CQP 2015 Form 10Q 1st 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 March 31, 2015


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

For the transition period from to

Commission File No. 001-33366

Cheniere Energy Partners, L.P.

(Exact name of registrant as specified in its charter)



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

700 Milam Street, Suite 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 April 17, 2015, the issuer had 57,093,848 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	2
	Consolidated Balance Sheets	2
	Consolidated Statements of Operations	3
	Consolidated Statement of Partners’ Equity	4
	Consolidated Statements of Cash Flows	5
	Notes to Consolidated Financial Statements	6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	31

Item 4.	Controls and Procedures	32

Part II. Other Information
Item 1.	Legal Proceedings	33

Item 1A.	Risk Factors	33

Item 5.	Other Information	33

Item 6.	Exhibits	34

	Signatures	35

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
EPC		engineering, procurement and construction
FERC		Federal Energy Regulatory Commission
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 metric tonnes per annum
SEC		Securities and Exchange Commission
SPA		LNG sale and purchase agreement
Train		a compressor train used in the industrial process to convert natural gas into LNG
TUA		terminal use agreement

Company Abbreviations



Cheniere		Cheniere Energy, Inc.
Cheniere Holdings		Cheniere Energy Partners LP Holdings, LLC
Cheniere Investments		Cheniere Energy Investments, LLC
Cheniere Terminals		Cheniere LNG Terminals, LLC
CTPL		Cheniere Creole Trail Pipeline, L.P.
Sabine Pass LNG		Sabine Pass LNG, L.P.
SPL		Sabine Pass Liquefaction, LLC

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 Sabine Pass LNG, 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)



	March 31,			December 31,
	2015			2014
ASSETS	(unaudited)
Current assets
Cash and cash equivalents	$	171,464		$	248,830
Restricted cash and cash equivalents	261,371			195,702
Accounts receivable	26,197			310
Advances to affiliate	21,804			27,323
LNG inventory	16,281			4,293
Prepaid expenses and other	10,120			6,411
Other—affiliate	5,195			3,651
Total current assets	512,432			486,520

Non-current restricted cash and cash equivalents	1,849,456			544,465
Property, plant and equipment, net	9,534,951			8,978,356
Debt issuance costs, net	214,450			241,909
Non-current derivative assets	472			11,744
Other non-current assets	137,192			124,521
Total assets	$	12,248,953		$	10,387,515

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	8,379		$	8,598
Accrued liabilities	204,461			136,596
Due to affiliates	17,527			19,660
Deferred revenue	26,653			26,655
Derivative liabilities	7,252			23,247
Total current liabilities	264,272			214,756

Long-term debt, net	10,992,229			8,991,333
Non-current deferred revenue	12,500			13,500
Other non-current liabilities	6,943			2,452
Other non-current liabilities—affiliate	45,710			34,745

Commitments and contingencies

Partners’ equity
Common unitholders’ interest (57.1 million units issued and outstanding at March 31, 2015 and December 31, 2014)	419,407			495,597
Class B unitholders’ interest (145.3 million units issued and outstanding at March 31, 2015 and December 31, 2014)	(38,216		)	(38,216		)
Subordinated unitholders’ interest (135.4 million units issued and outstanding at March 31, 2015 and December 31, 2014)	525,243			648,414
General partner’s interest (2% interest with 6.9 million units issued and outstanding at March 31, 2015 and December 31, 2014)	20,865			24,934
Total partners’ equity	927,299			1,130,729
Total liabilities and partners’ equity	$	12,248,953		$	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
	March 31,
	2015			2014
Revenues
Revenues	$	66,718		$	66,449
Revenues—affiliate	812			772
Total revenues	67,530			67,221

Operating costs and expenses
Operating and maintenance expense	31,987			9,219
Operating and maintenance expense—affiliate	4,773			4,431
Depreciation expense	14,879			14,318
Development expense	1,151			3,496
Development expense—affiliate	204			152
General and administrative expense	3,515			3,366
General and administrative expense—affiliate	21,597			27,153
Total operating costs and expenses	78,106			62,135

