CQP 2012 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, 2012


£	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 24, 2012, the issuer had 39,488,488 common units, 100,000,002 Class B units and 135,383,831 subordinated units outstanding.

CHENIERE ENERGY PARTNERS, L.P.

INDEX TO FORM 10-Q



Part I. Financial Information

Item 1.	Consolidated Financial Statements	1
	Consolidated Balance Sheets	1
	Consolidated Statements of Operations	2
	Consolidated Statements of Partners' and Owners' Capital (Deficit)	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	20

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	30

Item 4.	Controls and Procedures	31

Part II. Other Information

Item 1.	Legal Proceedings	32

Item 1A.	Risk Factors	32

Item 6.	Exhibits	33

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,
	2012			2011
ASSETS	(unaudited)
Current assets
Cash and cash equivalents	$	369,100		$	81,415
Restricted cash and cash equivalents	123,297			13,732
Accounts and interest receivable	25,144			525
Accounts receivable—affiliate	1,291			328
Advances to affiliate	3,700			692
LNG inventory	5,701			473
LNG inventory—affiliate	756			4,369
Prepaid expenses and other	7,378			7,976
Total current assets	536,367			109,510

Non-current restricted cash and cash equivalents	267,201			82,394
Property, plant and equipment, net	2,414,003			1,514,416
Debt issuance costs, net	222,144			17,622
Other	31,140			13,358
Total assets	$	3,470,855		$	1,737,300

LIABILITIES AND PARTNERS' CAPITAL (DEFICIT)
Current liabilities
Accrued liabilities	$	116,061		$	16,751
Accrued liabilities—affiliate	33,671			3,794
Deferred revenue	26,525			26,629
Deferred revenue—affiliate	688			688
Other	586			3,956
Total current liabilities	177,531			51,818

Long-term debt, net of discount	2,295,939			2,192,418
Deferred revenue	22,500			25,500
Deferred revenue—affiliate	14,720			12,266
Long-term derivative liability	29,384
Other non-current liabilities	306			317

Commitments and contingencies

Partners' capital (deficit)
Common unitholders (39,488,488 units and 31,003,154 units issued and outstanding at September 30, 2012 and December 31, 2011, respectively)	366,622			(52,774		)
Class B unitholders (100,000,002 units and zero units issued and outstanding as of September 30, 2012 and December 31, 2011, respectively)	(43,013		)	—
Subordinated unitholders (135,383,831 units issued and outstanding at September 30, 2012 and December 31, 2011)	615,344			(479,197		)
General partner interest (2% interest with 5,609,639 units and 3,395,653 units issued and outstanding at September 30, 2012 and December 31, 2011, respectively)	21,198			(13,048		)
Accumulated other comprehensive loss	(29,676		)	—
Total partners' capital (deficit)	930,475			(545,019		)
Total liabilities and partners' capital (deficit)	$	3,470,855		$	1,737,300

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,
	2012			2011			2012			2011
Revenues
Revenues	$	62,429		$	63,669		$	190,154		$	200,514
Revenues—affiliate	3,879			1,238			6,872			12,452
Total revenues	66,308			64,907			197,026			212,966

Expenses
Operating and maintenance expense	6,586			6,288			19,843			15,878
Operating and maintenance expense—affiliate	6,476			2,612			12,414			8,723
Depreciation expense	10,652			10,766			31,897			32,245
Development expense	4,229			8,971			35,369			26,751
Development expense—affiliate	102			923			2,365			2,746
General and administrative expense	4,248			867			7,668			4,068
General and administrative expense—affiliate	33,243			4,957			43,532			14,973
Total expenses	65,536			35,384			153,088			105,384
Income from operations	772			29,523			43,938			107,582

Other income (expense)
Interest expense, net	(43,626		)	(43,319		)	(130,554		)	(130,115		)
Derivative gain (loss)	287			(716		)	(288		)	(1,164		)
Other	145			33			289			140
Total other expense	(43,194		)	(44,002		)	(130,553		)	(131,139		)
Net loss	$	(42,422	)	$	(14,479	)	$	(86,615	)	$	(23,557	)

Basic and diluted net income per common unit	$	0.04		$	0.29		$	0.36		$	0.93

Weighted average number of common units outstanding used for basic and diluted net income per common unit calculation	31,997			27,408			31,449			26,867

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,
	2012			2011			2012			2011
Net loss	$	(42,422	)	$	(14,479	)	$	(86,615	)	$	(23,557	)
Other comprehensive loss
Change in fair value of interest rate cash flow hedges	(29,676		)	—			(29,676		)	—
Total other comprehensive loss	(29,676		)	—			(29,676		)	—
Comprehensive loss	$	(72,098	)	$	(14,479	)	$	(116,291	)	$	(23,557	)

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' CAPITAL (DEFICIT)

(in thousands)

(unaudited)



	Common Unitholders			Class B Unitholders			Subordinated Unitholders			General Partner Interest			Accumulated Other Comprehensive Loss			Total Partners' Capital (Deficit)
Balance at December 31, 2011	$	(52,774	)	$	—		$	(479,197	)	$	(13,048	)	$	—		$	(545,019	)
Net loss	(15,398		)	—			(66,131		)	(5,086		)	—			(86,615		)
Sale of common and general partner units	204,973			—			—			34,940			—			239,913
Distributions	(39,882		)	—			—			(814		)	—			(40,696		)
Non-cash contributions	—			—			—			5,206			—			5,206
Interest rate cash flow hedges	—			—			—			—			(29,676		)	(29,676		)
Sale of Class B units	—			1,387,362			—			—			—			1,387,362
Beneficial conversion feature of Class B units	273,566			(1,450,000		)	1,176,434			—			—			—
Amortization of beneficial conversion feature of Class B units	(3,863		)	19,625			(15,762		)	—			—			—
Balance at September 30, 2012	$	366,622		$	(43,013	)	$	615,344		$	21,198		$	(29,676	)	$	930,475

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,
	2012			2011
Cash flows from operating activities
Net loss	$	(86,615	)	$	(23,557	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation	31,897			32,245
Non-cash derivative loss	300			301
Amortization of debt issuance costs	8,373			3,278
Amortization of debt discount	3,521			3,520
Investment in restricted cash and cash equivalents for future interest payments	(41,197		)	(41,197		)
Use of restricted cash and cash equivalents	36,676			—
Other	3,209			—
Changes in operating assets and liabilities:
Accounts and interest receivable	(24,619		)	(85		)
Accounts receivable—affiliate	(963		)	(185		)
Accounts payable and accrued liabilities	40,888			40,416
Accounts payable and accrued liabilities—affiliate	29,162			3,762
Advances to affiliate	(3,627		)	3,135
Deferred revenue	(3,104		)	(3,135		)
LNG inventory	(282		)	—
LNG inventory—affiliate	3,613			(3,230		)
Other	(3,686		)	(2,634		)
Net cash provided by (used in) operating activities	(6,454		)	12,634

Cash flows from investing activities
LNG terminal construction-in-process, net	(876,531		)	(6,419		)
Use of restricted cash and cash equivalents	887,902			—
Advances under long-term contracts and other	(16,331		)	(722		)
Net cash used in investing activities	(4,960		)	(7,141		)

Cash flows from financing activities
Proceeds from sale of Class B units, net	1,387,560			—
Proceeds from Liquefaction Credit Facility	100,000			—
Investment in restricted cash and cash equivalents	(1,177,753		)	—
Distributions to unitholders	(40,696		)	(34,704		)
Proceeds from sale of partnership units	240,114			70,360
Debt issuance costs	(210,126		)	—
Net cash provided by financing activities	299,099			35,656

Net increase in cash and cash equivalents	287,685			41,149
Cash and cash equivalents—beginning of period	81,415			53,349
Cash and cash equivalents—end of period	$	369,100		$	94,498

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—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. As used in these Notes to Consolidated Financial Statements, the terms "Cheniere Partners", "we", "us" and "our" refer to Cheniere Energy Partners, L.P. and its wholly owned subsidiaries, unless otherwise stated or indicated by context.

Results of operations for the three and nine months ended September 30, 2012 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2012.

We are not subject to either federal or state income tax, as the partners are taxed individually on their allocable share of 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, 2011.

