 and Train 2.

Capital Resources

Senior Secured Notes

We currently have four series of senior notes outstanding:

•$1,665.5 million of 7.50% Senior Secured Notes due 2016 issued by Sabine Pass LNG (the "2016 Notes");

•$420.0 million of 6.50% Senior Secured Notes due 2020 issued by Sabine Pass LNG (the "2020 Notes" and

collectively with the 2016 Notes, the "Sabine Pass LNG Senior Notes");

•$2,000.0 million of the 2021 Sabine Pass Liquefaction Senior Notes; and

•$1,000.0 million of the 2023 Sabine Pass Liquefaction Senior Notes (collectively with the 2021 Sabine Pass

Liquefaction Notes, the "Sabine Pass Liquefaction Senior Notes").

Interest on the 2016 Notes is payable semi-annually in arrears on May 30 and November 30 of each year, interest on the 2020 Notes is payable semi-annually in arrears on May 1 and November 1 of each year, interest on the 2021 Sabine Pass Liquefaction Senior Notes is payable semi-annually in arrears on February 1 and August 1 of each year and interest on the 2023 Sabine Pass Liquefaction Senior Notes is payable semi-annually in arrears on April 15 and October 15 of each year. Subject to permitted liens, the Sabine Pass LNG Senior Notes are secured on a pari passu first-priority basis by a security interest in all of Sabine Pass LNG's equity interests and substantially all of Sabine Pass LNG's operating assets, and the Sabine Pass Liquefaction Senior Notes are secured on a first-priority basis by a security interest in all of the membership interests in Sabine Pass Liquefaction and substantially all of Sabine Pass Liquefaction's assets.

Sabine Pass LNG may redeem some or all of its 2016 Notes at any time, and from time to time, at the redemption prices specified in the indenture governing the 2016 Notes, plus accrued and unpaid interest, if any, to the date of redemption. Sabine Pass LNG may redeem some or all of the 2020 Notes at any time on or after November 1, 2016 at fixed redemption prices specified in the indenture governing the 2020 Notes, plus accrued and unpaid interest, if any, to the date of redemption. Sabine Pass LNG may also redeem some or all of the 2020 Notes at any time prior to November 1, 2016 at a "make-whole" price set forth in the indenture, plus accrued and unpaid interest, if any, to the date of redemption. At any time before November 1, 2015, Sabine Pass LNG may redeem up to 35% of the aggregate principal amount of the 2020 Notes at a redemption price of 106.5% of the principal amount of the 2020 Notes to be redeemed, plus accrued and unpaid interest, if any, to the redemption date, in an amount not to exceed the net proceeds of one or more completed equity offerings as long as Sabine Pass LNG redeems the 2020 Notes within 180 days of the closing date for such equity offering and at least 65% of the aggregate principal amount of the 2020 Notes originally issued remains outstanding after the redemption.

Under the indentures governing the Sabine Pass LNG Senior Notes, except for permitted tax distributions, Sabine Pass LNG may not make distributions until, among other requirements, deposits are made into debt service reserve accounts and a fixed charge coverage ratio test of 2:1 is satisfied. Under the indentures governing the Sabine Pass Liquefaction Senior Notes, Sabine Pass Liquefaction may not make any distributions until, among other requirements, substantial completion of Train 1 and Train 2 has occurred, deposits are made into debt service reserve accounts and a debt service coverage ratio for the prior 12-month period and a projected debt service coverage ratio for the upcoming 12-month period of 1.25:1.00 are satisfied.

Sabine Pass Liquefaction 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 Sabine Pass Liquefaction, including the Sabine Pass Liquefaction Senior Notes and the 2013 Liquefaction Credit Facilities described below.

