Edgar Filing: Cheniere Energy Partners, L.P.

CQP 2015 Form 10Q 2nd Qtr

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended June 30, 2015


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

For the transition period from to

Cheniere Energy Partners, L.P.

(Exact name of registrant as specified in its charter)



Delaware	001-33366	20-5913059
(State or other jurisdiction of incorporation or organization)	(Commission File Number)	(I.R.S. Employer Identification No.)

700 Milam Street, Suite 1900 Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)

(713) 375-5000

(Registrant’s telephone number, including area code)

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 (§232.405 of this chapter) 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 x	Accelerated filer ¨
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 x

As of July 21, 2015, the issuer had 57,095,348 common units, 145,333,334 Class B units and 135,383,831 subordinated units outstanding.

CHENIERE ENERGY PARTNERS, L.P.

TABLE OF CONTENTS



	Definitions	1
Part I. Financial Information
Item 1.	Consolidated Financial Statements	3
	Consolidated Balance Sheets	3
	Consolidated Statements of Operations	4
	Consolidated Statement of Partners’ Equity	5
	Consolidated Statements of Cash Flows	6
	Notes to Consolidated Financial Statements	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	33

Item 4.	Controls and Procedures	34

Part II. Other Information
Item 1.	Legal Proceedings	35

Item 1A.	Risk Factors	35

Item 5.	Other Information	35

Item 6.	Exhibits	36

	Signatures	38

DEFINITIONS

As commonly used in the liquefied natural gas industry, to the extent applicable, and as used in this quarterly report, the following terms have the following meanings:

Common Industry and Other Terms



Bcf/d		billion cubic feet per day
Bcf/yr		billion cubic feet per year
Bcfe		billion cubic feet equivalent
DOE		U.S. Department of Energy
EPC		engineering, procurement and construction
FERC		Federal Energy Regulatory Commission
FTA countries		countries with which the United States has a free trade agreement providing for national treatment for trade in natural gas
GAAP		generally accepted accounting principles in the United States
Henry Hub		the final settlement price (in USD per MMBtu) for the New York Mercantile Exchange’s Henry Hub natural gas futures contract for the month in which a relevant cargo’s delivery window is scheduled to begin
LIBOR		London Interbank Offered Rate
LNG		liquefied natural gas, a product of natural gas consisting primarily of methane (CH4) that is in liquid form at near atmospheric pressure
MMBtu		million British thermal units, an energy unit
mtpa		million tonnes per annum
non-FTA countries		countries without a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted
SEC		Securities and Exchange Commission
SPA		LNG sale and purchase agreement
Train		a refrigerant compressor train used in the industrial process to convert natural gas into LNG
TUA		terminal use agreement

Abbreviated Organizational Structure

The following diagram depicts our abbreviated organizational structure as of June 30, 2015, including our ownership of certain subsidiaries, and the references to these entities used in this quarterly report:

Unless the context requires otherwise, references to “Cheniere Partners,” “the Partnership,” “we,” “us” and “our” refer to Cheniere Energy Partners, L.P. (NYSE MKT: CQP) and its consolidated subsidiaries, including SPLNG, SPL and CTPL.

PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)



	June 30,			December 31,
	2015			2014
ASSETS	(unaudited)
Current assets
Cash and cash equivalents	$	194,914		$	248,830
Restricted cash	374,508			195,702
Accounts and interest receivable	410			333
Accounts receivable—affiliate	2,084			3,651
Advances to affiliate	24,783			27,323
LNG inventory	12,462			4,293
Other current assets	15,197			6,388
Total current assets	624,358			486,520

Non-current restricted cash	732,076			544,465
Property, plant and equipment, net	10,511,970			8,978,356
Debt issuance costs, net	292,450			241,909
Non-current derivative assets	426			11,744
Other non-current assets	147,257			124,521
Total assets	$	12,308,537		$	10,387,515

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	10,527		$	8,598
Accrued liabilities	312,292			136,578
Due to affiliates	49,672			18,952
Deferred revenue	26,671			26,655
Deferred revenue—affiliate	708			708
Derivative liabilities	7,839			23,247
Other current liabilities	599			18
Total current liabilities	408,308			214,756

Long-term debt, net	10,993,119			8,991,333
Non-current deferred revenue	11,500			13,500
Other non-current liabilities	1,833			2,452
Other non-current liabilities—affiliate	51,248			34,745

Partners’ equity
Common unitholders’ interest (57.1 million units issued and outstanding at June 30, 2015 and December 31, 2014)	377,702			495,597
Class B unitholders’ interest (145.3 million units issued and outstanding at June 30, 2015 and December 31, 2014)	(38,146		)	(38,216		)
Subordinated unitholders’ interest (135.4 million units issued and outstanding at June 30, 2015 and December 31, 2014)	483,802			648,414
General partner’s interest (2% interest with 6.9 million units issued and outstanding at June 30, 2015 and December 31, 2014)	19,171			24,934
Total partners’ equity	842,529			1,130,729
Total liabilities and partners’ equity	$	12,308,537		$	10,387,515

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						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
Revenues
Revenues	$	66,490		$	66,594		$	133,208		$	133,043
Revenues—affiliate	1,199			734			2,011			1,506
Total revenues	67,689			67,328			135,219			134,549

Operating costs and expenses
Operating and maintenance expense	9,095			24,232			41,082			33,451
Operating and maintenance expense—affiliate	7,501			4,860			12,274			9,291
Depreciation expense	15,991			14,722			30,870			29,040
Development expense	1,367			3,792			2,518			7,288
Development expense—affiliate	206			242			410			394
General and administrative expense	4,081			4,234			7,596			7,600
General and administrative expense—affiliate	33,472			22,972			55,069			50,125
Total operating costs and expenses	71,713			75,054			149,819			137,189

Loss from operations	(4,024		)	(7,726		)	(14,600		)	(2,640		)

Other income (expense)
Interest expense, net	(50,148		)	(43,789		)	(92,993		)	(84,059		)
Loss on early extinguishment of debt	(7,281		)	(114,335		)	(96,273		)	(114,335		)
Derivative gain (loss), net	1,175			(60,178		)	(35,209		)	(94,859		)
Other income (expense)	235			(196		)	356			(64		)
Total other expense	(56,019		)	(218,498		)	(224,119		)	(293,317		)

Net loss	$	(60,043	)	$	(226,224	)	$	(238,719	)	$	(295,957	)

Basic and diluted net loss per common unit	$	(0.01	)	$	(0.85	)	$	(0.62	)	$	(0.91	)

Weighted average number of common units outstanding used for basic and diluted net loss per common unit calculation	57,080			57,079			57,080			57,079

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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ EQUITY

(in thousands)

(unaudited)



	Common Unitholders’ Interest				Class B Unitholders’ Interest				Subordinated Unitholder’s Interest				General Partner’s Interest				Total Partners’ Equity
	Units	Amount			Units	Amount			Units	Amount			Units	Amount			Total Partners’ Equity
Balance at December 31, 2014	57,080	$	495,597		145,333	$	(38,216	)	135,384	$	648,414		6,894	$	24,934		$	1,130,729
Net loss	—	(69,383		)	—	—			—	(164,562		)	—	(4,774		)	(238,719		)
Distributions	—	(48,518		)	—	—			—	—			—	(990		)	(49,508		)
Issuance of common units as compensation to non-management directors	1	26			—	—			—	—			—	1			27
Amortization of beneficial conversion feature of Class B units	—	(20		)	—	70			—	(50		)	—	—			—
Balance at June 30, 2015	57,081	$	377,702		145,333	$	(38,146	)	135,384	$	483,802		6,894	$	19,171		$	842,529

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)



	Six Months Ended
	June 30,
	2015			2014
Cash flows from operating activities
Net loss	$	(238,719	)	$	(295,957	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation expense	30,870			29,040
Non-cash LNG inventory write-downs	17,366			14,978
Amortization of debt issuance costs and discount	5,019			5,639
Total losses on derivatives, net	35,128			94,859
Net cash used for settlement of derivative instruments	(38,028		)	(17,520		)
Loss on early extinguishment of debt	96,273			114,335
Other	25			139
Changes in restricted cash for certain operating activities	15,954			64,705
Changes in operating assets and liabilities:
Accounts and interest receivable	(77		)	(31		)
Accounts receivable—affiliate	1,441			173
Accounts payable and accrued liabilities	84,580			1,025
Due to affiliates	12,627			5,875
Deferred revenue	(1,985		)	(1,955		)
Advances to affiliate	2,541			12,838
LNG inventory	(25,534		)	(14,445		)
Other, net	(11,402		)	(6,613		)
Other, net—affiliate	16,501			(151		)
Net cash provided by operating activities	2,580			6,934

Cash flows from investing activities
Property, plant and equipment, net	(1,427,603		)	(1,305,506		)
Use of restricted cash for the acquisition of property, plant and equipment	1,471,632			1,302,039
Other	(51,017		)	2,495
Net cash used in investing activities	(6,988		)	(972		)

Cash flows from financing activities
Proceeds from issuances of long-term debt	2,000,000			2,584,500
Investment in restricted cash	(1,854,002		)	(2,321,253		)
Debt issuance and deferred financing costs	(145,998		)	(85,197		)
Repayments of long-term debt	—			(177,000		)
Distributions to owners	(49,508		)	(49,508		)
Other	—			(1,049		)
Net cash used in financing activities	(49,508		)	(49,507		)

Net decrease in cash and cash equivalents	(53,916		)	(43,545		)
Cash and cash equivalents—beginning of period	248,830			351,032
Cash and cash equivalents—end of period	$	194,914		$	307,487

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 Partners have been prepared in accordance with GAAP for interim financial information and with Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In our opinion, all adjustments, consisting only of normal recurring adjustments necessary for a fair presentation, have been included. Certain reclassifications have been made to conform prior period information to the current presentation. The reclassifications had no effect on our overall consolidated financial position, results of operations or cash flows.

Results of operations for the three and six months ended June 30, 2015 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2015.

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

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, 2014.

NOTE 2—UNITHOLDERS’ EQUITY

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. 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 holders of common units have the right to receive initial quarterly distributions of $0.425 per common unit, plus any arrearages thereon, before any distribution is made to the holders of the subordinated units. The holders of subordinated units will receive distributions only to the extent we have available cash above the initial quarterly distribution requirement for our common unitholders and general partner and certain reserves. 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 initial quarterly distributions have been achieved and as additional target levels are met. The higher percentages range from 15% to 50%.