NOTE 2—Restricted Cash and Cash Equivalents

Restricted cash and cash equivalents consist of cash and cash equivalents that are contractually restricted as to usage or withdrawal, as follows:

Senior Notes Debt Service Reserve

Sabine Pass LNG, L.P. ("Sabine Pass LNG") has consummated private offerings of an aggregate principal amount of $2,215.5 million of Senior Notes (see Note 5—"Long-Term Debt"). Under the indenture governing the Senior Notes (the "Sabine Pass Indenture"), 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 of $82.4 million. 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 Indenture. As of September 30, 2012 and December 31, 2011, we classified the permanent debt service reserve fund of $82.4 million as non-current restricted cash and cash equivalents. As of September 30, 2012 and December 31, 2011, we classified $54.9 million and $13.7 million, respectively, as current restricted cash and cash equivalents for the payment of interest due within twelve months. These cash accounts are controlled by a collateral trustee, and, therefore, are shown as restricted cash and cash equivalents on our Consolidated Balance Sheets.

Liquefaction Reserve

In July 2012, Sabine Pass Liquefaction, LLC ("Sabine Pass Liquefaction") closed on a $3.6 billion senior secured credit facility (the "Liquefaction Credit Facility"). Under the terms and conditions of the Liquefaction Credit Facility, Sabine Pass Liquefaction is required to deposit all cash received into reserve 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, 2012, we classified $184.8 million as non-current restricted cash and cash equivalents held by Sabine Pass Liquefaction as such funds are to be used to acquire non-current assets. As of September 30, 2012, we classified $68.4 million as current restricted cash and cash equivalents held by Sabine Pass Liquefaction as such funds are to be used to pay for current liabilities.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

NOTE 3—Property, Plant and Equipment

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



	September 30,			December 31,
	2012			2011
LNG terminal costs
LNG terminal	$	1,641,581		$	1,637,724
LNG terminal construction-in-process	927,665			286
LNG site and related costs, net	158			163
Accumulated depreciation	(155,989		)	(124,409		)
Total LNG terminal costs, net	2,413,415			1,513,764

Fixed assets
Computers and office equipment	336			227
Vehicles	496			416
Machinery and equipment	1,416			1,068
Other	631			916
Accumulated depreciation	(2,291		)	(1,975		)
Total fixed assets, net	588			652
Property, plant and equipment, net	$	2,414,003		$	1,514,416

Depreciation expense related to the Sabine Pass LNG terminal totaled $10.6 million and $10.7 million for the three months ended September 30, 2012 and 2011, respectively. Depreciation expense related to the Sabine Pass LNG terminal totaled $31.6 million and $32.0 million for the nine months ended September 30, 2012 and 2011, respectively.

In June 2012, LNG trains 1 and 2 of the liquefaction facilities we are developing and constructing adjacent to the Sabine Pass LNG terminal (the "Liquefaction Project") satisfied the criteria for capitalization. Accordingly, costs associated with the construction of LNG trains 1 and 2 of the Liquefaction Project have been recorded as construction-in-process since that date. For the three and nine months ended September 30, 2012, we capitalized $14.0 million of interest expense related to the construction of LNG trains 1 and 2 of the Liquefaction Project.

NOTE 4—Accrued Liabilities

As of September 30, 2012 and December 31, 2011, accrued liabilities consisted of the following (in thousands):



	September 30,		December 31,
	2012		2011
Interest expense and related debt fees	$	55,241	$	13,732
Affiliate	33,671		3,794
LNG terminal costs	869		1,122
LNG liquefaction costs	52,873		1,635
Other	7,078		262
Total accrued liabilities	$	149,732	$	20,545

NOTE 5—Long-Term Debt

As of September 30, 2012 and December 31, 2011, our long-term debt consisted of the following (in thousands):



	September 30,		December 31,
	2012		2011
Senior Notes, net of discount	$	2,195,939	$	2,192,418
Liquefaction Credit Facility	100,000		—
Total long-term debt	$	2,295,939	$	2,192,418

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

Senior Notes

In November 2006, Sabine Pass LNG issued an aggregate principal amount of $2,032.0 million of Senior Notes (the "Senior Notes"), consisting of $550.0 million of 7¼% Senior Secured Notes due 2013 (the "2013 Notes") and $1,482.0 million of 7½% Senior Secured Notes due 2016 (the "2016 Notes"). In September 2008, Sabine Pass LNG issued an additional $183.5 million, before discount, of 2016 Notes whose terms were identical to the previously outstanding 2016 Notes. Interest on the Senior Notes is payable semi-annually in arrears on May 30 and November 30 of each year. The 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 the Senior Notes at any time, and from time to time, at a redemption price equal to 100% of the principal plus any accrued and unpaid interest plus the greater of:

•1% of the principal amount of the Senior Notes; or

•

the excess of: a) the present value at such redemption date of (i) the redemption price of the Senior Notes plus (ii) all required interest payments due on the Senior Notes (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50 basis points; over b) the principal amount of the Senior Notes, if greater.

Under the Sabine Pass Indenture, 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 of approximately $82.4 million. 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 Indenture. During the nine months ended September 30, 2012 and 2011, Sabine Pass LNG made distributions to us of $182.9 million and $231.7 million, respectively, after satisfying all the applicable conditions in the Sabine Pass Indenture.

See Note 11—"Subsequent Events" for a description of the repurchase in October 2012 of the 2013 Notes and Sabine Pass LNG's issuance of new notes.

Liquefaction Credit Facility

In July 2012, Sabine Pass Liquefaction entered into the $3.6 billion Liquefaction Credit Facility with a syndicate of lenders. The Liquefaction Credit Facility will be used to fund a portion of the costs of developing, constructing and placing into operation LNG trains 1 and 2 of the Liquefaction Project. The Liquefaction Credit Facility will mature on the earlier of July 31, 2019 or the second anniversary of the completion date of LNG trains 1 and 2 of the Liquefaction Project. Borrowings under the Liquefaction Credit Facility may be refinanced, in whole or in part, at any time without premium or penalty, except for interest hedging and interest rate breakage costs. Sabine Pass Liquefaction made a $100.0 million borrowing under the Liquefaction Credit Facility in August 2012 after meeting the required conditions precedent to the initial advance. The second advance will not be made until Sabine Pass Liquefaction has received an aggregate of at least $1.9 billion of equity or subordinated debt proceeds, and has expended at least $1.8 billion of such funds in payment of costs for LNG trains 1 and 2 of the Liquefaction Project. In addition, the second advance will not be made until Cheniere Creole Trail Pipeline, L.P. has received equity or debt commitments sufficient to fund the pipeline modifications necessary to provide sufficient gas supply for the Liquefaction Project.

Borrowings under the Liquefaction Credit Facility bear interest, at Sabine Pass Liquefaction's election, at a variable rate equal to LIBOR or the base rate, plus the applicable margin. The applicable margin for LIBOR loans is 3.50% during construction and 3.75% during operations, and the applicable margin for base rate loans is 2.50% during construction and 2.75% during operations. Interest on LIBOR loans is due and payable at the end of each LIBOR period, and interest on base rate loans is due and payable at the end of each calendar quarter. The 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 provides 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 Liquefaction Credit Facility must be repaid in quarterly installments, commencing with the first calendar quarter ending at least three months following the completion of LNG trains 1 and 2 of the Liquefaction Project. Scheduled repayments are based upon an 18-year amortization, with the remaining balance due upon the maturity of the Liquefaction Credit Facility.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

Under the terms and conditions of the Liquefaction Credit Facility, all cash held by Sabine Pass Liquefaction is controlled by the collateral agent. These funds can only be released by the collateral agent upon satisfaction of certain terms and conditions, including receipt of satisfactory documentation that the Liquefaction Project costs are bona fide expenditures and are permitted under the terms of the Liquefaction Credit Facility. The Liquefaction Credit Facility does not permit Sabine Pass Liquefaction to hold any cash, or cash equivalents, outside of the accounts established under the agreement. Because these cash accounts are controlled by the collateral agent, the cash balance of $100.0 million held in these accounts as of September 30, 2012 is classified as restricted on our Consolidated Balance Sheets.

The Liquefaction Credit Facility contains customary 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 Liquefaction Credit Facility are 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 our rights under the Blackstone Unit Purchase Agreement and the guaranty related thereto.