Income (loss) from operations	(10,576		)	5,086

Other income (expense)
Interest expense, net	(42,845		)	(40,270		)
Loss on early extinguishment of debt	(88,992		)	—
Derivative loss, net	(36,384		)	(34,681		)
Other income	121			132
Total other expense	(168,100		)	(74,819		)

Net loss	$	(178,676	)	$	(69,733	)

Basic and diluted net loss per common unit	$	(0.61	)	$	(0.06	)

Weighted average number of common units outstanding used for basic and diluted net loss per common unit calculation	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	—	(51,931		)	—	—			—	(123,171		)	—	(3,574		)	(178,676		)
Distributions	—	(24,259		)	—	—			—	—			—	(495		)	(24,754		)
Balance at March 31, 2015	57,080	$	419,407		145,333	$	(38,216	)	135,384	$	525,243		6,894	$	20,865		$	927,299

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)



	Three Months Ended
	March 31,
	2015			2014
Cash flows from operating activities
Net loss	$	(178,676	)	$	(69,733	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation expense	14,879			14,318
Use of (investment in) restricted cash and cash equivalents for certain operating activities	6,244			(22,873		)
Non-cash LNG inventory write-downs	17,502			—
Amortization of debt issuance costs and discount	2,504			2,217
Total losses on derivatives, net	36,384			34,701
Net cash used for settlement of derivative instruments	(37,015		)	(1,706		)
Loss on early extinguishment of debt	88,992			—
Other	—			2
Changes in operating assets and liabilities:
Accounts receivable	(25,928		)	148
Accounts receivable—affiliate	(1,544		)	593
Accounts payable and accrued liabilities	47,945			39,263
Due to affiliates	(3,971		)	3,669
Deferred revenue	(1,003		)	(871		)
Advances to affiliate	5,519			1,880
LNG inventory	(29,491		)	2,902
Other, net	(5,727		)	(4,399		)
Other, net—affiliate	10,962			(567		)
Net cash used in operating activities	(52,424		)	(456		)

Cash flows from investing activities
Property, plant and equipment, net	(542,114		)	(751,808		)
Use of restricted cash and cash equivalents for the acquisition of property, plant and equipment	572,434			761,378
Other	(30,508		)	(10,050		)
Net cash used in investing activities	(188		)	(480		)

Cash flows from financing activities
Proceeds from issuances of long-term debt	2,000,000			—
Use of (investment in) restricted cash and cash equivalents	(1,949,338		)	13,957
Debt issuance and deferred financing costs	(50,662		)	(13,957		)
Distributions to owners	(24,754		)	(24,754		)
Net cash used in financing activities	(24,754		)	(24,754		)

Net decrease in cash and cash equivalents	(77,366		)	(25,690		)
Cash and cash equivalents—beginning of period	248,830			351,032
Cash and cash equivalents—end of period	$	171,464		$	325,342

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 months ended March 31, 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 common units have the right to receive initial quarterly distributions of $0.425 plus any arrearages thereon, before any distribution is made to the holders of the subordinated units. The subordinated units will receive distributions only to the extent we have available cash above the initial quarterly distribution requirement for our common unitholders and general partner and certain reserves. 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% up 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 (collectively, the “Creole Trail Pipeline Business”). 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 1.46 and 1.44, respectively, as of March 31, 2015. We expect the Class B

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

units to mandatorily convert into common units within 90 days of the substantial completion date of Train 3 of the Liquefaction Project, which we currently expect to occur before March 31, 2017. If the Class B units are not mandatorily converted by July 2019, the holders of the Class B units have the option to convert the Class B units into common units at that time.