During 2012, Blackstone CQP Holdco LP (“Blackstone”) and Cheniere completed their purchases of newly created Cheniere Partners Class B units (“Class B units”) for total consideration of $1.5 billion and $500.0 million, respectively. Proceeds from the financings were used to fund a portion of the costs of developing, constructing and placing into service the first two Trains of the natural gas liquefaction facilities at the Sabine Pass LNG terminal adjacent to the existing regasification facilities (the “Liquefaction Project”). In May 2013, Cheniere purchased an additional 12.0 million Class B units for consideration of $180.0 million in connection with our acquisition of CTPL and Cheniere Pipeline GP Interests, LLC. In 2013, Cheniere formed Cheniere Holdings to hold its limited partner interests in us. The Class B units are subject to conversion, mandatorily or at the option of the Class B unitholders under specified circumstances, into a number of common units based on the then-applicable conversion value of the Class B units. The Class B units are not entitled to cash distributions except in the event of our liquidation or a merger, consolidation or other combination of us with another person or the sale of all or substantially all of our assets. On a quarterly basis beginning on the date of the initial purchase of the Class B units and ending on the conversion date of the Class B units, the conversion value of the Class B units increases at a compounded rate of 3.5% per quarter, subject to additional upward adjustment for certain equity and debt financings. The accreted conversion ratio of the Class B units owned by Cheniere Holdings and Blackstone was 1.51 and 1.49, respectively, as of June 30, 2015. We expect the Class B units to mandatorily convert into common units within 90 days

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

of the substantial completion date of Train 3 of the Liquefaction Project, which we currently expect to occur before April 30, 2017. If the Class B units are not mandatorily converted by July 2019, the holders of the Class B units have the option to convert the Class B units into common units at that time.

NOTE 3—RESTRICTED CASH

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

SPLNG Senior Notes Debt Service Reserve

SPLNG, our wholly owned subsidiary, has consummated private offerings of an aggregate principal amount of $1,665.5 million, before discount, of 7.50% Senior Secured Notes due 2016 (the “2016 SPLNG Senior Notes”) and $420.0 million of 6.50% Senior Secured Notes due 2020 (the “2020 SPLNG Senior Notes” and collectively with the 2016 SPLNG Senior Notes, the “SPLNG Senior Notes”). Under the indentures governing the SPLNG Senior Notes (the “SPLNG Indentures”), except for permitted tax distributions, SPLNG may not make distributions until certain conditions are satisfied, including: (1) 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 (2) there must be on deposit in a permanent debt service reserve fund an amount equal to one semi-annual interest payment. Distributions are permitted only after satisfying the foregoing funding requirements, a fixed charge coverage ratio test of 2:1 and other conditions specified in the SPLNG Indentures.

As of both June 30, 2015 and December 31, 2014, we classified $15.0 million as current restricted cash for the payment of current interest due. As of both June 30, 2015 and December 31, 2014, we classified the permanent debt service reserve fund of $76.1 million as non-current restricted cash. These cash accounts are controlled by a collateral trustee; therefore, these amounts are shown as restricted cash on our Consolidated Balance Sheets.

SPL Reserve

During 2013, SPL entered into four credit facilities aggregating $5.9 billion (collectively, the “2013 SPL Credit Facilities”). In June 2015, SPL entered into four credit facilities aggregating $4.6 billion (collectively, the “2015 SPL Credit Facilities”), which replaced the 2013 SPL Credit Facilities. Under the terms and conditions of the 2015 SPL Credit Facilities, SPL is required to deposit all cash received into reserve accounts controlled by a collateral trustee. The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Project; therefore, these amounts are shown as restricted cash on our Consolidated Balance Sheets.

During 2013, SPL issued an aggregate principal amount of $2.0 billion, before premium, of 5.625% Senior Secured Notes due 2021 (the “2021 SPL Senior Notes”), $1.0 billion of 6.25% Senior Secured Notes due 2022 (the “2022 SPL Senior Notes”) and $1.0 billion of 5.625% Senior Secured Notes due 2023 (the “Initial 2023 SPL Senior Notes”). During 2014, SPL issued an aggregate principal amount of $2.0 billion of 5.75% Senior Secured Notes due 2024 (the “2024 SPL Senior Notes”) and additional 5.625% Senior Secured Notes due 2023 (the “Additional 2023 SPL Senior Notes” and collectively with the Initial 2023 SPL Senior Notes, the “2023 SPL Senior Notes”) in an aggregate principal amount of $0.5 billion, before premium. In March 2015, SPL issued an aggregate principal amount of $2.0 billion of 5.625% Senior Secured Notes due 2025 (the “2025 SPL Senior Notes” and collectively with the 2021 SPL Senior Notes, the 2022 SPL Senior Notes, the 2023 SPL Senior Notes and the 2024 SPL Senior Notes, the “SPL Senior Notes”). The use of cash proceeds from the SPL Senior Notes is restricted to the payment of liabilities related to the Liquefaction Project; therefore, these amounts are shown as restricted cash on our Consolidated Balance Sheets. See Note 7—Long-Term Debt for additional details about our long-term debt.

As of June 30, 2015 and December 31, 2014, we classified $340.5 million and $155.8 million, respectively, as current restricted cash held by SPL for the payment of current liabilities, including interest payments, related to the Liquefaction Project and $656.0 million and $457.1 million, respectively, as non-current restricted cash held by SPL for future Liquefaction Project construction costs.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

CTPL Reserve

In May 2013, CTPL entered into a $400.0 million term loan facility (the “CTPL Term Loan”). As of June 30, 2015 and December 31, 2014, we classified $19.0 million and $24.9 million, respectively, as current restricted cash held by CTPL for the payment of current liabilities and zero and $11.3 million, respectively, as non-current restricted cash held by CTPL because such funds may only be used for modifications of the 94-mile Creole Trail Pipeline, which interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines, in order to enable bi-directional natural gas flow, and for the payment of interest during construction of such modifications. The restricted cash reserved to pay interest during construction is controlled by a collateral agent and can only be released by the collateral agent upon satisfaction of certain terms and conditions. CTPL is required to pay annual fees to the administrative and collateral agents.

NOTE 4—PROPERTY, PLANT AND EQUIPMENT

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



	June 30,			December 31,
	2015			2014
LNG terminal costs
LNG terminal	$	2,435,391		$	2,240,233
LNG terminal construction-in-process	8,450,486			7,082,732
LNG site and related costs, net	138			141
Accumulated depreciation	(379,201		)	(348,907		)
Total LNG terminal costs, net	10,506,814			8,974,199
Fixed assets
Computer and office equipment	1,126			1,105
Vehicles	1,990			1,507
Machinery and equipment	1,508			1,508
Furniture and fixtures	1,375			1,375
Other	3,764			2,505
Accumulated depreciation	(4,607		)	(3,843		)
Total fixed assets, net	5,156			4,157
Property, plant and equipment, net	$	10,511,970		$	8,978,356

NOTE 5—DERIVATIVE INSTRUMENTS

We have entered into the following derivative instruments that are reported at fair value:


•	commodity derivatives to hedge the exposure to price risk attributable to future: (1) sales of our LNG inventory and (2) purchases of natural gas to operate the Sabine Pass LNG terminal (“Natural Gas Derivatives”);


•	commodity derivatives consisting of natural gas purchase agreements and associated economic hedges to secure natural gas feedstock for the Liquefaction Project (“Liquefaction Supply Derivatives”); and


•	interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the 2015 SPL Credit Facilities (“Interest Rate Derivatives”).

None of our derivative instruments are designated as cash flow hedging instruments, and changes in fair value are recorded within our Consolidated Statements of Operations.

SPLNG has elected to account for a portion of the Natural Gas Derivatives as normal purchase normal sale transactions, exempt from fair value accounting. Gains and losses for these physical hedges are not reflected on our Consolidated Statements of Operations until the period of delivery. SPLNG had not posted collateral for such forward contracts as of June 30, 2015 and December 31, 2014.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following table (in thousands) shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of June 30, 2015 and December 31, 2014, which are classified as other current assets, non-current derivative assets, derivative liabilities and other non-current liabilities in our Consolidated Balance Sheets.



	Fair Value Measurements as of
	June 30, 2015										December 31, 2014
	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
Natural Gas Derivatives asset	$	—	$	181		$	—	$	181		$	—	$	1,216		$	—	$	1,216
Liquefaction Supply Derivatives asset (liability)	—		(27		)	440		413			—		—			342		342
Interest Rate Derivatives liability	—		(8,172		)	—		(8,172		)	—		(12,036		)	—		(12,036		)

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

The fair value of substantially all of the Liquefaction Supply Derivatives is developed through the use of internal models which are impacted by inputs that are unobservable in the marketplace. As a result, the fair value of the Liquefaction Supply Derivatives is designated as Level 3 within the valuation hierarchy. The curves used to generate the fair value of the Liquefaction Supply Derivatives are based on basis adjustments applied to forward curves for a liquid trading point. In addition, there may be observable liquid market basis information in the near term, but terms of a particular Liquefaction Supply Derivatives contract may exceed the period for which such information is available, resulting in a Level 3 classification. In these instances, fair value of the contract incorporates extrapolation assumptions made in the determination of the market basis price for future delivery periods in which applicable commodity basis prices were either not observable or lacked corroborative market data. Internal fair value models that include contractual pricing with a fixed basis include fixed basis amounts for delivery at locations for which no market currently exists. Internal fair value models also include conditions precedent to the respective long-term natural gas purchase agreements. As of June 30, 2015 and December 31, 2014, the majority of the Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure has not been developed to accommodate marketable physical gas flow. Therefore, our internal fair value models were based on a market price that equated to our own contractual pricing due to: (1) the inactive and unobservable market and (2) conditions precedent and their impact on the uncertainty in the timing of our actual receipt of the physical volumes associated with each forward. The fair value of the Liquefaction Supply Derivatives is predominantly driven by market commodity basis prices and our assessment of the associated conditions precedent, including evaluating whether the respective market is available as pipeline infrastructure is developed.

There were no transfers into or out of Level 3 Liquefaction Supply Derivatives for the three and six months ended June 30, 2015 and 2014. As all of the physical Liquefaction Supply Derivatives are either purely index-priced or index-priced with a fixed basis, we do not believe that a significant change in market commodity prices would have a material impact on our Level 3 fair value measurements. The following table (in thousands, except natural gas basis spread) includes quantitative information for the unobservable inputs for the Level 3 Liquefaction Supply Derivatives as of June 30, 2015:



	Net Fair Value Asset	Valuation Technique	Significant Unobservable Input	Significant Unobservable Inputs Range
Liquefaction Supply Derivatives	$440	Income Approach	Basis Spread	$ (0.350) - $0.020

Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis, as all counterparty derivative contracts provide for net settlement.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Commodity Derivatives

We recognize all commodity derivative instruments that qualify for derivative accounting treatment, including our Natural Gas Derivatives and the Liquefaction Supply Derivatives (collectively, “Commodity Derivatives”), as either assets or liabilities and measure those instruments at fair value. Changes in the fair value of our Commodity Derivatives are reported in earnings.

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



	June 30, 2015								December 31, 2014
	Natural Gas Derivatives (1)		Liquefaction Supply Derivatives			Total			Natural Gas Derivatives (1)		Liquefaction Supply Derivatives			Total
Balance Sheet Location
Other current assets	$	181	$	307		$	488		$	1,216	$	76		$	1,292
Non-current derivative assets	—		426			426			—		586			586
Total derivative assets	181		733			914			1,216		662			1,878

Derivative liabilities	—		(222		)	(222		)	—		(53		)	(53		)
Other non-current liabilities	—		(98		)	(98		)	—		(267		)	(267		)
Total derivative liabilities	—		(320		)	(320		)	—		(320		)	(320		)

Derivative asset, net	$	181	$	413		$	594		$	1,216	$	342		$	1,558


(1)	Does not include a collateral deposit of $0.2 million and a collateral call of $1.1 million for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014, respectively.