Under the terms of the Liquefaction Credit Facility, Sabine Pass Liquefaction is required to hedge against the potential of rising interest rates with respect to no less than 75% (calculated on a weighted average basis) of the projected outstanding borrowings. In connection with the closing of the Liquefaction Credit Facility, Sabine Pass Liquefaction entered into interest rate swap agreements. The swap agreements have the effect of fixing the LIBOR component of the interest rate payable under the Liquefaction Credit Facility with respect to forecasted borrowings under the Liquefaction Credit Facility up to a maximum of $2.9 billion at 1.98% from August 14, 2012 to July 31, 2019, the final termination date of the swap agreements.

NOTE 6—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. On May 31, 2007, Cheniere LNG Holdings, LLC contributed all of its 135,383,831 subordinated units to Cheniere Subsidiary Holdings, LLC ("Cheniere Subsidiary Holdings").

The common units have the right to receive minimum 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.

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 minimum distributions have been achieved and as additional target levels are met. The higher percentages range from 15% up to 50%.

In January 2011, we initiated an at-the-market program to sell up to 1.0 million common units the proceeds from which are used primarily to fund development costs associated with the Liquefaction Project. During the year ended December 31, 2011, we sold 0.5 million common units with net proceeds of $9.0 million. During the nine months ended September 30, 2012, we sold 0.5 million common units in connection with the at-the-market program with net proceeds of $11.1 million. We paid $0.3 million in commissions to Miller Tabak + Co., Inc., as sales agent, in connection with the at-the-market program during the nine months ended September 30, 2012.

In September 2011, we sold 3.0 million common units in an underwritten public offering and 1.1 million common units to Cheniere Common Units Holding, LLC ("Cheniere Common Units Holding") at a price of $15.25 per common unit. We received net proceeds of approximately $60 million that we are using for general business purposes, including development costs associated with the Liquefaction Project. In September 2012, we sold 8.0 million common units in an underwritten public offering at a price of $25.07 per common unit. We received net proceeds of $194.0 million that we intend to use for partial repayment of Sabine Pass LNG's 2013 Notes, and, to the extent not so used, for general business purposes.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

During the year ended December 31, 2011, we also received $1.5 million in net proceeds from our general partner in connection with the exercise of its right to maintain its 2% ownership interest in us. We received $34.9 million in net proceeds from our general partner in connection with the exercise of its right to maintain its 2% ownership interest in us during the nine months ended September 30, 2012.

In May 2012, we and Blackstone CQP Holdco LP ("Blackstone") entered into a unit purchase agreement (the "Blackstone Unit Purchase Agreement") . Under the Blackstone Purchase Unit Agreement, Blackstone agreed to purchase $1.5 billion of newly issued Cheniere Partners Class B units ("Class B Units") from us in a private placement. In May 2012, Cheniere also entered into a unit purchase agreement with us (the "Cheniere Unit Purchase Agreeement"). Under the Cheniere Unit Purchase Agreement, Cheniere agreed to purchase $500 million of newly issued Class B Units. Subsequent to an initial funding of $500 million by Blackstone, we can require, based on liquidity needs, that Blackstone make additional capital contributions until Blackstone has funded $1.5 billion in the aggregate. Proceeds from the financings will be used to fund the equity portion of the costs of developing, constructing and placing into service the Liquefaction Project.

The Class B Units are subject to conversion, mandatorily or at the option of the holders of the Class B Units, 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 funding and ending on the conversion date of the Class B Units, the conversion value of the Class B Units will increase 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 will not be entitled to cash distributions except in the event of a liquidation. The holders of Class B Units will have a preference over the holders of the common and subordinated units in the event of a liquidation. The Class B Units will mandatorily convert into common units upon the earlier of the substantial completion date of LNG train 3 or the fifth anniversary of the latest initial funding by the holders of the Class B Units, provided that if the LNG train 3 notice to proceed with construction is issued prior to the fifth anniversary of such initial funding, then the mandatory conversion date becomes the date of substantial completion of LNG train 3. During the nine months ended September 30, 2012, we issued and sold 100 million Class B Units at a price of $15.00 per Class B Unit, resulting in total gross proceeds of $1.5 billion.

NOTE 7—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, 2012 and December 31, 2011, which are classified as other current assets, other current liabilities and other non-current liabilities in our Consolidated Balance Sheets.



	Fair Value Measurements as of
	September 30, 2012										December 31, 2011
	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 (liability)	$	—	$	(165	)	$	—	$	(165	)	$	—	$	1,610		$	—	$	1,610
Fuel Derivatives asset (liability)	—		60			—		60			—		(1,415		)	—		(1,415		)
Interest Rate Derivatives liability	—		(29,676		)	—		(29,676		)	—		—			—		—

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

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 that are calibrated to 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.

Commodity Cash Flow Hedges

Changes in the fair value of our LNG Inventory Derivatives and Fuel Derivatives are reported in earnings because we have not elected to designate these derivative instruments as a hedging instrument that is required to qualify for cash flow hedge accounting. The following table (in thousands) shows the fair value and location of our LNG Inventory and Fuel Derivatives on our Consolidated Balance Sheets:



		Fair Value Measurements as of
	Balance Sheet Location	September 30, 2012			December 31, 2011
LNG Inventory Derivatives asset (liability)	Prepaid expenses and other (other current liabilities)	$	(165	)	$	1,610
Fuel Derivatives asset (liability)	Prepaid expenses and other (other current liabilities)	60			(1,415		)

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, 2012 and 2011:



	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2012			2011		2012		2011
LNG Inventory Derivatives	$	(228	)	$	494	$	697	$	494

The following table (in thousands) shows the changes in the fair value and settlements of our Fuel Derivatives recorded in derivative gain (loss) on our Consolidated Statements of Operations during the three and nine months ended September 30, 2012 and 2011:



	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2012		2011			2012			2011
Fuel Derivatives	$	287	$	(716	)	$	(288	)	$	(1,164	)

Interest Rate Swaps Designated as Cash Flow Hedges

Sabine Pass Liquefaction has elected to designate these Interest Rate Derivatives as hedging instruments which is required in order to qualify for cash flow hedge accounting. As a result of this cash flow hedge designation, we recognize the Interest Rate Derivatives as an asset or liability at fair value, and reflect changes in fair value through other comprehensive income in our Consolidated Statements of Comprehensive Loss. Any hedge ineffectiveness associated with the Interest Rate Derivatives is recorded immediately as derivative gain (loss) in our Consolidated Statements of Operations. The realized gain (loss) on the Interest Rate Derivatives is 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 recorded in other comprehensive income is reclassified to earnings over the life of the Liquefaction Credit Facility as the fixed rate interest obligations affect 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)

The Interest Rate Derivatives hedge approximately 75% of the weighted average of the expected outstanding borrowings over the term of the Liquefaction Credit Facility. The aggregate notional amount each month follows our expected borrowing schedule under the Liquefaction Credit Facility with an expected maximum swap notional amount outstanding of $2.9 billion in 2017. At September 30, 2012, Sabine Pass Liquefaction had the following Interest Rate Derivatives outstanding that converted $20.0 million of the Liquefaction Credit Facility from a variable to a fixed interest rate. Sabine Pass Liquefaction pays a fixed interest rate on the swap and in exchange receives a variable interest rate based on the one-month LIBOR.



Initial Notional Amount	Maximum Notional Amount	Effective Date	Maturity Date	Weighted Average Fixed Interest Rate Paid	Variable Interest Rate Received
$20.0 million	$2.9 billion	August 14, 2012	July 31, 2019	1.98%	One-month LIBOR

Interest Rate Derivatives were reflected in our Consolidated Balance Sheets at fair value with the effective portion of the Interest Rate Derivatives' gain or loss recorded in other comprehensive income. The following table (in thousands) shows the fair value of our interest rate swaps:



		Fair Value Measurements as of
	Balance Sheet Location	September 30, 2012				December 31, 2011
Interest Rate Derivatives	Other current liabilities		$	(292	)	$	—
Interest Rate Derivatives	Other non-current liabilities		(29,384		)	—

The following table (in thousands) shows our Interest Rate Derivatives market adjustments recorded during the three and nine months ended September 30, 2012:



	Gain (Loss) in Other Comprehensive Income					Gain (Loss) Reclassified from Accumulated OCI into Interest Expense (Effective Portion)				Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
	2012			2011		2012		2011		2012		2011
Interest Rate Derivatives	$	(29,676	)	$	—	$	—	$	—	$	—	$	—

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, 2012				December 31, 2011
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
2013 Notes (1)	$	550,000	$	585,750	$	550,000	$	555,500
2016 Notes, net of discount (1)	1,645,939		1,773,499		1,642,418		1,650,630
Liquefaction Credit Facility (2)	100,000		100,000		—		—


(1)	The Level 2 estimated fair value of the Senior Notes, net of discount, 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, 2012 and December 31, 2011, as applicable.