2013 Liquefaction Credit Facilities

Sabine Pass Liquefaction has four credit facilities aggregating $5.9 billion, which will be used to fund a portion of the costs of developing, constructing and placing into operation Train 1 through Train 4 of the Liquefaction Project. The principal of the loans made under the 2013 Liquefaction Credit Facilities must be repaid in quarterly installments, commencing with the earlier of the last day of the first full calendar quarter after the Train 4 completion date and September 30, 2018. Loans under the 2013 Liquefaction Credit Facilities bear interest at a variable rate per annum equal to, at Sabine Pass Liquefaction's election, the London Interbank Offered Rate ("LIBOR"), plus the applicable margin. The applicable margins for LIBOR loans prior to, and after, the completion of Train 4 range from 2.3% to 3.0% and 2.3% to 3.25%, respectively, depending on the applicable 2013 Liquefaction Credit Facility. The 2013 Liquefaction Credit Facilities also require Sabine Pass Liquefaction to pay a commitment fee calculated at a rate per annum equal to 40% of the applicable margin for LIBOR loans, multiplied by the average daily amount of the undrawn commitments. Interest on LIBOR loans and the commitment fees are due and payable at the end of each LIBOR period.

2012 Liquefaction Credit Facility

In July 2012, Sabine Pass Liquefaction entered into a construction/term loan facility in an amount up to $3.6 billion (the "2012 Liquefaction Credit Facility"), which was available to Sabine Pass Liquefaction in four tranches solely to fund Liquefaction Project costs for Train 1 and Train 2, the related debt service reserve account up to an amount equal to six months of scheduled debt service and the return of equity and affiliate subordinated debt funding to Cheniere or its affiliates up to an amount that would result in senior debt being no more than 65% of our total capitalization. Borrowings under the 2012 Liquefaction Credit Facility were based on LIBOR plus 3.50% during construction and 3.75% during operations. Sabine Pass Liquefaction was also required to pay commitment fees on the undrawn amount. The 2012 Credit Facility was amended and restated with the 2013 Liquefaction Credit Facilities.

CTPL Credit Facility

CTPL has a $400 million term loan facility (the "CTPL Credit Facility"), which will be used to fund modifications to the Creole Trail Pipeline and for general business purposes. Loans under the CTPL Credit Facility bear interest at a variable rate per annum equal to, at CTPL's election, LIBOR or the base rate, plus the applicable margin. The applicable margin for LIBOR loans under the CTPL Credit Facility is 3.25%. The CTPL Credit Facility matures in 2017 when the full amount of the outstanding principal obligations must be repaid.

Sources and Uses of Cash

The following table summarizes (in thousands) the sources and uses of our cash and cash equivalents for the nine months ended September 30, 2013 and 2012. The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, that are referred to elsewhere in this report. Additional discussion of these items follows the table.



	Nine Months Ended September 30,
	2013			2012
Sources of cash and cash equivalents
Proceeds from debt issuances and credit facilities	$	3,504,478		$	100,000
Proceeds from the sale of partnership common and general partner units	375,897			240,114
Proceeds from sale of Class B units	—			1,387,560
Contributions to Creole Trail Pipeline Business from Cheniere, net	20,896			9,608
Total sources of cash and cash equivalents	3,901,271			1,737,282

Uses of cash and cash equivalents
LNG terminal costs, net	(2,449,360		)	(876,593		)
Investment in restricted cash and cash equivalents, net of uses of restricted cash and cash equivalents	(785,847		)	(289,851		)
Purchase of Creole Trail Pipeline Business, net	(313,892		)	—
Debt issuance and deferred financing costs	(231,198		)	(210,126		)
Repayment of 2012 Liquefaction Credit Facility	(100,000		)	—
Distributions to unitholders	(66,632		)	(40,696		)
Operating cash flow	(16,091		)	(14,940		)
Advances under long-term contracts	(12,528		)	(15,009		)
Other	(5,120		)	(2,382		)
Total uses of cash and cash equivalents	(3,980,668		)	(1,449,597		)

Net increase (decrease) in cash and cash equivalents	(79,397		)	287,685
Cash and cash equivalents—beginning of period	419,292			81,415
Cash and cash equivalents—end of period	$	339,895		$	369,100

Proceeds from the Debt Issuances and Credit Facilities and Repayment of 2012 Liquefaction Credit Facility

In February 2013 and April 2013, Sabine Pass Liquefaction issued an aggregate principal amount of $2.0 billion, before premium, of the 2021 Sabine Pass Liquefaction Senior Notes. In April 2013, Sabine Pass Liquefaction also issued $1.0 billion of the 2023 Sabine Pass Liquefaction Senior Notes. Net proceeds from those offerings are intended to be used to pay a portion of the capital costs incurred in connection with the construction of the Liquefaction Project. In May 2013, Sabine Pass Liquefaction closed the 2013 Liquefaction Credit Facilities aggregating $5.9 billion. The 2013 Liquefaction Credit Facilities are being used to fund a portion of the costs of developing, constructing and placing into operation the first four Trains of the Liquefaction Project. Sabine Pass Liquefaction made a $100.0 million borrowing under the 2013 Liquefaction Credit Facilities in June 2013 after meeting the required conditions precedent. Also in May 2013, CTPL entered into the $400.0 million CTPL Credit Facility, which will be used to fund modifications to the Creole Trail Pipeline and for general business purposes.