The following table (in thousands) shows the changes in the fair value and settlements and location of our Commodity Derivatives recorded on our Consolidated Statements of Operations during the three and six months ended June 30, 2015 and 2014:



		Three Months Ended June 30,						Six Months Ended June 30,
	Statement of Operations Location	2015			2014			2015		2014
Natural Gas Derivatives loss	Revenues	$	—		$	(2	)	$	—	$	(31	)
Natural Gas Derivatives gain (loss)	Derivative gain (loss), net	(294		)	(56		)	460		(258		)
Liquefaction Supply Derivatives gain (1)	Operating and maintenance expense	81			—			81		—


(1)	There were no physical settlements during the reporting period.

The use of Commodity Derivatives exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances when our Commodity Derivatives are in an asset position.

Natural Gas Derivatives

Our Natural Gas Derivatives are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. We are required by these financial institutions to use margin deposits as credit support for our Natural Gas Derivatives activities.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Liquefaction Supply Derivatives

SPL has entered into index-based physical natural gas supply contracts and associated economic hedges to secure natural gas feedstock for the Liquefaction Project. The terms of the physical contracts range from approximately one to seven years and commence upon the occurrence of conditions precedent, including the date of first commercial operation of specified Trains of the Liquefaction Project. We recognize the Liquefaction Supply Derivatives as either assets or liabilities and measure those instruments at fair value. Changes in the fair value of the Liquefaction Supply Derivatives are reported in earnings. As of June 30, 2015, SPL has secured up to approximately 2,162.8 million MMBtu of natural gas feedstock through long-term natural gas purchase agreements, of which the forward notional natural gas buy position of the Liquefaction Supply Derivatives was approximately 1,250.3 million MMBtu, which were recorded as derivatives due to minimum purchase requirements.

Interest Rate Derivatives

SPL has entered into Interest Rate Derivatives to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the 2015 SPL Credit Facilities. The Interest Rate Derivatives hedge a portion of the expected outstanding borrowings over the term of the 2015 SPL Credit Facilities.

In March 2015, SPL settled a portion of its interest rate derivatives related to the 2013 SPL Credit Facilities, and we recognized a derivative loss of $34.7 million within our Consolidated Statements of Operations in conjunction with the termination of approximately $1.8 billion of commitments under the 2013 SPL Credit Facilities as discussed in Note 7—Long-Term Debt. In May 2014, SPL settled a portion of its interest rate derivatives related to the 2013 SPL Credit Facilities and recognized a derivative loss of $9.3 million within our Consolidated Statements of Operations in conjunction with the early termination of approximately $2.1 billion of commitments under the 2013 SPL Credit Facilities.

At June 30, 2015, SPL had the following Interest Rate Derivatives outstanding:

Initial Notional Amount

Maximum Notional Amount

Effective Date

Maturity Date

Weighted Average Fixed Interest Rate Paid

Variable Interest Rate Received

Interest Rate Derivatives

$20.0 million

$690.8 million

August 14, 2012

July 31, 2019

1.98%

One-month LIBOR

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



		Fair Value Measurements as of
	Balance Sheet Location	June 30, 2015			December 31, 2014
Interest Rate Derivatives	Non-current derivative assets (Other non-current liabilities)	$	(555	)	$	11,158
Interest Rate Derivatives	Derivative liabilities	(7,617		)	(23,194		)

The following table (in thousands) shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in derivative gain (loss), net on our Consolidated Statements of Operations during the three and six months ended June 30, 2015 and 2014:



	Three Months Ended June 30,					Six Months Ended June 30,
	2015		2014			2015			2014
Interest Rate Derivatives gain (loss)	$	1,469	$	(60,122	)	$	(35,669	)	$	(94,601	)

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Balance Sheet Presentation

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



	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
As of June 30, 2015
Natural Gas Derivatives	$	267		$	(86	)	$	181
Liquefaction Supply Derivatives	733			—			733
Liquefaction Supply Derivatives	(320		)	—			(320		)
Interest Rate Derivatives	(8,172		)	—			(8,172		)
As of December 31, 2014
Natural Gas Derivatives	1,226			(10		)	1,216
Liquefaction Supply Derivatives	662			—			662
Liquefaction Supply Derivatives	(320		)	—			(320		)
Interest Rate Derivatives	11,158			—			11,158
Interest Rate Derivatives	(23,194		)	—			(23,194		)

NOTE 6—ACCRUED LIABILITIES

As of June 30, 2015 and December 31, 2014, accrued liabilities consisted of the following (in thousands):



	June 30,		December 31,
	2015		2014
Interest expense and related debt fees	$	224,690	$	112,858
Liquefaction Project costs	78,827		22,014
LNG terminal costs	6,477		1,077
Other accrued liabilities	2,298		629
Total accrued liabilities	$	312,292	$	136,578

NOTE 7—LONG-TERM DEBT

As of June 30, 2015 and December 31, 2014, our long-term debt consisted of the following (in thousands):



	Interest	June 30,			December 31,
	Rate	2015			2014
Long-term debt
2016 SPLNG Senior Notes	7.500%	$	1,665,500		$	1,665,500
2020 SPLNG Senior Notes	6.500%	420,000			420,000
2021 SPL Senior Notes	5.625%	2,000,000			2,000,000
2022 SPL Senior Notes	6.250%	1,000,000			1,000,000
2023 SPL Senior Notes	5.625%	1,500,000			1,500,000
2024 SPL Senior Notes	5.750%	2,000,000			2,000,000
2025 SPL Senior Notes	5.625%	2,000,000			—
2015 SPL Credit Facilities (1)	(2)	—			—
CTPL Term Loan	(3)	400,000			400,000
Total long-term debt		10,985,500			8,985,500
Long-term debt premium (discount)
2016 SPLNG Senior Notes		(6,651		)	(8,998		)
2021 SPL Senior Notes		9,457			10,177
2023 SPL Senior Notes		6,745			7,089
CTPL Term Loan		(1,932		)	(2,435		)
Total long-term debt, net		$	10,993,119		$	8,991,333

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)


(1)	Matures on the earlier of December 31, 2020 or the second anniversary of the completion date of Trains 1 through 5 of the Liquefaction Project.

(2)

Variable interest rate, at SPL’s election, is LIBOR or the base rate plus the applicable margin. The applicable margins for LIBOR loans range from 1.30% to 1.75%, depending on the applicable 2015 SPL Credit Facility, and the applicable margin for base rate loans is 1.75%. 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 quarter.


(3)	Variable interest rate, at CTPL’s election, is LIBOR or the base rate plus the applicable margin. CTPL has historically elected LIBOR loans, for which the applicable margin is 3.25% and is due and payable at the end of each LIBOR period.

For the three months ended June 30, 2015 and 2014, we incurred $174.8 million and $140.4 million of total interest cost, respectively, of which we capitalized and deferred $124.7 million and $96.6 million, respectively, of interest cost, including amortization of debt issuance costs, primarily related to the construction of the first four Trains of the Liquefaction Project. For the six months ended June 30, 2015 and 2014, we incurred $334.9 million and $269.0 million of total interest cost, respectively, of which we capitalized and deferred $241.9 million and $184.9 million, respectively, of interest cost, including amortization of debt issuance costs, primarily related to this construction.

SPLNG Senior Notes

Under the SPLNG Indentures, except for permitted tax distributions, SPLNG may not make distributions until certain conditions are satisfied as described in Note 3—Restricted Cash. During the six months ended June 30, 2015 and 2014, SPLNG made distributions of $199.6 million and $173.0 million, respectively, after satisfying all the applicable conditions in the SPLNG Indentures.

SPL Senior Notes

In March 2015, SPL issued an aggregate principal amount of $2.0 billion of the 2025 SPL Senior Notes, for which borrowings accrue interest at a fixed rate of 5.625%. The terms of the 2025 SPL Senior Notes are governed by the same common indenture with the other SPL Senior Notes. In connection with the closing of the sale of the 2025 SPL Senior Notes, SPL entered into a Registration Rights Agreement dated March 3, 2015 (the “2025 SPL Registration Rights Agreement”). Under the terms of the 2025 SPL Registration Rights Agreement, SPL has agreed, and any future guarantors of the 2025 SPL Senior Notes will agree, to use commercially reasonable efforts to file with the SEC and cause to become effective a registration statement within 360 days after March 3, 2015 with respect to an offer to exchange any and all of the 2025 SPL Senior Notes for a like aggregate principal amount of debt securities of SPL with terms identical in all material respects to the respective 2025 SPL Senior Notes sought to be exchanged (other than with respect to restrictions on transfer or to any increase in annual interest rate), and that are registered under the Securities Act of 1933, as amended. Under specified circumstances, SPL has also agreed, and any future guarantors will also agree, to use commercially reasonable efforts to cause to become effective a shelf registration statement relating to resales of the 2025 SPL Senior Notes. SPL will be obligated to pay additional interest if it fails to comply with its obligations to register the 2025 SPL Senior Notes within the specified time periods.

2015 SPL Credit Facilities

In June 2015, SPL entered into the 2015 SPL Credit Facilities with commitments aggregating $4.6 billion. The 2015 SPL Credit Facilities are being used to fund a portion of the costs of developing, constructing and placing into operation Trains 1 through 5 of the Liquefaction Project. Borrowings under the 2015 SPL Credit Facilities may be refinanced, in whole or in part, at any time without premium or penalty; however, interest rate hedging and interest rate breakage costs may be incurred. As of June 30, 2015, SPL had $4.6 billion of available commitments and no outstanding borrowings under the 2015 SPL Credit Facilities.

SPL incurred $89.9 million of debt issuance costs in connection with the 2015 SPL Credit Facilities. In addition to interest, SPL is required to pay insurance/guarantee premiums of 0.45% per annum on any drawn amounts under the covered tranches of the 2015 SPL Credit Facilities. The 2015 SPL Credit Facilities also require SPL to pay a quarterly commitment fee calculated at either: (1) a rate per annum equal to 40% of the applicable margin, multiplied by the average daily amount of the undrawn commitment, or (2) 0.70% of the undrawn commitment, depending on the applicable 2015 SPL Credit Facility. The principal of the loans made under the 2015 SPL Credit Facilities must be repaid in quarterly installments, commencing with the earlier of June 30, 2020 and the last day of the first full calendar quarter after the completion date of Trains 1 through 5 of the Liquefaction Project.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Scheduled repayments are based upon an 18-year amortization profile, with the remaining balance due upon the maturity of the 2015 SPL Credit Facilities.

The 2015 SPL Credit Facilities contain conditions precedent for borrowings, as well as customary affirmative and negative covenants. The obligations of SPL under the 2015 SPL Credit Facilities are secured by substantially all of the assets of SPL as well as all of the membership interests in SPL on a pari passu basis with the SPL Senior Notes.