(2)	The Level 2 estimated fair value of the Liquefaction Credit Facility was determined to be the carrying amount due to our ability to call this debt at anytime without penalty.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

NOTE 8—Related Party Transactions

As of September 30, 2012 and December 31, 2011, we had $3.7 million and $0.7 million of advances to affiliates, respectively. In addition, we have entered into the following related party transactions:

LNG Terminal Capacity Agreements

Terminal Use Agreement

In November 2006, Cheniere Marketing, LLC, a wholly owned subsidiary of Cheniere ("Cheniere Marketing"), reserved approximately 2.0 Bcf/d of regasification capacity under a firm commitment terminal use agreement ("TUA") with Sabine Pass LNG and was required to make capacity reservation fee payments aggregating approximately $250 million per year for the period from January 1, 2009, through at least September 30, 2028. Cheniere guaranteed Cheniere Marketing's obligations under its TUA.

Effective July 1, 2010, Cheniere Marketing assigned its existing TUA with Sabine Pass LNG to Cheniere Energy Investments, LLC ("Cheniere Investments"), our wholly owned subsidiary, including all of its rights, titles, interests, obligations and liabilities in and under the TUA. In connection with the assignment, Cheniere's guarantee of Cheniere Marketing's obligations under the TUA was terminated. Cheniere Investments was required to make capacity payments under the TUA aggregating approximately $250 million per year through at least September 30, 2028; however, the revenue earned from Cheniere Investments' capacity payments is eliminated upon consolidation of our financial statements. We guaranteed Cheniere Investments' obligations under its TUA.

Sabine Pass Liquefaction has also entered into a TUA with Sabine Pass LNG pursuant to which Sabine Pass Liquefaction has reserved approximately 2.0 Bcf/d of regasification capacity and is obligated to make monthly capacity payments to Sabine Pass LNG aggregating approximately $250 million per year, continuing until at least 20 years after one of Sabine Pass Liquefaction's customers delivers its first commercial cargo at Sabine Pass Liquefaction's facilities under construction, which may occur as early as late 2015. Sabine Pass Liquefaction obtained this reserved capacity as a result of an assignment in July 2012 by Cheniere Energy Investments, LLC ("Cheniere Investments") of its rights, title and interest under its TUA. In connection with the assignment, Sabine Pass Liquefaction, Cheniere Investments 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. The revenue earned by Sabine Pass LNG from the capacity payments made under the TUA is 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 Gas and Power North America, Inc. ("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. These agreements 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 a fifth LNG train, provide increased flexibility in managing LNG cargo loading and unloading activity starting with the commencement of commercial operations of the third LNG train, and permit Sabine Pass Liquefaction to more flexibly manage its storage with the commencement of the first LNG train. Notwithstanding any arrangements between Total and Sabine Pass Liquefaction, payments required to be made by Total under the TUA shall continue to be made by Total in accordance with the Sabine Pass LNG TUA.

In connection with the TUA assignment to Sabine Pass Liquefaction, Cheniere Investments entered into an amended and restated variable capacity rights agreement ("VCRA") with Cheniere Marketing in order for Cheniere Investments to monetize the capacity rights granted under the TURA. Under the terms of the VCRA, Cheniere Marketing is responsible for monetizing the capacity at the Sabine Pass LNG terminal held by Cheniere Investments under the TURA and has the right to utilize all of the services and other rights at the Sabine Pass LNG terminal available under the TURA. In consideration of these rights, Cheniere Marketing is obligated to pay Cheniere Investments 80% of the expected gross margin of each cargo of LNG delivered to the Sabine Pass LNG terminal. To the extent payments from Cheniere Marketing to Cheniere Investments under the VCRA increase our available cash in excess of the common unit and general partner distributions and certain reserves, the cash would be distributed to Cheniere in the form of distributions on its subordinated units. During the term of the VCRA, Cheniere Marketing is responsible for the payment of taxes and new regulatory costs paid by Cheniere Investments under the TUA. We recorded $3.2 million and

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

$0.7 million of revenues—affiliate from Cheniere Marketing in the three months ended September 30, 2012 and 2011, respectively, related to the VCRA. We recorded $4.9 million and $9.8 million of revenues—affiliate from Cheniere Marketing in the nine months ended September 30, 2012 and 2011, respectively, related to the VCRA.

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 will enable 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 its LNG inventory. Under the terms of the LNG Lease Agreement, Cheniere Marketing will fund all activities related to the purchase and hedging of the LNG, and Cheniere Investments will reimburse Cheniere Marketing for all costs and assume 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, 2012, we had 266,630 MMBtu of LNG inventory—affiliate recorded at $0.8 million on our Consolidated Balance Sheets, and as of December 31, 2011, we had 1,527,000 MMBtu of LNG inventory—affiliate recorded at $4.4 million on our Consolidated Balance Sheets. During the three months ended September 30, 2012 and 2011, we recognized a gain of $0.1 million and a loss of $5.2 million, respectively, as a result of LCM adjustments to our LNG inventory—affiliate. During the nine months ended September 30, 2012 and 2011, we recognized a loss of $0.5 million and $4.8 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, 2012 and December 31, 2011 was $0.2 million and $1.6 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 losses of $0.2 million and revenues of $0.7 million related to LNG inventory—affiliate derivatives in the three and nine months ended September 30, 2012, respectively.

Service Agreements

During the three months ended September 30, 2012 and 2011, we recorded general and administrative expense—affiliate of $20.6 million and $4.8 million, respectively, under the following service agreements. During the nine months ended September 30, 2012 and 2011, we recorded general and administrative expense—affiliate of $30.3 million and $14.2 million, respectively, under the following service agreements.

Cheniere Partners Services Agreement

We have entered into a services agreement with Cheniere LNG Terminals, Inc. ("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 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, LLC ("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 LNG 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 LNG 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 LNG train, Sabine Pass Liquefaction will pay a fixed monthly fee of $541,667 for services with respect to such LNG train.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

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 existing TUA to Cheniere Investments and concurrently entered into a VCRA, allowing Cheniere Marketing to monetize 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 monetize the capacity rights granted under the TURA. The amended and restated VCRA provides that Cheniere Marketing will continue to fund the CEAs during the term of the amended and restated VCRA and, in exchange, Cheniere Marketing will receive any future credits.

On a consolidated basis, these TUA 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, 2012 and December 31, 2011, we had $14.7 million and $12.3 million of other non-current assets and non-current deferred revenue resulting from Sabine Pass LNG's ad valorem tax payments and the advance TUA 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 an agreement with Cheniere Marketing. Under this agreement, 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 and $1.1 million of natural gas and LNG purchased from Cheniere Marketing under this agreement in the three months ended September 30, 2012 and 2011, respectively. Sabine Pass LNG recorded $1.9 million and $3.2 million of natural gas and LNG purchased from Cheniere Marketing under this agreement in the nine months ended September 30, 2012 and 2011, respectively.

LNG Terminal Export Agreement

In January 2010, Sabine Pass LNG and Cheniere Marketing entered into an LNG Terminal Export Agreement that provides Cheniere Marketing the ability to export LNG from the Sabine Pass LNG terminal. Sabine Pass LNG recorded revenues—affiliate of zero pursuant to this agreement in the three months ended September 30, 2012 and 2011. Sabine Pass LNG recorded revenues—affiliate of zero and $0.3 million pursuant to this agreement in the nine months ended September 30, 2012 and 2011, respectively.