Proceeds from the Sale of Partnership Common and General Partner Units

The proceeds from the sale of partnership common and general partner units in the nine months ended September 30, 2013 related to a February 2013 common unit purchase agreement with institutional investors to sell 17.6 million common units for net proceeds, after deducting expenses, of $372.4 million, which included the general partner's proportionate capital contribution of approximately $7.4 million. We used the proceeds from the February 2013 offering to purchase the Creole Trail Pipeline Business. In May 2013, we received proceeds of $3.7 million from the general partner's proportionate capital contribution related to our issuance of 12.0 million Class B units to Cheniere discussed above.

In September 2012, we sold 8.0 million common units in an underwritten public offering at a price of $25.07 per common unit for net cash proceeds of $194.0 million. In addition, during the nine months ended September 30, 2012, we sold 0.5 million common units for net cash proceeds of $11.1 million under the at-the-market program initiated in January 2011.

Proceeds from the Sale of Class B Units

Concurrent with the Creole Trail Pipeline Business acquisition in May 2013, we issued 12.0 million Class B units to Cheniere for aggregate consideration of $180.0 million. See Purchase of the Creole Trail Pipeline, net below.

During the nine months ended September 30, 2012, we issued and sold an aggregate of 100.0 million Class B units to Cheniere and Blackstone pursuant to unit purchase agreements for total consideration of $1.5 billion, before fees. Proceeds from the Class B unit sales are being used to fund the equity portion of the costs of developing, constructing and placing into service the Liquefaction Project.

Contributions to Creole Trail Pipeline Business from Cheniere, net

Contributions to Creole Trail Pipeline Business from Cheniere, net relate to equity contributions provided by Cheniere to the entities owning the Creole Trail Pipeline that we purchased in May 2013. The acquisition has been accounted for as a transfer of net assets between entities under common control. During the period from January 1, 2013 to the purchase date, Cheniere contributed $20.9 million to the Creole Trail Pipeline entities that we acquired. During the nine months ended September 30, 2012, Cheniere contributed $9.6 million to the Creole Trail Pipeline entities that we acquired.

LNG Terminal Costs, net

LNG terminal costs, net primarily related to the construction of Train 1 through Train 4 of the Liquefaction Project. In June 2012, we began capitalizing costs associated with Train 1 and Train 2 of the Liquefaction Project, and in May 2013, we began capitalizing costs associated with Train 3 and Train 4 of the Liquefaction Project.

Investment in Restricted Cash and Cash Equivalents, Net of Uses of Restricted Cash and Cash Equivalents

In the nine months ended September 30, 2013, we invested a net $785.8 million in restricted cash and cash equivalents. This investment in restricted cash and cash equivalents is primarily a result of a $3,243.7 million investment in restricted cash and cash equivalents primarily related to the net proceeds from the Sabine Pass Liquefaction Senior Notes, the CTPL Credit Facility and the 2013 Liquefaction Credit Facilities. This investment in restricted cash and cash equivalents was partially offset by the use of $2,457.8 million of restricted cash and cash equivalents primarily related to the construction of the Liquefaction Project.

Purchase of the Creole Trail Pipeline, net

In May 2013, we completed the acquisition of the Creole Trail Pipeline Business for $480.0 million and reimbursed Cheniere $13.9 million for certain expenditures incurred prior to the closing date. Concurrent with the Creole Trail Pipeline Business acquisition closing, we issued 12.0 million Class B units to Cheniere for aggregate consideration of $180.0 million pursuant to a unit purchase agreement with Cheniere Class B Units Holdings, LLC, a wholly owned subsidiary of Cheniere. As a result of the two transactions, we paid Cheniere net cash of $313.9 million.