Under the terms of the 2015 SPL Credit Facilities, within 90 days of the closing date, SPL is required to hedge not less than 65% of the variable interest rate exposure of its projected outstanding borrowings, calculated on a weighted average basis in comparison to its anticipated draw of principal.

2013 SPL Credit Facilities

In May 2013, SPL entered into the 2013 SPL Credit Facilities to fund a portion of the costs of developing, constructing and placing into operation Trains 1 through 4 of the Liquefaction Project. As of December 31, 2014, SPL had no outstanding borrowings under the 2013 SPL Credit Facilities. In June 2015, the 2013 SPL Credit Facilities were replaced with the 2015 SPL Credit Facilities.

In March 2015, in conjunction with SPL’s issuance of the 2025 SPL Senior Notes, SPL terminated approximately $1.8 billion of commitments under the 2013 SPL Credit Facilities. This termination and the replacement of the 2013 SPL Credit Facilities with the 2015 SPL Credit Facilities in June 2015 resulted in a write-off of debt issuance costs and deferred commitment fees associated with the 2013 SPL Credit Facilities of $7.3 million and $96.3 million for the three and six months ended June 30, 2015, respectively.

CTPL Term Loan

As of June 30, 2015, CTPL had borrowed the full amount of $400.0 million available under the CTPL Term Loan. The CTPL Term Loan matures in 2017 when the full amount of the outstanding principal obligations must be repaid. The outstanding balance may be repaid, in whole or in part, at any time without premium or penalty.

SPL LC Agreement

In April 2014, SPL entered into a $325.0 million senior letter of credit and reimbursement agreement (the “SPL LC Agreement”) that it uses for the issuance of letters of credit for certain working capital requirements related to the Liquefaction Project. SPL pays (1) a commitment fee in an amount equal to an annual rate of 0.75% of an amount equal to the unissued portion of letters of credit available pursuant to the SPL LC Agreement and (2) a letter of credit fee equal to an annual rate of 2.5% of the undrawn portion of all letters of credit issued under the SPL LC Agreement. If draws are made upon any letters of credit issued under the SPL LC Agreement, the amount of the draw will be deemed a loan issued to SPL. SPL is required to pay the full amount of this loan on or prior to the business day immediately succeeding the deemed issuance of the loan. These loans accrue interest at a rate of 2.0% plus the base rate as defined in the SPL LC Agreement. As of June 30, 2015 and December 31, 2014, SPL had issued letters of credit in an aggregate amount of $72.9 million and $9.5 million, respectively, and as of both June 30, 2015 and December 31, 2014, no draws had been made upon any letters of credit issued under the SPL LC Agreement.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Fair Value Disclosures

The following table (in thousands) shows the carrying amount and estimated fair value of our long-term debt:



	June 30, 2015				December 31, 2014
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
2016 SPLNG Senior Notes, net of discount (1)	$	1,658,849	$	1,745,939	$	1,656,502	$	1,718,621
2020 SPLNG Senior Notes (1)	420,000		435,750		420,000		428,400
2021 SPL Senior Notes, net of premium (1)	2,009,457		2,049,646		2,010,177		1,985,050
2022 SPL Senior Notes (1)	1,000,000		1,027,500		1,000,000		1,020,000
2023 SPL Senior Notes, net of premium (1)	1,506,745		1,493,561		1,507,089		1,476,947
2024 SPL Senior Notes (1)	2,000,000		1,982,500		2,000,000		1,970,000
2025 SPL Senior Notes (1)	2,000,000		1,960,000		—		—
2015 SPL Credit Facilities (2)	—		—		—		—
CTPL Term Loan, net of discount (2)	398,068		400,000		397,565		400,000


(1)	The Level 2 estimated fair value was based on quotations obtained from broker-dealers who make markets in these and similar instruments based on the closing trading prices on June 30, 2015 and December 31, 2014, as applicable.


(2)	The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.

NOTE 8—RELATED PARTY TRANSACTIONS

LNG Terminal Capacity Agreements

Terminal Use Agreement

SPL obtained approximately 2.0 Bcf/d of regasification capacity under a TUA with SPLNG as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA with SPLNG. SPL is obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year, continuing until at least 20 years after SPL delivers its first commercial cargo at the Liquefaction Project.

In connection with this TUA, SPL is required to pay for a portion of the cost (primarily LNG inventory) to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal. During the three months ended June 30, 2015 and 2014, we recorded a recovery of $0.1 million and expense of $15.0 million, respectively, and during the six months ended June 30, 2015 and 2014, we recorded $17.7 million and $14.8 million, respectively, as operating and maintenance expense related to this obligation.

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

In an effort to utilize Cheniere Investments’ reserved capacity under the TURA during construction of the Liquefaction Project, Cheniere Marketing has entered into an amended and restated variable capacity rights agreement with Cheniere Investments (the “Amended and Restated VCRA”) pursuant to which Cheniere Marketing is obligated to pay Cheniere Investments 80% of the expected gross margin of each cargo of LNG that Cheniere Marketing arranges for delivery to the Sabine Pass LNG terminal. We recorded no revenues—affiliate from Cheniere Marketing during the three and six months ended June 30, 2015 and 2014, respectively, related to the Amended and Restated VCRA.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Cheniere Marketing SPA

Cheniere Marketing has entered into an amended and restated SPA with SPL to purchase, at Cheniere Marketing’s option, any LNG produced by SPL in excess of that required for other customers at a price of 115% of Henry Hub plus $3.00 per MMBtu of LNG.

Commissioning Agreement

In May 2015, SPL entered into an agreement with a wholly owned subsidiary of Cheniere Marketing that obligates such subsidiary in certain circumstances to buy LNG cargoes produced during the periods while Bechtel Oil, Gas and Chemicals, Inc. has control of, and is commissioning, the first four Trains of the Liquefaction Project.

Pre-commercial LNG Marketing Agreement

In May 2015, SPL entered into an agreement with a wholly owned subsidiary of Cheniere Marketing that authorizes such subsidiary to act on SPL’s behalf to market and sell pre-commercial LNG that has not been accepted by BG Gulf Coast LNG, LLC.

Services Agreements

As of June 30, 2015 and December 31, 2014, we had $24.8 million and $27.3 million of advances to affiliates, respectively, under the services agreements described below. During the three months ended June 30, 2015 and 2014, we recorded general and administrative expense—affiliate of $33.5 million and $23.0 million, respectively, and operating and maintenance expense—affiliate of $7.5 million and $4.9 million, respectively, under the services agreements described below. During the six months ended June 30, 2015 and 2014, we recorded general and administrative expense—affiliate of $55.1 million and $50.1 million, respectively, and operating and maintenance expense—affiliate of $12.3 million and $9.3 million, respectively, under the services agreements described below.

Cheniere Partners Services Agreement

We have entered into a services agreement with Cheniere Terminals, a wholly owned subsidiary of Cheniere, pursuant to which Cheniere Terminals is entitled to 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, Cheniere Terminals is entitled to reimbursement for all audit, tax, legal and finance fees incurred by Cheniere Terminals that are necessary to perform the services under the agreement.

SPLNG O&M Agreement

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

SPLNG MSA

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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

SPL O&M Agreement

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

SPL MSA

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

CTPL O&M Agreement

CTPL has entered into an amended long-term operation and maintenance agreement (the “CTPL O&M Agreement”) with Cheniere Investments pursuant to which CTPL receives all necessary services required to operate and maintain the Creole Trail Pipeline. CTPL is required to reimburse the counterparty for its operating expenses, which consist primarily of labor expenses. Cheniere Investments provides the services required under the CTPL O&M Agreement pursuant to a secondment agreement with a wholly owned subsidiary of Cheniere.

CTPL MSA

CTPL has entered into a management services agreement with Cheniere Terminals pursuant to which Cheniere Terminals manages the modification and operation of the Creole Trail Pipeline, excluding those matters provided for under the CTPL O&M Agreement. The services include, among other services, exercising the day-to-day management of CTPL’s affairs and business, managing CTPL’s regulatory matters, managing bank and brokerage accounts and financial books and records of CTPL’s business and operations and providing contract administration services for all contracts associated with the pipeline facilities. CTPL pays a monthly fee equal to 3.0% of the capital expenditures to enable bi-directional natural gas flow on the Creole Trail Pipeline incurred in the previous month.

LNG Lease Agreement

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

As a result of Cheniere Investments assuming full price risk associated with the LNG Lease Agreement, any LNG inventory purchased by Cheniere Marketing under this arrangement is classified as LNG inventory—affiliate on our Consolidated Balance Sheets. This amount is recorded at cost and subject to lower of cost or market (“LCM”) adjustments at the end of each period.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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 June 30, 2015 and December 31, 2014, we had no LNG inventory—affiliate recorded on our Consolidated Balance Sheets under the LNG Lease Agreement.

Agreement to Fund SPLNG’s Cooperative Endeavor Agreements (“CEAs”)

In July 2007, SPLNG executed CEAs with various Cameron Parish, Louisiana taxing authorities that allow them to collect certain annual property tax payments from SPLNG from 2007 through 2016. This ten-year initiative represents an aggregate commitment of up to $25.0 million, and SPLNG 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 SPLNG’s advance payments of annual ad valorem taxes, Cameron Parish will grant SPLNG 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, SPLNG entered into an agreement with Cheniere Marketing, pursuant to which Cheniere Marketing would pay SPLNG 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 SPLNG under its TUA starting in 2019. In June 2010, Cheniere Marketing assigned its TUA to Cheniere Investments and concurrently entered into a variable capacity rights agreement, allowing Cheniere Marketing to utilize Cheniere Investments’ capacity under the TUA after the assignment. In July 2012, Cheniere Investments entered into the Amended and Restated VCRA with Cheniere Marketing in order for Cheniere Investments to utilize during construction of the Liquefaction Project the capacity rights granted under the TURA. Cheniere Marketing will continue to fund the CEAs during the term of the Amended and Restated VCRA and, in exchange, Cheniere Marketing will receive the benefit of any future credits.

On a consolidated basis, these advance tax payments were recorded to other non-current assets, and payments from Cheniere Marketing that SPLNG utilized to make the ad valorem tax payments were recorded as a long-term obligation. As of June 30, 2015 and December 31, 2014, we had $22.1 million and $19.6 million, respectively, of other non-current assets resulting from SPLNG’s ad valorem tax payments and non-current liabilities—affiliate resulting from these payments received from Cheniere Marketing.

Contracts for Sale and Purchase of Natural Gas and LNG

SPLNG is able to sell and purchase natural gas and LNG under agreements with Cheniere Marketing. Under these agreements, SPLNG purchases natural gas or LNG from Cheniere Marketing at a sales price equal to the actual purchase price paid by Cheniere Marketing to suppliers of the natural gas or LNG, plus any third-party costs incurred by Cheniere Marketing with respect to the receipt, purchase and delivery of natural gas or LNG to the Sabine Pass LNG terminal. As a result, SPLNG records the purchases of natural gas and LNG from Cheniere Marketing to be utilized as fuel to operate the Sabine Pass LNG terminal as operating and maintenance expense.