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 the three months ended September 30, 2012 and 2011. Tug Services recorded revenues—affiliate from Cheniere Marketing of $2.1 million and $2.0 million pursuant to this agreement in the nine months ended September 30, 2012 and 2011, respectively.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

NOTE 9—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, 2012 (in thousands, except per unit data):



				Total Distribution
Date Paid	Period Covered by Distribution	Distribution Per Common Unit		Common Units		Class B Units		Subordinated Units		General Partner Units
February 14, 2012	October 1, 2011 - December 31, 2011	$	0.425	$	13,176	$	—	$	—	$	269
May 15, 2012	January 1, 2012 - March 31, 2012	$	0.425	$	13,323	$	—	$	—	$	272
August 14, 2012	April 1, 2012 - June 30, 2012	$	0.425	$	13,383	$	—	$	—	$	273

The subordinated units will receive distributions only to the extent we have available cash above the minimum quarterly distribution requirement for our common unitholders and general partner and certain reserves. As a result of the assignment of Cheniere Marketing's TUA to Cheniere Investments, effective July 1, 2010, our available cash for distributions was reduced. Therefore, we have not paid distributions on our subordinated units since the distribution made with respect to the quarter ended March 31, 2010.

Pursuant to the Blackstone and Cheniere Unit Purchase Agreements, we issued and sold 100 million Class B Units at a price of $15.00 per Class B Unit in the nine months ended September 30, 2012, resulting in total gross proceeds of $1.5 billion. 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 $1,450.0 million represents a beneficial conversion feature and is reflected as an increase in common and subordinated unitholders’ capital and a decrease in Class B unitholders’ capital to reflect the fair value of the Class B Units at issuance on our consolidated statement of partners’ and owners' capital (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' capital and a decrease in common and subordinated unitholders’ capital. The impact of the beneficial conversion feature is also included in earnings per unit for the three and nine months ended September 30, 2012.

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 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.

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 common unit calculation for any of the periods presented.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

The following table provides a reconciliation of net income (loss) and the allocation of net income (loss) to the common units, the Class B 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
Three Months Ended September 30, 2012
Net loss	$	(42,422	)
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	(59,547		)	(12,467		)	—		(42,744		)	(4,336		)
Assumed allocation of net income (loss)				$	1,345		$	14,888	$	(54,661	)	$	(3,994	)

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

Three Months Ended September 30, 2011
Net loss	$	(14,479	)
Declared distributions	13,445			13,176								269
Assumed allocation of undistributed net loss	(27,924		)	(5,099		)	—		(22,267		)	(558		)
Assumed allocation of net income (loss)				$	8,077		$	—	$	(22,267	)	$	(289	)

Weighted average units outstanding				27,408			—		135,384
Net income (loss) per unit				$	0.29		$	—	$	(0.16	)

Nine Months Ended September 30, 2012
Net loss	$	(86,615	)
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	(130,991		)	(28,278		)	—		(96,948		)	(5,765		)
Assumed allocation of net income (loss)				$	11,347		$	19,625	$	(112,710	)	$	(4,877	)

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

Nine Months Ended September 30, 2011
Net loss	$	(23,557	)
Declared distributions	36,691			35,957								734
Assumed allocation of undistributed net loss	(60,248		)	(11,002		)	—		(48,041		)	(1,205		)
Assumed allocation of net income (loss)				$	24,955		$	—	$	(48,041	)	$	(471	)

Weighted average units outstanding				26,867			—		135,384
Net income (loss) per unit				$	0.93		$	—	$	(0.35	)

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,
	2012		2011
Cash paid during the period for interest, net of amounts capitalized	$	77,140	$	82,512
Construction-in-process funded with accrued liabilities	$	52,830	$	—

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

NOTE 11—Subsequent Events

Class B Units

In October 2012, Blackstone purchased $300.0 million of additional Class B Units, which, when added to prior Class B Units purchased by Blackstone, totals $1.3 billion invested.

2013 Notes

In October 2012, Sabine Pass LNG repurchased approximately 97% of the 2013 Notes. Funds used for the repurchase included proceeds received from newly issued $420.0 million 6.50% senior secured notes due in 2020 and from an equity contribution from us of approximately $194 million. Sabine Pass LNG has issued a redemption notice for the remaining approximately $16.5 million outstanding 2013 Notes which it expects to redeem in November 2012.


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

Information Regarding Forward-Looking Statements

This quarterly report contains certain statements that are, or may be deemed to be, "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements, other than statements of historical 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") or Sabine Pass Liquefaction, LLC ("Sabine Pass Liquefaction");


•	statements regarding future levels of domestic natural gas production, supply or consumption; future levels of liquefied natural gas ("LNG") imports into North America; sales of natural gas in North America or other markets; exports of LNG from North America; and the transportation, other infrastructure or prices related to natural gas, LNG or other energy sources;


•	statements regarding any financing or refinancing transactions or arrangements, including the amounts or timing thereof, interest rates thereon or ability to enter into such transactions or arrangements, whether on the part of Cheniere Energy Partners, L.P. or any subsidiary or at the project level;

•

statements regarding any commercial arrangements presently contracted, optioned or marketed, or potential arrangements, to be performed substantially in the future, including any cash distributions and revenues anticipated to be received and the anticipated timing thereof, and statements regarding the amounts of total LNG regasification, liquefaction or storage capacity that are, or may become, subject to such commercial arrangements;


•	statements regarding counterparties to our commercial contracts, construction contracts and other contracts;


•	statements relating to the construction and operations of our liquefaction facilities, including statements concerning the anticipated dates for commencement of construction or operations or at all, the costs related thereto and certain characteristics, including amounts of liquefaction capacity and storage capacity and the number of LNG trains;


•	statements regarding any business strategy, any business plans or any other plans, forecasts, projections or objectives, including potential revenues and capital expenditures, any or all of which are subject to change;


•	statements regarding legislative, governmental, regulatory, administrative or other public body actions, requirements, permits, investigations, proceedings or decisions; 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," "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 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, 2011. 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 Item 1. "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 Sabine Pass LNG terminal located in western Cameron Parish, Louisiana on the Sabine Pass Channel. Through our wholly owned subsidiary, Sabine Pass Liquefaction, we are constructing liquefaction facilities adjacent to the Sabine Pass LNG terminal.

Overview of Significant Events

In the first nine months of 2012, and through the filing date of this Form 10-Q, we continue to execute our strategy to operate the Sabine Pass LNG terminal, generate steady and reliable revenues under Sabine Pass LNG's long-term terminal use agreements ("TUAs") and develop and construct liquefaction facilities adjacent to the Sabine Pass LNG terminal (the "Liquefaction Project"). The major events in our business that have occurred since January 1, 2012 include the following:


•	In January 2012, Sabine Pass Liquefaction entered into an amended and restated LNG Sale and Purchase Agreement ("SPA") with BG Gulf Coast LNG, LLC ("BG"), a subsidiary of BG Group plc, under which BG agreed to purchase an additional 2.0 million tonnes per annum ("mtpa") of LNG, bringing BG's total annual contract quantity to 5.5 mtpa of LNG.


•	In January 2012, Sabine Pass Liquefaction entered into an LNG SPA with Korea Gas Corporation ("KOGAS"), under which KOGAS agreed to purchase 182.5 million MMBtu of LNG per year (approximately 3.5 mtpa).

•

In April 2012, Sabine Pass Liquefaction and Sabine Pass LNG received authorization under Section 3 of the Natural Gas Act (the "Order") from the Federal Energy Regulatory Commission ("FERC") to site, construct and operate facilities for the liquefaction and export of domestically produced natural gas at the Sabine Pass LNG terminal located in Cameron Parish, Louisiana. The Order authorizes the development of up to four modular LNG trains.

•

In May 2012, we entered into a Unit Purchase Agreement ("Agreement") with Blackstone CQP Holdco LP ("Blackstone"). Under the Agreement, Blackstone agreed to purchase $1.5 billion of newly issued Cheniere Partners Class B units ("Class B Units") from us in a private placement. Cheniere also agreed to purchase $500.0 million of Class B Units pursuant to a separate unit purchase agreement. Proceeds from the financings will be used to fund part of the equity portion of the costs of developing, constructing and placing into service the Liquefaction Project. In August 2012, Blackstone purchased $500.0 million of Class B Units from Cheniere Partners. In September and October 2012, Blackstone purchased $500.0 million and $300.0 million additional Class B Units, respectively, for an aggregate investment to date of $1.3 billion. In June and July 2012, Cheniere purchased $166.7 million and $333.3 million of Class B Units for an aggregate investment of $500 million.


•	In June 2012, we issued a limited notice to proceed to Bechtel Oil, Gas and Chemicals, Inc. ("Bechtel") to construct LNG trains 1 and 2 of the Liquefaction Project.


•	In July 2012, Sabine Pass Liquefaction closed on a $3.6 billion senior secured credit facility (the "Liquefaction Credit Facility") that will be used to fund a portion of the costs of developing, constructing and placing into service LNG trains 1 and 2 of the Liquefaction Project.