Debt Issuance and Deferred Financing Costs

Debt issuance and deferred financing costs in the nine months ended September 30, 2013 resulted from amounts paid by Sabine Pass Liquefaction related to the 2013 Liquefaction Credit Facilities and the Sabine Pass Liquefaction Senior Notes and amounts paid by CTPL related to the CTPL Credit Facility.

Debt issuance and deferred financing costs in the nine months ended September 30, 2012 resulted from amounts paid by Sabine Pass Liquefaction upon the closing of the 2012 Liquefaction Credit Facility.

Distributions to Unitholders

During the nine months ended September 30, 2013 and 2012, we distributed $66.6 million and $40.7 million, respectively, to our common and general partner unitholders. The increase in distributions from 2012 to 2013 is the result of the issuance of common units to the public in September 2012 and February 2013 and the increase in general partner units to maintain its 2% ownership interest in us.

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 nine months ended September 30, 2013:



						Total Distribution (in thousands)
Date Paid	Period Covered by Distribution	Distribution Per Common Unit		Distribution Per Subordinated Unit		Common Units		Class B Units		Subordinated Units		General Partner Units
February 14, 2013	October 1 - December 31, 2012	$	0.425	$	—	$	16,783	$	—	$	—	$	342
May 15, 2013	January 1 - March 31, 2013	0.425		—		24,259		—		—		495
August 15, 2013	April 1 - June 30, 2013	0.425				24,259		—		—		495

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 or fees received from Cheniere Marketing under the amended and restated VCRA. The ending of the subordination period and conversion of the subordinated units into common units will depend upon future business development.

In 2012, we issued Class B units in connection with the development of the Liquefaction Project. The Class B units are not entitled to cash distributions except in the event of our liquidation, our merger, consolidation or other combination with another person or the sale of all or substantially all of our assets. The Class B units are subject to conversion, mandatorily or at the option of the holders of the Class B units under specified circumstances, into a number of common units based on the then-applicable conversion value of the Class B units. On a quarterly basis beginning on the initial purchase of the Class B units, and ending on the conversion date of the Class B units, the conversion value of the Class B units increases at a compounded rate of 3.5% per quarter, subject to an additional upward adjustment for certain equity and debt financings. The accreted conversion ratio of the Class B units owned by Cheniere and Blackstone was 1.19 and 1.17, respectively, as of September 30, 2013. The Class B units will mandatorily convert into common units on the first business day following the record date with respect to our first distribution (the "Mandatory Conversion Date") after the earlier of the substantial completion date of Train 3 or August 9, 2017, although if a notice to proceed is given to Bechtel for Train 3 prior to August 9, 2017, the Mandatory Conversion Date will be the substantial completion date of Train 3. The notice to proceed was given to Bechtel on May 28, 2013. We currently expect the substantial completion date of Train 3 to occur before March 31, 2017. If the Class B units are not mandatorily converted by July 2019, the holders of the Class B units have the option to convert the Class B units into common units at that time.

The following table illustrates the number of common units into which the Class B units would convert at the dates specified below (amounts in thousands) and the percentage ownership of the then outstanding limited partner interests, assuming that none of the outstanding Class B units are optionally converted prior to the dates set forth in the table and that no additional limited partner interests are issued by us prior to such dates:



	December 31, 2013 ⁽¹⁾	December 31, 2014 ⁽¹⁾	December 31, 2015 ⁽¹⁾	December 31, 2016	December 31, 2017	December 31, 2018	July 9, 2019
Cheniere:
Number of Common Units	55,821	64,050	73,491	84,357	96,792	110,060	119,362
Percentage Ownership	53.9%	52.4%	50.9%	49.4%	47.9%	46.5%	45.8%
Blackstone:
Number of Common Units	121,118	138,934	159,371	182,881	209,782	240,640	258,550
Percentage Ownership	32.1%	34.4%	36.7%	39.0%	41.2%	43.3%	44.4%

(1)Information as of December 31, 2013, 2014 and 2015 is presented for informational purposes only. We do not believe

that the Class B units will convert, either mandatorily or optionally, into common units prior to such dates.

The holders of Class B units have a preference over the holders of the subordinated units in the event of our liquidation, our merger, consolidation or other combination with another person or the sale of all or substantially all of our assets.