SPLNG recorded operating and maintenance expense of $1.1 million and $0.7 million in the three months ended June 30, 2015 and 2014, respectively, and $2.7 million and $1.2 million in the six months ended June 30, 2015 and 2014, respectively, for natural gas purchased from Cheniere Marketing under these agreements. SPLNG recorded revenues—affiliate of $4.1 million and $0.1 million in the three months ended June 30, 2015 and 2014, respectively, and $5.4 million and $0.1 million in the six months ended June 30, 2015 and 2014, respectively, for natural gas sold to Cheniere Marketing under these agreements.

Tug Boat Lease Sharing Agreement

In connection with its tug boat lease, Sabine Pass Tug Services, LLC (“Tug Services”), a wholly owned subsidiary of SPLNG, entered into a tug sharing agreement with a wholly owned subsidiary of Cheniere to provide its LNG cargo vessels with tug boat and marine services at the Sabine Pass LNG terminal. Tug Services recorded revenues—affiliate of $0.7 million pursuant to this agreement in each of the three months ended June 30, 2015 and 2014, and $1.4 million in each of the six months ended June 30, 2015 and 2014.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

LNG Terminal Export Agreement

In January 2010, SPLNG 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. SPLNG did not record any revenues associated with this agreement during the three and six months ended June 30, 2015 and 2014.

State Tax Sharing Agreements

In November 2006, SPLNG and Cheniere entered into a state tax sharing agreement. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which SPLNG and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, SPLNG will pay to Cheniere an amount equal to the state and local tax that SPLNG would be required to pay if its state and local tax liability were computed on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from SPLNG under this agreement; therefore, Cheniere has not demanded any such payments from SPLNG. The agreement is effective for tax returns due on or after January 1, 2008.

In August 2012, SPL entered into a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which SPL and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, SPL will pay to Cheniere an amount equal to the state and local tax that SPL would be required to pay if SPL’s state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from SPL under this agreement; therefore, Cheniere has not demanded any such payments from SPL. The agreement is effective for tax returns due on or after August 2012.

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

NOTE 9—NET LOSS PER COMMON UNIT

Net income (loss) per common unit for a given period is based on the distributions that will be made to the unitholders with respect to the period plus an allocation of undistributed net income (loss) based on provisions of the partnership agreement, divided by the weighted average number of common units outstanding. Distributions paid by us are presented on the Consolidated Statement of Partners’ Equity. On July 24, 2015, we declared a $0.425 distribution per common unit and the related distribution to our general partner to be paid on August 14, 2015 to unitholders of record as of August 3, 2015 for the period from April 1, 2015 to June 30, 2015.

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. Historical income (loss) attributable to a company that was purchased from an entity under common control is allocated to the predecessor owner in accordance with the terms of the partnership agreement. Distributions are treated as distributed earnings in the computation of earnings per common unit even though cash distributions are not necessarily derived from current or prior period earnings.

The Class B units were issued at a discount to the market price of the common units into which they are convertible. This discount totaling $2,130.0 million represents a beneficial conversion feature and is reflected as an increase in common and subordinated unitholders’ equity and a decrease in Class B unitholders’ equity to reflect the fair value of the Class B units at

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

issuance on our Consolidated Statements of Partners’ Equity. The beneficial conversion feature is considered a dividend that will be distributed ratably with respect to any Class B unit from its issuance date through its conversion date, resulting in an increase in Class B unitholders’ equity and a decrease in common and subordinated unitholders’ equity. We amortize the beneficial conversion feature assuming a conversion date of June 2017 and August 2017 for Cheniere Holdings’ and Blackstone’s Class B units, respectively, although actual conversion may occur prior to or after these assumed dates. We are amortizing using the effective yield method with a weighted average effective yield of 888.7% per year and 966.1% per year for Cheniere Holdings’ and Blackstone’s Class B units, respectively. The impact of the beneficial conversion feature is also included in earnings per unit for the three and six months ended June 30, 2015 and 2014.

The following is a schedule by years, based on the capital structure as of June 30, 2015, of the anticipated impact to the capital accounts in connection with the amortization of the beneficial conversion feature (in thousands):



	Common Units		Class B Units	Subordinated Units
2015	(232	)	781	(549	)
2016	(29,564	)	99,685	(70,121	)
2017	(594,404	)	2,004,209	(1,409,805	)

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Under our partnership agreement, the incentive distribution rights (“IDRs”) participate in net income (loss) only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in undistributed net income (loss). We did not allocate earnings or losses to IDR holders for the purpose of the two-class method earnings per unit calculation for any of the periods presented. The following table provides a reconciliation of net loss and the allocation of net loss to the common units, the subordinated units and the general partner for purposes of computing net 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 June 30, 2015
Net loss	$	(60,043	)
Declared distributions	24,754			24,259			—		—			495
Assumed allocation of undistributed net loss	$	(84,797	)	(24,646		)	—		(58,455		)	(1,696		)
Assumed allocation of net loss				$	(387	)	$	—	$	(58,455	)	$	(1,201	)

Weighted average units outstanding				57,080			145,333		135,384
Net loss per unit				$	(0.01	)	$	—	$	(0.43	)

Three Months Ended June 30, 2014
Net loss	$	(226,224	)
Declared distributions	24,754			24,259			—		—			495
Assumed allocation of undistributed net loss	$	(250,978	)	(72,944		)	—		(173,014		)	(5,020		)
Assumed allocation of net loss				$	(48,685	)	$	—	$	(173,014	)	$	(4,525	)

Weighted average units outstanding				57,079			145,333		135,384
Net loss per unit				$	(0.85	)	$	—	$	(1.28	)

Six Months Ended June 30, 2015
Net loss	$	(238,719	)
Declared distributions	49,508			48,518			—		—			990
Assumed allocation of undistributed net loss	$	(288,227	)	(83,771		)	—		(198,691		)	(5,765		)
Assumed allocation of net loss				$	(35,253	)	$	—	$	(198,691	)	$	(4,775	)

Weighted average units outstanding				57,080			145,333		135,384
Net loss per unit				$	(0.62	)	$	—	$	(1.47	)

Six Months Ended June 30, 2014
Net loss	$	(295,957	)
Declared distributions	49,508			48,518			—		—			990
Assumed allocation of undistributed net loss	$	(345,465	)	(100,406		)	—		(238,150		)	(6,909		)
Assumed allocation of net loss				$	(51,888	)	$	—	$	(238,150	)	$	(5,919	)

Weighted average units outstanding				57,079			145,333		135,384
Net loss per unit				$	(0.91	)	$	—	$	(1.76	)

NOTE 10—SUPPLEMENTAL CASH FLOW INFORMATION

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



	Six Months Ended June 30,
	2015		2014
Cash paid during the year for interest, net of amounts capitalized and deferred	$	55,516	$	49,219
Balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate)	236,549		289,453

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 11—RECENT ACCOUNTING STANDARDS

In May 2014, the Financial Accounting Standards Board (the “FASB”) amended its guidance on revenue recognition. The core principle of this amendment is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This guidance is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, with earlier adoption not permitted. This guidance may be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.

In August 2014, the FASB issued authoritative guidance that requires an entity’s management to evaluate, for each reporting period, whether there are conditions and events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the financial statements are issued. Additional disclosures are required if management concludes that conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. This guidance is effective for annual reporting periods ending after December 15, 2016, and for annual periods and interim periods thereafter, with earlier adoption permitted. The adoption of this guidance is not expected to have an impact on our Consolidated Financial Statements or related disclosures.

In February 2015, the FASB amended its guidance on consolidation analysis. This amendment primarily affects asset managers and reporting entities involved with limited partnerships or similar entities, but the analysis is relevant in the evaluation of any reporting organization’s requirement to consolidate a legal entity. This guidance changes (1) the identification of variable interests, (2) the variable interest entity characteristics for a limited partnership or similar entity and (3) the primary beneficiary determination. This guidance is effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period, with earlier adoption permitted. This guidance may be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.

In April 2015, the FASB issued authoritative guidance that requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the debt liability rather than as an asset. This guidance is effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period, with earlier adoption permitted. This guidance must be adopted retrospectively to each prior reporting period presented and disclosures will be required for a change in accounting principles. We are currently evaluating the impact of the provisions of this guidance on our Consolidated Balance Sheets.

In April 2015, the FASB issued authoritative guidance that requires a master limited partnership to allocate net income (losses) of a transferred business entirely to the general partner when computing earnings per unit for periods before the dropdown transaction occurred. This guidance also requires a master limited partnership to disclose the effects of the dropdown transaction on net income (losses) per unit for the periods before and after the dropdown transaction occurred. This guidance is effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period, with earlier adoption permitted. This guidance must be adopted retrospectively to each prior reporting period presented. The adoption of this guidance is not expected to have an impact on our Consolidated Financial Statements or related disclosures.

In July 2015, the FASB issued revised guidance related to the measurement of inventory. Inventory would be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This guidance is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, with earlier adoption permitted. This guidance should be adopted prospectively. We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.


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.” All statements, other than statements of historical facts, included herein or incorporated herein by reference are “forward-looking statements.” Included among “forward-looking statements” are, among other things:


•	statements regarding our ability to pay distributions to our unitholders;


•	statements regarding our expected receipt of cash distributions from SPLNG, SPL or CTPL;


•	statements that we expect to commence or complete construction of our proposed LNG terminals, liquefaction facilities, pipeline facilities or other projects, or any expansions thereof, by certain dates, or at all;

•

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


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


•	statements relating to the construction of our Trains, including statements concerning the engagement of any EPC contractor or other contractor and the anticipated terms and provisions of any agreement with any EPC or other contractor, and anticipated costs related thereto;


•	statements regarding any SPA or other agreement to be entered into or performed substantially in the future, including any revenues anticipated to be received and the anticipated timing thereof, and statements regarding the amounts of total LNG regasification, liquefaction or storage capacities that are, or may become, subject to contracts;


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


•	statements regarding our planned development and construction of additional Trains, including the financing of such Trains;


•	statements that our Trains, when completed, will have certain characteristics, including amounts of liquefaction capacities;


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


•	statements regarding legislative, governmental, regulatory, administrative or other public body actions, approvals, requirements, permits, applications, filings, investigations, proceedings or decisions; and


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

All of these types of statements, other than statements of historical fact, are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology. The forward-looking statements contained in this quarterly report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe that such estimates are reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond our control. In addition, assumptions may prove to be inaccurate. We caution that the forward-looking statements contained in this quarterly report are not guarantees of future performance and that such statements may not be realized or the forward-looking statements or events may not occur. Actual results may differ materially from those anticipated or implied in forward-looking statements due to factors described in this quarterly report and in the other reports and other information that we file with the SEC. These forward-looking statements speak only as of the date made, and other than as required by law, we undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

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, 2014. 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.