•	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 October 2012, Sabine Pass LNG repurchased approximately 97% of the outstanding $550.0 million 7.25% Senior Secured Notes due 2013 (the "2013 Notes"). Funds used for the repurchase included proceeds received from newly issued $420.0 million 6.50% senior secured notes due in 2020 (the "2020 Notes") and from an equity contribution from us. Sabine Pass LNG has issued a redemption notice for the remaining approximately $16.5 million outstanding 2013 Notes which it expects to redeem in November 2012.

Liquidity and Capital Resources

Cash and Cash Equivalents

As of September 30, 2012, we had $369.1 million of cash and cash equivalents and $390.5 million of restricted cash and cash equivalents, which is restricted as described below.

In September 2011, we sold 3.0 million common units in an underwritten public offering and 1.1 million common units to Cheniere Common Units Holding, LLC ("Cheniere Common Units Holding") at a price of $15.25 per common unit. We received net proceeds of approximately $60 million that we are using for general business purposes, including development costs associated with the Liquefaction Project. In September 2012, we sold 8.0 million common units in an underwritten public offering at a price of $25.07 per common unit. We received net proceeds of $194.0 million, a portion of which we have used for the partial repayment of the 2013 Notes, and, to the extent not so used, for general business purposes.

During the nine months ended September 30, 2012, we issued and sold 100 million Class B Units at a price of $15.00 per Class B Unit, resulting in total gross proceeds of $1.5 billion that will be used to fund the equity portion of the costs of developing, constructing and placing into service the Liquefaction Project.

Sabine Pass LNG Terminal

Regasification Facilities

Approximately 2.0 Bcf/d of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term third-party 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 and 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 per year for 20 years that commenced April 1, 2009. Total S.A. has guaranteed Total’s obligations under its TUA up to $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 per year 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.

Each of Total and Chevron previously paid Sabine Pass LNG $20.0 million in nonrefundable advance capacity reservation fees, which are being amortized over a 10-year period as a reduction of each customer's regasification capacity reservation fees payable under its respective TUA.

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. These agreements 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 a fifth LNG train, provide increased flexibility in managing LNG cargo loading and unloading activity starting with the commencement of commercial operations of the third LNG train, and permit Sabine Pass Liquefaction to more flexibly manage its storage with the commencement of the first LNG train. Notwithstanding any arrangements between Total and Sabine Pass Liquefaction, payments required to be made by Total under the TUA shall continue to be made by Total in accordance with the Sabine Pass LNG TUA.

In connection with the TUA assignment to Sabine Pass Liquefaction, Cheniere Investments entered into an amended and restated variable capacity rights agreement ("VCRA") with Cheniere Marketing, LLC, a wholly owned subsidiary of Cheniere ("Cheniere Marketing"), in order for Cheniere Investments to monetize the capacity rights granted under the TURA. Under the terms of the VCRA, Cheniere Marketing is responsible for monetizing the capacity at the Sabine Pass LNG terminal held by Cheniere Investments under the TURA and has the right to utilize all of the services and other rights at the Sabine Pass LNG terminal available under the TURA. In consideration of these rights, Cheniere Marketing is obligated to pay Cheniere Investments 80% of the expected gross margin of each cargo of LNG delivered to the Sabine Pass LNG terminal. To the extent payments from Cheniere Marketing to Cheniere Investments under the VCRA increase our available cash in excess of the common unit and general partner distributions and certain reserves, the cash would be distributed to Cheniere in the form of distributions on its subordinated units. During the term of the VCRA, Cheniere Marketing is responsible for the payment of taxes and new regulatory costs paid by Cheniere Investments under the TUA. Cheniere Marketing continues to develop its business, lacks a credit rating and may be limited by access to capital. Cheniere, which has guaranteed the obligations of Cheniere Marketing under the VCRA, has a non-investment grade corporate rating.

Under each of these TUAs, Sabine Pass LNG is entitled to retain 2% of the LNG delivered for the customer's account.

Liquefaction Facilities

In June 2010, we formed Sabine Pass Liquefaction to own, develop and operate liquefaction facilities adjacent to the Sabine Pass LNG terminal. In constructing the liquefaction facilities, we propose to take advantage of the existing marine and storage facilities that were constructed for the LNG receiving terminal, thereby saving a substantial amount of capital cost compared to the cost of constructing a greenfield facility. We anticipate that LNG exports could commence as early as 2015 with each LNG train commencing operations approximately six to nine months after the previous LNG train.

The Department of Energy ("DOE") has granted Sabine Pass Liquefaction an order authorizing the export of up to the equivalent of 16 mtpa (approximately 800 Bcf) per year of domestically produced LNG by vessel from the Sabine Pass LNG terminal to Free Trade Agreement ("FTA") countries for a 30-year term, beginning on the earlier of the date of first export or September 7, 2020, and another order authorizing the export of up to the equivalent of 803 Bcf per year (approximately 16 mtpa) of domestically produced LNG by vessel from the Sabine Pass LNG terminal to non-FTA countries for a 20-year term, beginning on the earlier of the date of first export or May 20, 2016.

In April 2012, Sabine Pass Liquefaction received authorization from the FERC to site, construct and operate liquefaction and export facilities at the Sabine Pass LNG terminal.

Sabine Pass Liquefaction has entered into four third-party SPAs, under which customers have committed to purchase, in aggregate, 834.0 million MMBtu of LNG per year (approximately 16 mtpa) as follows:


•	BG Gulf Coast LNG, LLC ("BG") has agreed to purchase 286.5 million MMBtu of LNG per year (approximately 5.5 mtpa);


•	Gas Natural Aprovisionamientos SDG S.A. ("Gas Natural Fenosa"), an affiliate of Gas Natural SDG S.A., has agreed to purchase 182.5 million MMBtu of LNG per year (approximately 3.5 mtpa);


•	Korea Gas Corporation ("KOGAS") has agreed to purchase 182.5 million MMBtu of LNG per year (approximately 3.5 mtpa); and


•	GAIL (India) Limited ("GAIL") has agreed to purchase 182.5 million MMBtu of LNG per year (approximately 3.5 mtpa).

In aggregate, these customers have agreed to pay Sabine Pass Liquefaction approximately $2.3 billion annually, plus an amount per MMBtu of LNG equal to 115% of the final settlement price for the New York Mercantile Exchange natural gas futures contract for the month in which the relevant cargo is scheduled.

In addition, Cheniere Marketing has entered into an SPA to purchase certain excess LNG produced that is not committed to non-affiliate parties, up to a maximum of 104.0 million MMBtu of LNG per year (approximately 2.0 mtpa). The sales price to be paid by Cheniere Marketing will be 115% of the then-current Henry Hub price per MMBtu plus a profit sharing equal to 100% of profits up to $3.00/MMBtu for the first 36 million MMBtu of the most profitable cargoes sold each year to Cheniere Marketing and 20% of profits for the subsequent 68 million MMBtu sold each year to Cheniere Marketing.

In November 2011, Sabine Pass Liquefaction entered into a lump sum turnkey agreement with Bechtel for procurement, engineering, design, installation, training, commissioning and placing into service the first two LNG trains and related facilities adjacent to the Sabine Pass LNG terminal. We issued to Bechtel a limited notice to proceed with construction of LNG trains 1 and 2 in June 2012, and a full notice to proceed with construction of LNG trains 1 and 2 in August 2012. We expect to begin operations of the first LNG train in late 2015, with the second LNG train commencing operations approximately six to nine months after the first LNG train. We expect to complete our construction plan and cost estimates for LNG trains 3 and 4 by the end of 2012 and begin implementing a financing strategy for those LNG trains. Commencement of construction for the third and fourth LNG trains is subject, but not limited to, entering into an EPC contract, obtaining financing and making a final investment decision.

The cost to construct LNG trains 1 and 2 is currently estimated to be approximately $4.5 billion to $5 billion, before financing costs. Our cost estimates are subject to change due to such items as change orders, delays in construction, increased component and material costs, escalation of labor costs and increased spending to maintain our construction schedule.