On October 22, 2013, we declared a $0.425 distribution per common unit and the related distribution to our general partner to be paid to owners of record on November 1, 2013 for the period from July 1, 2013 to September 30, 2013.

Results of Operations

Three Months Ended September 30, 2013 vs. Three Months Ended September 30, 2012

Our consolidated net loss increased $46.7 million, from $51.4 million of net loss in the three months ended September 30, 2012, to $98.1 million of net loss in the three months ended September 30, 2013. The increase in net loss was primarily a result of increased derivative loss, operating and maintenance expense (including affiliate expense) and general and administrative expense (including affiliate expense), which was partially offset by decreased development expense (including affiliate expense). Derivative loss increased $22.6 million in the three months ended September 30, 2013 as compared to the three months ended September 30, 2012 primarily as a result of the change in fair value of Sabine Pass Liquefaction's interest rate derivatives to hedge the exposure to volatility in a portion of the floating-rate interest payments under the 2013 Liquefaction Credit Facilities. Operating and maintenance expense (including affiliate expense) increased $15.8 million in the three months ended September 30, 2013 as compared to the three months ended September 30, 2012 primarily as a result of the loss incurred to purchase LNG to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal and increased LNG terminal maintenance and repair costs and increased fuel costs at the Sabine Pass LNG terminal. Our general and administrative expense (including affiliate expense) increased $3.3 million in the three months ended September 30, 2013 as compared to the three months ended September 30, 2012 primarily as a result of increased costs incurred to manage the construction of Train 1 through Train 4 of the Liquefaction Project, which resulted from a management services agreement entered into by Sabine Pass Liquefaction, in which Sabine Pass Liquefaction is required to pay a wholly owned subsidiary of Cheniere a monthly fee based upon the capital expenditures incurred in the previous month for the Liquefaction Project. Development expense (including affiliate expense) decreased $2.8 million in the three months ended September 30, 2013 as compared to the three months ended September 30, 2012 primarily as a result of Train 1 and Train 2 satisfying the criteria for capitalization in June 2012 and Train 3 and Train 4 of the Liquefaction Project satisfying the criteria for capitalization in May 2013. We continue to incur development expenses for Train 5 and Train 6.

Nine Months Ended September 30, 2013 vs. Nine Months Ended September 30, 2012

Our consolidated net loss increased $90.0 million, from $106.8 million of net loss in the nine months ended September 30, 2012, to $196.9 million of net loss in the nine months ended September 30, 2013. The increase in net loss was primarily a result of loss on the early extinguishment of debt, increased general and administrative expense (including affiliate expense) and increased operating and maintenance expense (including affiliate expense), which was partially offset by increased derivative gain and decreased development expense (including affiliate expense). Loss on early extinguishment of debt increased $80.5 million in the nine months ended September 30, 2013 as compared to the nine months ended September 30, 2012 as a result of of the amendment and restatement of the 2012 Liquefaction Credit Facility with the 2013 Liquefaction Credit Facilities. Our general and administrative expense (including affiliate expense) increased $52.5 million in the nine months ended September 30, 2013 as compared to the nine months ended September 30, 2012 primarily as a result of increased costs incurred to manage the construction of Train 1 through Train 4 of the Liquefaction Project, which resulted from a management services agreement entered into by Sabine Pass Liquefaction, in which Sabine Pass Liquefaction is required to pay a wholly owned subsidiary of Cheniere a monthly fee based upon the capital expenditures incurred in the previous month for the Liquefaction Project. Operating and maintenance expense (including affiliate expense) increased $41.7 million in the nine months ended September 30, 2013 as compared to the nine months ended September 30, 2012 primarily as a result of the loss incurred to purchase LNG to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal, increased LNG terminal maintenance and repair costs and increased fuel costs at the Sabine Pass LNG terminal and increased costs to manage the operation and maintenance of the regasification facilities at the Sabine Pass LNG terminal under Sabine Pass LNG's long-term operation and maintenance agreement with a wholly owned subsidiary of Cheniere. Derivative gain increased $56.0 million in the nine months ended September 30, 2013 as compared to the nine months ended September 30, 2012 primarily as a result of the change in fair value of Sabine Pass Liquefaction's interest rate derivatives. Development expense (including affiliate expense) decreased $28.4 million in the nine months ended September 30, 2013 as compared to the nine months ended September 30, 2012 primarily as a result of Train 1 and Train 2 satisfying the criteria for capitalization in June 2012 and Train 3 and Train 4 of the Liquefaction Project satisfying the criteria for capitalization in May 2013. We continue to incur development expenses for Train 5 and Train 6.