Introduction

The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our Consolidated Financial Statements and the accompanying notes. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future. Our discussion and analysis 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 Estimates


•	Recent Accounting Standards

Overview of Business

We are a publicly traded Delaware limited partnership formed by Cheniere (NYSE MKT: LNG). Through our wholly owned subsidiary, SPLNG, we own and operate the regasification facilities at the Sabine Pass LNG terminal located on the Sabine Pass deepwater shipping channel less than four miles from the Gulf Coast. The Sabine Pass LNG terminal includes existing infrastructure of five LNG storage tanks with capacity of approximately 16.9 Bcfe, two docks that can accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. We are developing and constructing natural gas liquefaction facilities (the “Liquefaction Project”) at the Sabine Pass LNG terminal adjacent to the existing regasification facilities through our wholly owned subsidiary, SPL. We plan to construct up to six Trains, which are in various stages of development. Each Train is expected to have a nominal production capacity of approximately 4.5 mtpa of LNG. We also own the 94-mile Creole Trail Pipeline through our wholly owned subsidiary, CTPL, which interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines.

Overview of Significant Events

Our significant accomplishments since January 1, 2015 and through the filing date of this Form 10-Q include the following:


•	SPL issued an aggregate principal amount of $2.0 billion of 5.625% Senior Secured Notes due 2025 (the “2025 SPL Senior Notes”). Net proceeds from the offering will be used to pay a portion of the capital costs associated with the construction of the first four Trains of the Liquefaction Project.


•	We received authorization from the FERC to site, construct and operate Trains 5 and 6 of the Liquefaction Project.


•	SPL received authorization from the DOE to export up to a combined total of the equivalent of 503.3 Bcf/yr of domestically produced LNG by vessel from Trains 5 and 6 of the Liquefaction Project to non-FTA countries for a 20-year term.


•	SPL entered into a lump sum turnkey contract for the engineering, procurement and construction of Train 5 of the Liquefaction Project (the “EPC Contract (Train 5)”).


•	SPL entered into four credit facilities (collectively, the “2015 SPL Credit Facilities”) totaling $4.6 billion, which replaced its existing credit facilities. The 2015 SPL Credit Facilities will be used to fund a portion of the costs of developing, constructing and placing into operation Trains 1 through 5 of the Liquefaction Project.


•	SPL issued a notice to proceed to Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) under the EPC Contract (Train 5).

Liquidity and Capital Resources

Cash and Cash Equivalents

As of June 30, 2015, we had $194.9 million of cash and cash equivalents and $1,106.6 million of current and non-current restricted cash (which included current and non-current restricted cash available to us, SPL and SPLNG) designated for the following purposes: $996.5 million for the Liquefaction Project; $19.0 million for CTPL; and $91.1 million for interest payments related to the SPLNG Senior Notes described below.

Sabine Pass LNG Terminal

Regasification Facilities

The Sabine Pass LNG terminal has operational regasification capacity of approximately 4.0 Bcf/d and aggregate LNG storage capacity of approximately 16.9 Bcfe. Approximately 2.0 Bcf/d of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term third-party TUAs, under which SPLNG’s customers are required to pay fixed monthly fees, whether or not they use the LNG terminal. Each of Total Gas & Power North America, Inc. (“Total”) and 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 SPLNG aggregating approximately $125 million annually for 20 years that commenced in 2009. Total S.A. has guaranteed Total’s obligations under its TUA up to $2.5 billion, subject to certain exceptions, and Chevron Corporation has guaranteed Chevron’s obligations under its TUA up to 80% of the fees payable by Chevron.

The remaining approximately 2.0 Bcf/d of capacity has been reserved under a TUA by SPL. SPL is obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million annually, continuing until at least 20 years after SPL delivers its first commercial cargo at the Liquefaction Project.

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

Liquefaction Facilities

The Liquefaction Project is being developed and constructed at the Sabine Pass LNG terminal adjacent to the existing regasification facilities. We commenced construction of Trains 1 and 2 and the related new facilities needed to treat, liquefy, store and export natural gas in August 2012. Construction of Trains 3 and 4 and the related facilities commenced in May 2013. In April 2015, we received authorization from the FERC to site, construct and operate Trains 5 and 6. In June 2015, we commenced construction of Train 5 and the related facilities.

The DOE has authorized the export of up to a combined total of the equivalent of 16 mtpa (approximately 803 Bcf/yr) of domestically produced LNG by vessel from the Sabine Pass LNG terminal to FTA countries for a 30-year term and to non-FTA countries for a 20-year term. The DOE further issued an order authorizing SPL to export up to the equivalent of approximately 203 Bcf/yr of domestically produced LNG from the Sabine Pass LNG terminal to FTA countries for a 25-year period. SPL’s application for authorization to export that same 203 Bcf/yr of domestically produced LNG from the Sabine Pass LNG terminal to non-FTA countries is currently pending at the DOE. Additionally, the DOE further issued orders authorizing SPL to export up to a combined total of 503.3 Bcf/yr of domestically produced LNG from the Sabine Pass LNG terminal to FTA countries and non-FTA countries for a 20-year term. The Sierra Club has requested a rehearing of the non-FTA order pertaining to the 503.3 Bcf/yr, and the DOE has not yet ruled on this request. In each case, the terms of these authorizations begin on the earlier of the date of first export thereunder or the date specified in the particular order, which ranges from 5 to 10 years from the date the order was issued.

As of June 30, 2015, the overall project completion percentages for Trains 1 and 2 and Trains 3 and 4 of the Liquefaction Project were approximately 92.2% and 69.2%, respectively, which are ahead of the contractual schedule. Based on our current construction schedule, we anticipate that Train 1 will produce LNG as early as late 2015, and Trains 2 through 5 are expected to commence operations on a staggered basis thereafter.

Customers

SPL has entered into six fixed price, 20-year SPAs with third parties that in the aggregate equate to approximately 19.75 mtpa of LNG that commence with the date of first commercial delivery for Trains 1 through 5, which are fully permitted. Under these SPAs, the customers will purchase LNG from SPL for a price consisting of a fixed fee plus 115% of Henry Hub per MMBtu of LNG. In certain circumstances, the customers may elect to cancel or suspend deliveries of LNG cargoes, in which case the customers would still be required to pay the fixed fee with respect to cargoes that are not delivered. A portion of the fixed fee will be subject to annual adjustment for inflation. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA commences upon the start of operations of the specified Train.

In aggregate, the fixed fee portion to be paid by these customers is approximately $2.9 billion annually for Trains 1 through 5, with the applicable fixed fees starting from the commencement of commercial operations of the applicable Train. These fixed fees equal approximately $411 million, $564 million, $650 million, $648 million and $588 million for each of Trains 1 through 5, respectively.

In addition, Cheniere Marketing has entered into an amended and restated SPA with SPL to purchase, at Cheniere Marketing’s option, any LNG produced by SPL in excess of that required for other customers at a price of 115% of Henry Hub plus $3.00 per MMBtu of LNG.

Natural Gas Transportation and Supply

For SPL’s natural gas feedstock transportation requirements, it has entered into transportation precedent agreements to secure firm pipeline transportation capacity with CTPL and third-party pipeline companies. SPL has also entered into enabling agreements and long-term natural gas purchase agreements with third parties in order to secure natural gas feedstock for the Liquefaction Project. As of June 30, 2015, SPL has secured up to approximately 2,162.8 million MMBtu of natural gas feedstock through long-term natural gas purchase agreements.

Construction

SPL entered into lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of Trains 1 through 5, under which Bechtel charges a lump sum for all work performed and generally bears project cost risk unless certain specified events occur, in which case Bechtel may cause SPL to enter into a change order, or SPL agrees with Bechtel to a change order.

The total contract prices of the EPC contract for Trains 1 and 2 (“EPC Contract (Trains 1 and 2)”), EPC contract for Trains 3 and 4 (“EPC Contract (Trains 3 and 4)”) and EPC Contract (Train 5) are approximately $4.1 billion, $3.8 billion and $3.0 billion, respectively, reflecting amounts incurred under change orders through June 30, 2015. Total expected capital costs for Trains 1 through 5 are estimated to be between $12.5 billion and $13.5 billion before financing costs and between $17.0 billion and $18.0 billion after financing costs, including, in each case, estimated owner’s costs and contingencies.

Pipeline Facilities

CTPL owns the Creole Trail Pipeline, a 94-mile pipeline interconnecting the Sabine Pass LNG terminal with a number of large interstate pipelines. In December 2013, CTPL began construction of certain modifications to allow the Creole Trail Pipeline to be able to transport natural gas to the Sabine Pass LNG terminal, which were completed in April 2015.

Final Investment Decision on Train 6

We will contemplate making a final investment decision to commence construction of Train 6 of the Liquefaction Project based upon, among other things, entering into an EPC contract, entering into acceptable commercial arrangements and obtaining adequate financing to construct the Train.

Capital Resources

We currently expect that SPL’s capital resources requirements with respect to Trains 1 through 5 of the Liquefaction Project will be financed through one or more of the following: borrowings, equity contributions from us and cash flows under the SPAs.

We believe that with the net proceeds of borrowings, unfunded commitments under the 2015 SPL Credit Facilities and cash flows from operations, we will have adequate financial resources available to complete Trains 1 through 5 of the Liquefaction Project and to meet our currently anticipated capital, operating and debt service requirements. We currently project that we will generate cash flow from the Liquefaction Project by early 2016, when Train 1 of the Liquefaction Project is anticipated to achieve initial LNG production.

Senior Secured Notes

As of June 30, 2015, our subsidiaries had seven series of senior secured notes outstanding (collectively, the “Senior Notes”):


•	$1.7 billion of 7.50% Senior Secured Notes due 2016 issued by SPLNG (the “2016 SPLNG Senior Notes”);


•	$0.4 billion of 6.50% Senior Secured Notes due 2020 issued by SPLNG (the “2020 SPLNG Senior Notes” and collectively with the 2016 SPLNG Senior Notes, the “SPLNG Senior Notes”);


•	$2.0 billion of 5.625% Senior Secured Notes due 2021 issued by SPL (the “2021 SPL Senior Notes”);


•	$1.0 billion of 6.25% Senior Secured Notes due 2022 issued by SPL (the “2022 SPL Senior Notes”);


•	$1.5 billion of 5.625% Senior Secured Notes due 2023 issued by SPL (the “2023 SPL Senior Notes”);


•	$2.0 billion of 5.75% Senior Secured Notes due 2024 issued by SPL (the “2024 SPL Senior Notes” and collectively with the 2021 SPL Senior Notes, the 2022 SPL Senior Notes, the 2023 SPL Senior Notes and the 2025 SPL Senior Notes, the “SPL Senior Notes”); and


•	$2.0 billion of the 2025 SPL Senior Notes.

Interest on the Senior Notes is payable semi-annually in arrears. Subject to permitted liens, the SPLNG Senior Notes are secured on a pari passu first-priority basis by a security interest in all of SPLNG’s equity interests and substantially all of SPLNG’s operating assets. The SPL Senior Notes are secured on a first-priority basis by a security interest in all of the membership interests in SPL and substantially all of SPL’s assets.

SPLNG may redeem all or part of its 2016 SPLNG Senior Notes at any time at a redemption price equal to 100% of the principal plus any accrued and unpaid interest plus the greater of:


•	1.0% of the principal amount of the 2016 SPLNG Senior Notes; or

•

the excess of: (1) the present value at such redemption date of (a) the redemption price of the 2016 SPLNG Senior Notes plus (b) all required interest payments due on the 2016 SPLNG 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 (2) the principal amount of the 2016 SPLNG Senior Notes, if greater.