Financing

In May 2012, we and Blackstone entered into a unit purchase agreement whereby we agreed to sell to Blackstone in a private placement 100 million Class B Units of Cheniere Partners at a price of $15.00 per Class B Unit. Subsequent to an initial funding of $500 million by Blackstone, we can require, based on liquidity needs, that Blackstone make additional capital contributions until Blackstone has funded $1.5 billion in the aggregate. In addition, we and a wholly owned subsidiary of Cheniere entered into a unit purchase agreement whereby we agreed to sell 33.3 million Class B Units at a price of $15.00 per unit, for total consideration of $500 million, of which $166.7 million was sold in June 2012 so that we could issue a limited notice to proceed to Bechtel and the remaining $333.3 million was sold in July 2012. We will use the net proceeds from the private placements to pay for a portion of the cost to construct the first two LNG trains and related facilities and equipment. During the nine months ended September 30, 2012, we issued and sold an aggregate of 100 million Class B Units at a price of $15.00 per Class B Unit, resulting in total gross proceeds of $1.5 billion. In October 2012, Blackstone purchased $300.0 million of additional Class B Units, which, when added to prior Class B Units purchased, equals $1.3 billion total invested.

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, 2012 and 2011. 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,
	2012			2011
Sources of cash and cash equivalents
Proceeds from the sale of Class B Units	$	1,387,560		$	—
Proceeds from the sale of partnership common and general partner units	240,114			70,360
Proceeds from Liquefaction Credit Facility	100,000			—
Operating cash flow	—			12,634
Total sources of cash and cash equivalents	1,727,674			82,994

Uses of cash and cash equivalents
LNG terminal construction-in-process, net	(876,531		)	(6,419		)
Investment in restricted cash and cash equivalents	(289,851		)	—
Debt issuance costs	(210,126		)	—
Operating cash flow	(6,454		)	—
Distributions to unitholders	(40,696		)	(34,704		)
Other	(16,331		)	(722		)
Total uses of cash and cash equivalents	(1,439,989		)	(41,845		)

Net increase (decrease) in cash and cash equivalents	287,685			41,149
Cash and cash equivalents—beginning of period	81,415			53,349
Cash and cash equivalents—end of period	$	369,100		$	94,498

Proceeds from the Sale of Class B Units

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 at a price of $15.00 per Class B Unit, resulting in total net proceeds of $1,387.6 million.

Proceeds from the Sale of Partnership Common and General Partner Units

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 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 Liquefaction Credit Facility and Debt Issuance Costs

In July 2012, Sabine Pass Liquefaction entered into the $3.6 billion Liquefaction Credit Facility with a syndicate of lenders. Sabine Pass Liquefaction made $100.0 million of borrowings under the Liquefaction Credit Facility in August 2012 after meeting the required conditions precedent to the initial advance. Debt issuance costs relate to $210.1 million paid by Sabine Pass Liquefaction upon the closing of the Liquefaction Credit Facility.

Operating Cash Flow

Operating cash flow decreased $19.1 million for the nine months ended September 30, 2012 compared to the same period in 2011. The decrease in operating cash flow primarily resulted from increased costs incurred to develop and manage the construction of LNG trains 1 and 2 of the Liquefaction Project, and decreased LNG cargo export loading fee revenue.

LNG Terminal and Pipeline Construction-in-Process, net

Capital expenditures for the Sabine Pass LNG terminal were $876.5 million and $6.4 million in the nine months ended September 30, 2012, and 2011, respectively. We began capitalizing costs associated with construction of our liquefaction facilities as construction-in-process during the second quarter of 2012.

Investment in Restricted Cash and Cash Equivalents

During the nine months ended September 30, 2012, we invested $289.9 million in restricted cash and cash equivalents. This investment was a result of the $1,177.8 million investment in restricted cash and cash equivalents from the proceeds of Class B Unit sales that was partially offset by the use of restricted cash for the construction of LNG trains 1 and 2 of the Liquefaction Project.

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, 2012:



				Total Distribution
				(in thousands)
Date Paid	Period Covered by Distribution	Distribution Per Common Unit		Common Units		Subordinated Units		General Partner Units
February 14, 2012	October 1, 2011 - December 31, 2011	$	0.425	$	13,176	$	—	$	269
May 15, 2012	January 1, 2012 - March 31, 2012	$	0.425	$	13,323	$	—	$	272
August 15, 2012	April 1, 2012 - June 30, 2012	$	0.425	$	13,383	$	—	$	273

The subordinated units will receive distributions only to the extent we have available cash above the minimum 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 VCRA. The ending of the subordination period and conversion of the subordinated units into common units will depend upon future business development.

On October 22, 2012, 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, 2012 for the period from July 1, 2012 to September 30, 2012.

Debt Agreements

Senior Notes

•1.0% of the principal amount of the Senior Notes; or

•

Under the Sabine Pass Indenture, 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 of approximately $82.4 million. 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 Indenture. During the nine months ended September 30, 2012 and 2011, Sabine Pass LNG made distributions to us of $182.9 million and $155.6 million, respectively, after satisfying all of the applicable conditions in the Sabine Pass Indenture.

In October 2012, Sabine Pass LNG repurchased approximately 97% of the 2013 Notes. Funds used for the repurchase included proceeds received from the sale of the 2020 Notes and from an equity contribution from us. Sabine Pass LNG has issued a redemption notice for the remaining approximately $16.5 million outstanding 2013 Notes which it expects to redeem in November 2012.

Liquefaction Credit Facility

Under the terms of the Liquefaction Credit Facility, Sabine Pass Liquefaction is required to hedge against the potential of rising interest rates with respect to no less than 75% (calculated on a weighted average basis) of the projected outstanding borrowings. Shortly after the closing of the Liquefaction Credit Facility, Sabine Pass Liquefaction entered into interest rate swap agreements. The swap agreements have the effect of fixing the LIBOR component of the interest rate payable under the Liquefaction Credit Facility with respect to forecasted borrowings under the Liquefaction Credit Facility up to a maximum of $2.9 billion at 1.98% from August 14, 2012 to July 31, 2019, the final termination date of the swap agreements.

Services Agreements

During the nine months ended September 30, 2012 and 2011, we recorded general and administrative expense—affiliate of $30.3 million and $14.2 million, respectively, under the following service agreements.

Cheniere Partners Services Agreement

Sabine Pass LNG O&M Agreement

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.

Sabine Pass Liquefaction MSA

Results of Operations

Three Months Ended September 30, 2012 vs. Three Months Ended September 30, 2011

Overall Operations

Our net loss increased $27.9 million, from a net loss of $14.5 million in the three months ended September 30, 2011 to a net loss of $42.4 million in the three months ended September 30, 2012. This increase in net loss primarily resulted from increased costs incurred to manage the construction of LNG trains 1 and 2 of the Liquefaction Project, partially offset by decreased development costs.

General and Administrative Expense (including Affiliate Expense)

Our general and administrative expense (including affiliate expense) increased $31.7 million, from $5.8 million in the three months ended September 30, 2011 to $37.5 million in the three months ended September 30, 2012. This increase in general and administrative expense is primarily a result of increased costs incurred to manage the construction of LNG trains 1 and 2 of the Liquefaction Project.

Operating and Maintenance Expense (including Affiliate Expense)

Operating and maintenance expense (including affiliate expense) increased $4.2 million, from $8.9 million in the three months ended September 30, 2011 to $13.1 million in the three months ended September 30, 2012. This increase in operating and maintenance expense (including affiliate expense) is primarily a result of increased dredging services in the three months ended September 30, 2012.

Development Expense (including Affiliate Expense)

Development expense (including affiliate expense) decreased $5.6 million, from $9.9 million in the three months ended September 30, 2011 to $4.3 million in the three months ended September 30, 2012. This decrease in LNG terminal and pipeline development expense resulted from LNG trains 1 and 2 of the Liquefaction Project satisfying the criteria for capitalization in June 2012.

Nine Months Ended September 30, 2012 vs. Nine Months Ended September 30, 2011

Overall Operations

Our net loss increased $63.0 million, from $23.6 million in the nine months ended September 30, 2011 to $86.6 million in the nine months ended September 30, 2012. This increase in net loss primarily resulted from increased costs incurred to manage the construction of LNG trains 1 and 2 of the Liquefaction Project, decreased revenues, increased development expense and increased operating and maintenance expense.

General and Administrative Expense (including Affiliate Expense)

Our general and administrative expense (including affiliate expense) increased $32.2 million, from $19.0 million in the nine months ended September 30, 2011 to $51.2 million in the nine months ended September 30, 2012. This increase in general and administrative expense is primarily a result of increased costs incurred to manage the construction of LNG trains 1 and 2 of the Liquefaction Project.