Off-Balance Sheet Arrangements

As of September 30, 2013, we had no "off-balance sheet arrangements" that may have a current or future material effect on our consolidated financial position or results of operations.

Summary of Critical Accounting Policies and Estimates

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives but involve an implementation and interpretation of existing rules, and the use of judgment, to apply the accounting rules to the specific set of circumstances existing in our business. In preparing our consolidated financial statements in conformity with generally accepted accounting principles in the United States ("GAAP"), we endeavor to comply with all applicable rules on or before their adoption, and we believe that the proper implementation and consistent application of the accounting rules are critical. However, not all situations are specifically addressed in the accounting literature. In these cases, we must use our best judgment to adopt a policy for accounting for these situations. We accomplish this by analogizing to similar situations and the accounting guidance governing them. There have been no significant changes to our critical accounting policies and estimates from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2012, as amended by Amendment No. 1 on Form 10-K/A.

Recent Accounting Standards

In February 2013, the Financial Accounting Standards Board ("FASB") issued guidance that requires entities to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, entities are required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount is required under GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under GAAP to be reclassified in their entirety to net income, entities are required to cross-reference to other disclosures required under GAAP that provide additional detail on these amounts. This standard is effective prospectively for reporting periods beginning after December 15, 2012. We adopted this standard effective January 1, 2013. The adoption of this guidance did not have an impact on our consolidated financial position, results of operations or cash flows, as it only expanded disclosures.

In December 2011 and February 2013, the FASB issued guidance that requires entities to disclose both gross and net information about both derivatives and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting agreement. The objective of the disclosure is to facilitate comparison between those entities that prepare their financial statements on the basis of GAAP and those entities that prepare their financial statements on the basis of International Financial Reporting Standards. Retrospective presentation for all comparative periods presented is required. We adopted this guidance effective January 1, 2013. The adoption of this guidance did not have an impact on our consolidated financial position, results of operations or cash flows, as it only expanded disclosures.

There are currently no new accounting standards that have been issued that will have a significant impact on our consolidated financial position, results of operations or cash flows upon adoption.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Cash Investments

We have cash investments that we manage based on internal investment guidelines that emphasize liquidity and preservation of capital. Such cash investments are stated at historical cost, which approximates fair market value on our Consolidated Balance Sheets.

Marketing and Trading Commodity Price Risk

We have entered into certain instruments to hedge the exposure to variability in expected future cash flows attributable to the future sale of our LNG inventory ("LNG Inventory Derivatives") and to hedge the exposure to price risk attributable to future purchases of natural gas to be utilized as fuel to operate the Sabine Pass LNG terminal ("Fuel Derivatives"). We use one-day value at risk ("VaR") with a 95% confidence interval and other methodologies for market risk measurement and control purposes of our LNG Inventory Derivatives and Fuel Derivatives. The VaR is calculated using the Monte Carlo simulation method. The table below provides information about our LNG Inventory Derivatives and Fuel Derivatives that are sensitive to changes in natural gas prices and interest rates as of September 30, 2013.



Hedge Description	Hedge Instrument	Contract Volume (MMBtu)	Price Range ($/MMBtu)	Final Hedge Maturity Date	Fair Value (in thousands)			VaR (in thousands)
LNG Inventory Derivatives	Fixed price natural gas swaps	1,705,306	$3.553 - $4.319	January 2014	$	219		$	14
Fuel Derivatives	Fixed price natural gas swaps	636,000	$3.56 - $3.837	May 2014	(227		)	5

We have entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the 2013 Liquefaction Credit Facilities ("Interest Rate Derivatives"). In order to test the sensitivity of the fair value of the Interest Rate Derivatives to changes in interest rates, management modeled a 10% change in the forward 1-month LIBOR curve across the full 7-year term of the Interest Rate Derivatives. This 10% change in interest rates resulted in a change in the fair value of the Interest Rate Derivatives of $30.7 million. The table below provides information about our Interest Rate Derivatives that are sensitive to changes in the forward 1-month LIBOR curve as of September 30, 2013.