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

At any time prior to three months before the respective dates of maturity for each series of the SPL Senior Notes, SPL may redeem all or part of such series of the SPL Senior Notes at a redemption price equal to the “make-whole” price set forth in the common indenture governing the SPL Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. SPL may also, at any time within three months of the respective maturity dates for each series of the SPL Senior Notes, redeem all or part of such series of the SPL Senior Notes at a redemption price equal to 100% of the principal amount of such series of the SPL Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.

Under the indentures governing the SPLNG Senior Notes (the “SPLNG Indentures”), except for permitted tax distributions, SPLNG may not make distributions until, among other requirements, deposits are made into debt service reserve accounts and a fixed charge coverage ratio test of 2:1 is satisfied. Under the common indenture governing the SPL Senior Notes, SPL may not make any distributions until, among other requirements, substantial completion of Trains 1 and 2 has occurred, deposits are made into debt service reserve accounts and a debt service coverage ratio test of 1.25:1.00 is satisfied. During the six months ended June 30, 2015 and 2014, SPLNG made distributions of $199.6 million and $173.0 million, respectively, after satisfying all the applicable conditions in the SPLNG Indentures.

The SPL Senior Notes are governed by a common indenture with restrictive covenants. SPL may incur additional indebtedness in the future, including by issuing additional notes, and such indebtedness could be at higher interest rates and have different maturity dates and more restrictive covenants than the current outstanding indebtedness of SPL, including the SPL Senior Notes, the 2015 SPL Credit Facilities and a $325.0 million senior letter of credit and reimbursement agreement (the “SPL LC Agreement”) described below.

2015 SPL Credit Facilities

Loans under the 2015 SPL Credit Facilities accrue interest at a variable rate per annum equal to, at SPL’s election, LIBOR or the base rate plus the applicable margin. The applicable margin for LIBOR loans ranges from 1.30% to 1.75%, depending on the applicable 2015 SPL Credit Facility, and the applicable margin for base rate loans is 1.75%. 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 quarter. In addition, SPL is required to pay insurance/guarantee premiums of 0.45% per annum on any drawn amounts under the covered tranches of the 2015 SPL Credit Facilities. The 2015 SPL Credit Facilities also require SPL to pay a quarterly commitment fee calculated at either: (1) a rate per annum equal to 40% of the applicable margin, multiplied by the average daily amount of the undrawn commitment, or (2) 0.70% of the undrawn commitment, depending on the applicable 2015 SPL Credit Facility. The principal of the loans made under the 2015 SPL Credit Facilities must be repaid in quarterly installments, commencing with the earlier of June 30, 2020 and the last day of the first full calendar quarter after the completion date of Trains 1 through 5 of the Liquefaction Project. Scheduled repayments are based upon an 18-year amortization profile, with the remaining balance due upon the maturity of the 2015 SPL Credit Facilities

The obligations of SPL under the 2015 SPL Credit Facilities are secured by substantially all of the assets of SPL as well as all of the membership interests in SPL on a pari passu basis with the SPL Senior Notes.

2013 SPL Credit Facilities

In May 2013, SPL entered into four credit facilities aggregating $5.9 billion (collectively, the “2013 SPL Credit Facilities”) to fund a portion of the costs of developing, constructing and placing into operation Trains 1 through 4 of the Liquefaction Project. In June 2015, the 2013 SPL Credit Facilities were replaced with the 2015 SPL Credit Facilities.

CTPL Term Loan

CTPL has a $400.0 million term loan facility (“CTPL Term Loan”), which was used to fund modifications to the Creole Trail Pipeline and for general business purposes. The CTPL Term Loan matures in 2017 when the full amount of the outstanding principal obligations must be repaid. CTPL’s loan may be repaid, in whole or in part, at any time without premium or penalty. As of June 30, 2015, CTPL had borrowed the full amount of $400.0 million available under the CTPL Term Loan. Borrowings under the CTPL Term Loan accrue interest at a variable rate per annum equal to, at CTPL’s election, LIBOR or the base rate, plus the applicable margin. The applicable margin for LIBOR loans is 3.25%. Interest on LIBOR loans is due and payable at the end of each LIBOR period.

SPL LC Agreement

In April 2014, SPL entered into the SPL LC Agreement that it uses for the issuance of letters of credit for certain working capital requirements related to the Liquefaction Project. SPL pays (1) a commitment fee in an amount equal to an annual rate of 0.75% of an amount equal to the unissued portion of letters of credit available pursuant to the SPL LC Agreement and (2) a letter of credit fee equal to an annual rate of 2.5% of the undrawn portion of all letters of credit issued under the SPL LC Agreement. If draws are made upon any letters of credit issued under the SPL LC Agreement, the amount of the draw will be deemed a loan issued to SPL. SPL is required to pay the full amount of this loan on or prior to the business day immediately succeeding the deemed issuance of the loan. These loans accrue interest at a rate of 2.0% plus the base rate as defined in the SPL LC Agreement. As of June 30, 2015, SPL had issued letters of credit in an aggregate amount of $72.9 million and no draws had been made upon any letters of credit issued under the SPL LC Agreement.

Sources and Uses of Cash

The following table summarizes (in thousands) the sources and uses of our cash and cash equivalents for the six months ended June 30, 2015 and 2014. The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussion of these items follows the table.



	Six Months Ended June 30,
	2015			2014
Sources of cash and cash equivalents
Proceeds from issuances of long-term debt	$	2,000,000		$	2,584,500
Use of restricted cash for the acquisition of property, plant and equipment	1,471,632			1,302,039
Operating cash flow	2,580			6,934
Other	—			2,495
Total sources of cash and cash equivalents	3,474,212			3,895,968

Uses of cash and cash equivalents
Investment in restricted cash	(1,854,002		)	(2,321,253		)
Property, plant and equipment, net	(1,427,603		)	(1,305,506		)
Debt issuance and deferred financing costs	(145,998		)	(85,197		)
Repayments of long-term debt	—			(177,000		)
Distributions to owners	(49,508		)	(49,508		)
Other	(51,017		)	(1,049		)
Total uses of cash and cash equivalents	(3,528,128		)	(3,939,513		)

Net decrease in cash and cash equivalents	(53,916		)	(43,545		)
Cash and cash equivalents—beginning of period	248,830			351,032
Cash and cash equivalents—end of period	$	194,914		$	307,487

Proceeds from Issuances of Long-Term Debt, Debt Issuance and Deferred Financing Costs and Repayments of Long-Term Debt

In March 2015, SPL issued an aggregate principal amount of $2.0 billion of the 2025 SPL Senior Notes. In June 2015, SPL entered into the 2015 SPL Credit Facilities aggregating $4.6 billion, which terminated and replaced the 2013 SPL Credit Facilities. Debt issuance and deferred financing costs in the six months ended June 30, 2015 primarily relate to up-front fees paid upon the closing of these transactions. In May 2014, SPL issued the 2024 SPL Senior Notes and additional 5.625% Senior Secured Notes due 2023 in an aggregate principal amount of $0.5 billion (the “Additional 2023 SPL Senior Notes”) for total net proceeds of approximately $2.5 billion. Debt issuance and deferred financing costs in the six months ended June 30, 2014 primarily relate to up-front fees paid upon the closing of this offering in May 2014.

During the six months ended June 30, 2014, SPL repaid its $177.0 million of borrowings under the 2013 SPL Credit Facilities upon the issuance of the Additional 2023 SPL Senior Notes and the 2024 SPL Senior Notes.

Use of Restricted Cash for the Acquisition of Property, Plant and Equipment and Property, Plant and Equipment, net

During the six months ended June 30, 2015 and 2014, we used $1,471.6 million and $1,302.0 million, respectively, of restricted cash for investing activities to fund $1,427.6 million and a portion of the $1,305.5 million, respectively, of construction costs for Trains 1 through 5 of the Liquefaction Project. The costs associated with the construction of Trains 1 through 5 of the Liquefaction Project are capitalized as construction-in-process.

Investment in Restricted Cash

In the six months ended June 30, 2015, we invested $1,854.0 million in restricted cash primarily related to the net proceeds from the 2025 SPL Senior Notes. In the six months ended June 30, 2014, we invested $2,321.3 million in restricted cash primarily related to the net proceeds from the 2024 SPL Senior Notes and the Additional 2023 SPL Senior Notes issued in May 2014.

Operating Cash Flow

Cash used in operations was $2.6 million and $6.9 million in the six months ended June 30, 2015 and 2014, respectively. The decrease in operating cash outflows primarily related to the timing of amounts paid to third parties for the construction of the Liquefaction Project.

Other

Other cash outflows increased from $1.0 million during the six months ended June 30, 2014 to $51.0 million during the six months ended June 30, 2015, primarily for payments made to a municipal water district for water system enhancements that will increase potable water supply to our Sabine Pass LNG terminal.

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 six months ended June 30, 2015 and 2014:



						Total Distribution (in thousands)
Date Paid	Period Covered by Distribution	Distribution Per Common Unit		Distribution Per Subordinated Unit		Common Units		Class B Units		Subordinated Units		General Partner Units
May 15, 2015	January 1 - March 31, 2015	$	0.425	$	—	$	24,259	$	—	$	—	$	495
February 13, 2015	October 1 - December 31, 2014	0.425		—		24,259		—		—		495

May 15, 2014	January 1 - March 31, 2014	$	0.425	$	—	$	24,259	$	—	$	—	$	495
February 14, 2014	October 1 - December 31, 2013	0.425		—		24,259		—		—		495

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

be generated through new business development or fees received from Cheniere Marketing under an amended and restated variable capacity rights agreement pursuant to which Cheniere Marketing is obligated to pay Cheniere Investments 80% of the expected gross margin of each cargo of LNG that Cheniere Marketing arranges for delivery to the Sabine Pass LNG terminal. The ending of the subordination period and conversion of the subordinated units into common units will depend upon future business development.

In 2012 and 2013, we issued Class B units, a new class of equity interests representing limited partner interests in us, in connection with the development of the Liquefaction Project. The Class B units are not entitled to cash distributions, except in the event of our liquidation or a merger, consolidation or other combination of us with another person or the sale of all or substantially all of our assets. The Class B units are subject to conversion, mandatorily or at the option of the holders of the Class B units under specified circumstances, into a number of common units based on the then-applicable conversion value of the Class B units. On a quarterly basis beginning on the initial purchase of the Class B units, and ending on the conversion date of the Class B units, the conversion value of the Class B units increases at a compounded rate of 3.5% per quarter, subject to an additional upward adjustment for certain equity and debt financings. The holders of Class B units have a preference over the holders of the subordinated units in the event of our liquidation or a merger, consolidation or other combination of us with another person or the sale of all or substantially all of our assets.

On July 24, 2015, we declared a $0.425 distribution per common unit and the related distribution to our general partner to be paid on August 14, 2015 to owners of record as of August 3, 2015 for the period from April 1, 2015 to June 30, 2015.