Revenues (including Affiliate Revenues)

Revenues (including affiliate revenues) decreased $16.0 million, from $213.0 million in the nine months ended September 30, 2011 to $197.0 million in the nine months ended September 30, 2012. This decrease in revenues (including affiliate revenues) is primarily a result of decreased LNG cargo export loading fee revenue, decreased revenues earned under the VCRA, and a provision for loss on a firm purchase commitment for LNG inventory that will be used to restore the heating value of vaporized LNG to conform to natural gas pipeline specifications.

Development Expense

Development expense increased $8.6 million from $26.8 million in the nine months ended September 30, 2011 to $35.4 million in the nine months ended September 30, 2012. This increase in development expense resulted from costs incurred to develop LNG trains 1 and 2 of the Liquefaction Project.

Operating and Maintenance Expense (including Affiliate Expense)

Operating and maintenance expense (including affiliate expense) increased $7.7 million, from $24.6 million in the nine months ended September 30, 2011 to $32.3 million in the nine months ended September 30, 2012. This increase in operating and maintenance expense (including affiliate expense) is primarily a result of increased dredging services in the nine months ended September 30, 2012.

Off-Balance Sheet Arrangements

As of September 30, 2012, we had no "off-balance sheet arrangements" that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

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, 2011.

Recent Accounting Standards

In May 2011, the Financial Accounting Standards Board ("FASB") issued guidance that further addresses fair value measurement accounting and related disclosure requirements. The guidance clarifies the FASB's intent regarding the application of existing fair value measurement and disclosure requirements, changes the fair value measurement requirements for certain financial instruments, and sets forth additional disclosure requirements for other fair value measurements. The guidance is to be applied prospectively and is effective for periods beginning after December 15, 2011. We adopted this guidance effective January 1, 2012. 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.


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, 2012.



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	740,344	$2.932 - $3.234	December 2012	$	(165	)	$	11
Fuel Derivatives	Fixed price natural gas swaps	1,086,500	$3.230 - $4.275	October 2013	60			3

We have entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the Liquefaction Credit Facility ("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 $19.1 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, 2012.



Hedge Description	Hedge Instrument	Initial 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	Interest rate swaps	$	20,000	1.977 - 1.981	July 2019	$	(29,676	)	$	19,116

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 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, 2012, 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 1A. Risk Factors

The number of our common units outstanding increases the risk that we will be unable to make the initial quarterly distribution on our common units.

We are currently paying the initial quarterly distribution of $0.425 on each of our common units and the related distribution on the general partner units. We are currently not paying any distributions on the subordinated units. The Class B Units are not entitled to receive distributions until they convert into common units. As of October 24, 2012, we had outstanding 39,488,488 common units. The aggregate initial minimum quarterly distribution on these common units and the related general partner units is $68.5 million per year. We are not currently generating sufficient operating surplus each quarter to pay the initial quarterly distribution on all of these units and therefore intend to use a portion of our accumulated operating surplus each quarter to enable us to make this distribution. We may not have sufficient operating surplus to continue paying the initial quarterly distribution on all of our common units before our first two LNG trains commence commercial operations, which is not expected to occur until at least 2016. Furthermore, if our first two LNG trains do not commence commercial operations as expected and the outstanding Class B Units convert into common units, we may not have sufficient operating surplus to be able to pay the initial quarterly distribution on all common units then outstanding.

Accordingly, until the first two LNG trains commence commercial operations, the amount of cash that we can distribute on our common units principally will depend upon the amount of cash that we generate from our existing operations, which will be based on, among other things:

•performance by counterparties of their obligations under the TUAs;

•performance by Sabine Pass LNG of its obligations under the TUAs;

•performance by, and the level of cash receipts received from, Cheniere Marketing under the VCRA; and

•the level of our operating costs, including payments to our general partner and its affiliates.

In addition, the actual amount of cash that we will have available for distribution will depend on other factors such as:

•the restrictions contained in our debt agreements and our debt service requirements, including the ability of Sabine Pass

LNG to pay distributions to us under the indenture governing the Sabine Pass LNG notes as a result of requirements for a debt service reserve account, a debt payment account and satisfaction of a fixed charge coverage ratio, and the ability of Sabine Pass Liquefaction to pay distributions to us under the Liquefaction Credit Facility;

•the costs and capital requirements of acquisitions, if any;

•fluctuations in our working capital needs;

•our ability to borrow for working capital or other purposes; and

•the amount, if any, of cash reserves established by our general partner.

We may not be successful in our efforts to maintain or increase our cash available for distribution to cover the initial quarterly distribution on our common units. Any reductions in distributions to our unitholders because of a shortfall in cash flow or other events will result in a decrease of the quarterly distribution on our common units below the initial quarterly distribution. Any portion of the initial quarterly distribution that is not distributed on our common units will accrue and be paid to the common unitholders in accordance with our partnership agreement, if at all.

Sabine Pass Liquefaction may be restricted under the terms of the Liquefaction Credit Facility from making distributions under certain circumstances, which may limit our ability to pay or increase distributions to our unitholders.

In general, Sabine Pass Liquefaction is permitted to make distributions to us under the Liquefaction Credit Facility only if:

•no default or event of default under the Liquefaction Credit Facility has occurred and is continuing or would occur as a consequence

of such distribution;

•the first two LNG trains have been completed;

•Sabine Pass Liquefaction has achieved a debt service coverage ratio determined as of the end of the most recent calendar

quarter of at least 1.25 to 1.00, calculated on a trailing 12-month basis (except that any such calculation performed prior

to the first anniversary of the completion of the first two LNG trains will be based on the number of months elapsed since

such completion date);

•Sabine Pass Liquefaction has on deposit in a debt payment account an amount equal to the projected debt service payments

with respect to its senior secured debt for the next six months;

•the first principal amortization payment owing under the Liquefaction Credit Facility has been paid;

•any such distribution is paid no later than 25 business days following the last day of the most recent calendar quarter;

and

•any such distribution is paid prior to the last calendar quarter immediately preceding the Liquefaction Credit Facility maturity date.

Sabine Pass Liquefaction's inability to pay distributions to us as a result of the foregoing restrictions in the Liquefaction Credit Facility will restrict our ability to pay or increase distributions to our unitholders.


Item 6.	Exhibits



Exhibit No.		Description
10.1*		Letter Agreement, dated September 11, 2012, between Total Gas & Power North America, Inc. and Sabine Pass LNG, L.P.

10.2*		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-0008 Delay in Full Placement of Insurance, dated July 27, 2012, (ii) the Change Order CO-0009 HAZOP Action Items, dated July 31, 2012, (iii) the Change Order CO-0010 Fuel Provisional Sum, dated August 8, 2012, (iv) the Change Order CO-0011 Currency Provisional Sum, dated August 8, 2012, (v) the Change Order CO-0012 Delay in NTP, dated August 8, 2012, and (vi) the Change Order CO-0013 Early EPC Work Credit, dated August 29, 2012.

10.3*		Amended and Restated Services and Secondment Agreement, dated as of August 9, 2012, between Cheniere LNG O&M Services, LLC and Cheniere Energy Partners GP, LLC.

10.4*		Amended and Restated Management and Administrative Services Agreement, dated as of August 9, 2012, by and between Cheniere Energy Partners, L.P., Cheniere LNG Terminals, Inc. and Cheniere Energy, Inc.

10.5*		Amended and Restated Operation and Maintenance Agreement (Sabine Pass LNG Facilities), dated as of August 9, 2012, by and among Cheniere LNG O&M Services, LLC, Cheniere Energy Partners GP, LLC and Sabine Pass LNG, L.P.

10.6*		Amended and Restated Management Services Agreement, dated as of August 9, 2012, by and between Cheniere LNG Terminals, Inc. and Sabine Pass LNG, L.P.

10.7*		Form of Amendment to Phantom Units Agreement.

10.8*		Form of Phantom Units Agreement under the Cheniere Energy Partners, L.P. Long-Term Incentive Plan.

10.9*		Form of Phantom Units Agreement under the Cheniere Energy Partners, L.P. Long-Term Incentive Plan (2012 Reload Award).

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.



+	Pursuant to Rule 406T of Regulation S-T, the interactive data files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Section 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.

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 2, 2012