Hedge Description

Initial Notional Amount (in thousands)

Maximum Notional Amount (in thousands)

Fixed Interest Rate Range (%)

Final Hedge Maturity Date

Fair Value (in thousands)

10% Change in LIBOR (in thousands)

Interest Rate Derivatives - Not Designated

$20.0 million

$3.6 billion

1.99%

May 2020

56,039

30,659

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 Securities and Exchange Commission'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.

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. In the opinion of management, as of September 30, 2013, there were no pending legal matters that could reasonably be expected to have a material adverse impact on our consolidated results of operations, financial position or cash flows.

ITEM 5. OTHER INFORMATION

Compliance Disclosure

Pursuant to Section 13(r) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), if during the quarter ended September 30, 2013, we or any of our affiliates had engaged in certain transactions with Iran or with persons or entities designated under certain executive orders, we would be required to disclose information regarding such transactions in our Quarterly Report on Form 10-Q as required under Section 219 of the Iran Threat Reduction and Syria Human Rights Act of 2012 ("ITRA"). During the quarter ended September 30, 2013, we did not engage in any transactions with Iran or with persons or entities related to Iran.

Blackstone CQP HoldCo LP, an affiliate of The Blackstone Group L.P. ("Blackstone"), is a holder of approximately 30% of our outstanding equity interests and has three representatives on our Board of Directors. Accordingly, Blackstone may be deemed an "affiliate" of us, as that term is defined in Exchange Act Rule 12b-2. We have received notice from Blackstone that it may include in its Quarterly Report on Form 10-Q for the quarter ended September 30, 2013 disclosures pursuant to ITRA regarding one of its portfolio companies that may be deemed to be an affiliate of Blackstone. Because of the broad definition of "affiliate" in Exchange Act Rule 12b-2, this portfolio company of Blackstone, through Blackstone's ownership of us, may also be deemed to be an affiliate of ours.

Blackstone has reported that Travelport Limited ("Travelport") has engaged in the following activities: as part of its global business in the travel industry, Travelport provides certain passenger travel-related GDS and Airline IT Solutions services to Iran Air and Airline IT Solutions services to Iran Air Tours. The gross revenues and net profits attributable to such activities during the reporting period were reported by Travelport to be approximately $164,000 and $122,000, respectively. Blackstone has reported that Travelport intends to continue these business activities with Iran Air and Iran Air Tours as such activities are either exempt from applicable sanctions prohibitions or specifically licensed by OFAC.

ITEM 6. EXHIBITS



Exhibit No.		Description
10.1*		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00026 Bundle of Changes, dated June 28, 2013, (ii) the Change Order CO-00027 16" Water Pumps, dated July 12, 2013, (iii) the Change Order CO-00028 HRU Operability, dated July 26, 2013, (iv) the Change Order CO-00029 Belleville Washers, dated August 14, 2013 and (v) the Change Order CO-0030 Soils Preparation Provisional Sum Transfer dated August 29, 2013. (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.)

10.2		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 2 Liquefaction Facility, dated as of December 20, 2012, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-0005 Credit to EPC Contract Value for TSA Work, dated June 24, 2013, (ii) the Change Order CO-0006 HRU Operability with Lean Gas & Controls Upgrade and Ultrasonic Meter Configuration and Calibration, (iii) the Change Order CO-0007 Additional Belleville Washers, dated August 15, 2013, (iv) the Change Order CO-0008 GTG Switchgear Arrangement/Upgrade Fuel Gas Heater System, dated August 26, 2013, (iv) the Change Order CO-0009 Soils Preparation Provisional Sum Transfer and Closure, dated August 26, 2013. (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.49 to Cheniere Energy Partners LP Holdings, LLC's Registration Statement on Form S-1 (SEC File No. 333-191298), filed on October 18, 2013)

31.1*		Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act

31.2*		Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act

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

32.2**		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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



*	Filed herewith.

**	Furnished herewith.

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

By:	/s/ JERRY D. SMITH
	Jerry D. Smith
	Chief Accounting Officer
	(on behalf of the registrant and as principal accounting officer)
Date:	November 8, 2013