Results of Operations

Three Months Ended June 30, 2015 vs. Three Months Ended June 30, 2014

Our consolidated net loss decreased $166.2 million, from $226.2 million of consolidated net loss in the three months ended June 30, 2014, to $60.0 million of consolidated net loss in the three months ended June 30, 2015. The decrease in consolidated net loss was primarily a result of decreased loss on early extinguishment of debt, increased derivative gain (loss), net and decreased operating and maintenance expense, partially offset by increased general and administrative expense—affiliate and increased interest expense, net.

Loss on early extinguishment of debt decreased $107.1 million in the three months ended June 30, 2015, as compared to the three months ended June 30, 2014, due to the $114.3 million write-off of debt issuance costs in connection with the early extinguishment of $2.1 billion of commitments under the 2013 SPL Credit Facilities in May 2014, whereas the termination and replacement of the 2013 SPL Credit Facilities with the 2015 SPL Credit Facilities in June 2015 resulted in a write-off of debt issuance costs and deferred commitment fees of $7.3 million. Derivative gain (loss), net increased $61.5 million from a loss of $60.2 million in the three months ended June 30, 2014 to a gain of $1.2 million in the three months ended June 30, 2015, primarily due to a decrease in long-term LIBOR during the three months ended June 30, 2014 and the loss recognized in May 2014 upon the termination of interest rate swaps associated with approximately $2.1 billion of commitments that were terminated under the 2013 SPL Credit Facilities. Operating and maintenance expense decreased $15.1 million in the three months ended June 30, 2015, as compared to the three months ended June 30, 2014, primarily as a result of the expense incurred during the three months ended June 30, 2014 to purchase LNG to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal, which we did not incur during the three months ended June 30, 2015.

General and administrative expense—affiliate increased $10.5 million in the three months ended June 30, 2015, as compared to the three months ended June 30, 2014, primarily as a result of an increase in management fees incurred pursuant to management services agreements, which are based on capital expenditures incurred during the period. Interest expense, net increased $6.4 million in the three months ended June 30, 2015, as compared to the three months ended June 30, 2014, due to an increase in our indebtedness outstanding. For the three months ended June 30, 2015 and 2014, we incurred $174.8 million and $140.4 million of total interest cost, respectively, of which we capitalized and deferred $124.7 million and $96.6 million, respectively.

Six Months Ended June 30, 2015 vs. Six Months Ended June 30, 2014

Our consolidated net loss decreased $57.2 million, from $296.0 million of consolidated net loss in the six months ended June 30, 2014, to $238.7 million of consolidated net loss in the six months ended June 30, 2015. The decrease in consolidated net loss was primarily a result of decreased derivative loss, net and decreased loss on early extinguishment of debt, partially offset by increased interest expense, net and increased operating and maintenance expense.

Derivative loss, net decreased $59.7 million in the six months ended June 30, 2015, as compared to the six months ended June 30, 2014. The higher derivative loss recognized during the six months ended June 30, 2014 was attributable to a decrease in long-term LIBOR during that period, as compared to minimal effect of the movement in long-term LIBOR on derivative loss for the six months ended June 30, 2015 as a result of a lower notional amount of interest rate derivatives. The $35.2 million derivative loss recognized during the six months ended June 30, 2015 was primarily attributable to the loss recognized in March 2015 upon the termination of interest rate swaps associated with approximately $1.8 billion of commitments that were terminated under the 2013 SPL Credit Facilities. Loss on early extinguishment of debt decreased $18.1 million in the six months ended June 30, 2015, as compared to the six months ended June 30, 2014, due to $96.3 million in write-off of debt issuance costs and deferred commitment fees in connection with the termination of approximately $1.8 billion of commitments under the 2013 SPL Credit Facilities in March 2015 and the replacement of the 2013 SPL Credit Facilities with the 2015 SPL Credit Facilities in June 2015, as compared to $114.3 million in write-off of debt issuance costs in connection with the early extinguishment of $2.1 billion of commitments under the 2013 SPL Credit Facilities in May 2014.

Interest expense, net increased $8.9 million in the six months ended June 30, 2015, as compared to the six months ended June 30, 2014, due to an increase in our outstanding indebtedness. For the six months ended June 30, 2015 and 2014, we incurred $334.9 million and $269.0 million of total interest cost, respectively, of which we capitalized and deferred $241.9 million and $184.9 million, respectively. Operating and maintenance expense increased $7.6 million in the six months ended June 30, 2015, as compared to the six months ended June 30, 2014, primarily as a result of the expense incurred to purchase LNG to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal and increased costs to manage the operation and maintenance of the Sabine Pass LNG terminal.

Off-Balance Sheet Arrangements

As of June 30, 2015, we had no “off-balance sheet arrangements” that may have a current or future material effect on our consolidated financial position or results of operations.

Summary of Critical Accounting Estimates

The preparation of our Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. There have been no significant changes to our critical accounting estimates from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2014.

Recent Accounting Standards

For descriptions of recently issued accounting standards, see Part 1. Financial Information, Item 1. Notes to Consolidated Financial Statements, Note 11—Recent Accounting Standards.

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 commodity derivatives to hedge the exposure to price risk attributable to future sales of our LNG inventory (“Natural Gas 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 Natural Gas Derivatives. The VaR is calculated using the Monte Carlo simulation method. The VaR related to our Natural Gas Derivatives was $0.2 million as of June 30, 2015.

We have entered into commodity derivatives consisting of natural gas purchase agreements to secure natural gas feedstock for the Liquefaction Project (“Liquefaction Supply Derivatives”). In order to test the sensitivity of the fair value of the Liquefaction

Supply Derivatives to changes in underlying commodity prices, management modeled a 10% change in the basis price for natural gas for each delivery location. As of June 30, 2015, we estimated the fair value of the Liquefaction Supply Derivatives to be $0.4 million. Based on actual derivative contractual volumes, a 10% increase or decrease in underlying basis price would have resulted in a change in the fair value of the Liquefaction Supply Derivatives of $0.4 million as of June 30, 2015.

Interest Rate Risk

We have entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the 2015 SPL Credit Facilities (“Interest Rate Derivatives”). In order to test the sensitivity of the fair value of the Interest Rate Derivatives to changes in interest rates, management modeled a 10% change in the forward 1-month LIBOR curve across the full 7-year term of the Interest Rate Derivatives. This 10% change in interest rates would have resulted in a change in the fair value of our Interest Rate Derivatives of $3.5 million as of June 30, 2015.

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 Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. As of the end of the period covered by this report, we evaluated, under the supervision and with the participation of our general partner’s management, including our general partner’s Chief Executive Officer and Chief Financial Officer, the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act. Based on that evaluation, our general partner’s Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective.

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

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 June 30, 2015, there were no pending legal matters that could reasonably be expected to have a material impact on our consolidated results of operations, financial position or cash flows.

ITEM 1A. RISK FACTORS

There have been no material changes from the risk factors disclosed in our Annual Report on Form 10-K for the year ended December 31, 2014.

ITEM 5. OTHER INFORMATION

Compliance Disclosure

Pursuant to Section 13(r) of the Exchange Act, if during the quarter ended June 30, 2015, we or any of our affiliates had engaged in certain transactions with Iran or with persons or entities designated under certain executive orders, we would be required to disclose information regarding such transactions in our Quarterly Report on Form 10-Q as required under Section 219 of the Iran Threat Reduction and Syria Human Rights Act of 2012 (“ITRA”). During the quarter ended June 30, 2015, we did not engage in any transactions with Iran or with persons or entities related to Iran.

ITEM 6. EXHIBITS



Exhibit No.		Description
10.1		Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 3 Liquefaction Facility, dated May 4, 2015, by and between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc. (Portions of this exhibit have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K/A (SEC File No. 001-33366), filed on July 1, 2015)
10.2		Change order 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.: the Change Order CO-00041 Additional Building Utility Tie-in Packages and Fire and Gas Modifications, dated April 9, 2015 (Incorporated by reference to Exhibit 10.2 to Sabine Pass Liquefaction, LLC’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on July 30, 2015)
10.3		Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 2 Liquefaction Facility, dated as of December 20, 2012, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00018 Permanent Restroom Trailers and Installation of Tie-In for GTG Fuel Gas Interconnect, dated May 21, 2015 (Incorporated by reference to Exhibit 10.3 to Sabine Pass Liquefaction, LLC’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on July 30, 2015)
10.4		Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 3 Liquefaction Facility, dated as of May 4, 2015, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00001 Currency and Fuel Provisional Sum Adjustment, dated June 25, 2015 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment) (Incorporated by reference to Exhibit 10.4 to Sabine Pass Liquefaction, LLC’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on July 30, 2015)
10.5		Second Amended and Restated Credit Agreement (Term Loan A), dated as of June 30, 2015, among Sabine Pass Liquefaction, LLC, as Borrower, Société Générale, as the Commercial Banks Facility Agent and the Common Security Trustee, and the lenders from time to time party thereto (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-33366), filed on July 1, 2015)
10.6		Second Amended and Restated Common Terms Agreement, dated as of June 30, 2015, among Sabine Pass Liquefaction, LLC, as Borrower, the representatives and agents from time to time parties thereto, and Société Générale, as the Common Security Trustee and Intercreditor Agent (Incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-33366), filed on July 1, 2015)
10.7		KEXIM Direct Facility Agreement, dated as of June 30, 2015, among Sabine Pass Liquefaction, LLC, as Borrower, The Export-Import Bank of Korea, a governmental financial institution of the Republic of Korea (“KEXIM”), as the KEXIM Direct Facility Lender, Shinhan Bank New York Branch, as the KEXIM Facility Agent, and Société Générale, as the Common Security Trustee (Incorporated by reference to Exhibit 10.3 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-33366), filed on July 1, 2015)
10.8		KEXIM Covered Facility Agreement, dated as of June 30, 2015, among Sabine Pass Liquefaction, LLC, as Borrower, Shinhan Bank New York Branch, as the KEXIM Facility Agent, Société Générale, as the Common Security Trustee, KEXIM and the lenders from time to time party thereto (Incorporated by reference to Exhibit 10.4 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-33366), filed on July 1, 2015)
10.9		Amended and Restated KSURE Covered Facility Agreement, dated as of June 30, 2015, among Sabine Pass Liquefaction, LLC, as Borrower, The Korea Development Bank, New York Branch, as the KSURE Covered Facility Agent, Société Générale, as the Common Security Trustee, and the lenders from time to time party thereto (Incorporated by reference to Exhibit 10.5 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-33366), filed on July 1, 2015)
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



Exhibit No.		Description
101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document



*	Filed herewith.
**	Furnished herewith.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



		CHENIERE ENERGY PARTNERS, L.P.
		By:	Cheniere Energy Partners GP, LLC,
			its general partner

Date:	July 30, 2015	By:	/s/ Michael J. Wortley
			Michael J. Wortley
			Senior Vice President and Chief Financial Officer
			(on behalf of the registrant and as principal financial officer)

Date:	July 30, 2015	By:	/s/ Leonard Travis
			Leonard Travis
			Chief Accounting Officer
			(on behalf of the registrant and as principal accounting officer)