NOTE 3—RESTRICTED CASH AND CASH EQUIVALENTS

Restricted cash and cash equivalents 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 and cash equivalents includes the following:

Sabine Pass LNG Senior Notes Debt Service Reserve

Sabine Pass LNG, 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 Sabine Pass LNG Senior Notes”) and $420.0 million of 6.50% Senior Secured Notes due 2020 (the “2020 Sabine Pass LNG Senior Notes”). Collectively, the 2016 Sabine Pass LNG Senior Notes and the 2020 Sabine Pass LNG Senior Notes are referred to as the “Sabine Pass LNG Senior Notes.” Under the indentures governing the Sabine Pass LNG Senior Notes (the “Sabine Pass LNG Indentures”), except for permitted tax distributions, Sabine Pass LNG may not make distributions until certain conditions are satisfied, including: (i) 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 (ii) there must be on deposit in a permanent debt service reserve fund an amount equal to one semi-annual interest payment. Distributions are permitted only after satisfying the foregoing funding requirements, a fixed charge coverage ratio test of 2:1 and other conditions specified in the Sabine Pass LNG Indentures.

As of March 31, 2015 and December 31, 2014, we classified $53.0 million and $15.0 million, respectively, as current restricted cash and cash equivalents for the payment of current interest due. As of both March 31, 2015 and December 31, 2014, we classified the permanent debt service reserve fund of $76.1 million as non-current restricted cash and cash equivalents. These cash accounts are controlled by a collateral trustee; therefore, these amounts are shown as restricted cash and cash equivalents on our Consolidated Balance Sheets.

SPL Reserve

During 2013, SPL entered into four credit facilities aggregating $5.9 billion (collectively, the “2013 Liquefaction Credit Facilities”). Under the terms and conditions of the 2013 Liquefaction 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 and cash equivalents 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. During 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”). See Note 7—Long-Term Debt for additional details about our long-term debt.

As of March 31, 2015 and December 31, 2014, we classified $186.3 million and $155.8 million, respectively, as current restricted cash and cash equivalents held by SPL for the payment of current liabilities, including interest payments, related to the Liquefaction Project and $1,767.4 million and $457.1 million, respectively, as non-current restricted cash and cash equivalents 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 “2017 CTPL Term Loan”). As of March 31, 2015 and December 31, 2014, we classified $22.1 million and $24.9 million, respectively, as current restricted cash and cash equivalents held by CTPL for the payment of current liabilities and $6.0 million and $11.3 million, respectively, as non-current restricted cash and cash equivalents 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.

NOTE 4—PROPERTY, PLANT AND EQUIPMENT

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



	March 31,			December 31,
	2015			2014
LNG terminal costs
LNG terminal	$	2,240,715		$	2,240,233
LNG terminal construction-in-process	7,652,783			7,082,732
LNG site and related costs, net	140			141
Accumulated depreciation	(363,398		)	(348,907		)
Total LNG terminal costs, net	9,530,240			8,974,199
Fixed assets
Computer and office equipment	1,105			1,105
Vehicles	1,748			1,507
Machinery and equipment	1,508			1,508
Furniture and fixtures	1,375			1,375
Other	3,199			2,505
Accumulated depreciation	(4,224		)	(3,843		)
Total fixed assets, net	4,711			4,157
Property, plant and equipment, net	$	9,534,951		$	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 variability in expected future cash flows attributable to the future sale of our LNG inventory (“LNG Inventory Derivatives”);


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


•	interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the 2013 Liquefaction Credit Facilities (“Interest Rate Derivatives”).

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.

Additionally, Sabine Pass LNG has entered into forward contracts under an International Swaps and Derivatives Association master agreement with Cheniere Marketing, a wholly owned subsidiary of Cheniere, to hedge the exposure to price risk attributable to future purchases of natural gas to be utilized as fuel to operate the Sabine Pass LNG terminal (“Fuel Derivatives”). Sabine Pass LNG elected to account for these Fuel 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. Sabine Pass LNG had not posted collateral with Cheniere Marketing for such forward contracts as of March 31, 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 March 31, 2015 and December 31, 2014, which are classified as prepaid expenses and other, non-current derivative assets and other current liabilities in our Consolidated Balance Sheets.



	Fair Value Measurements as of
	March 31, 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
LNG Inventory Derivatives asset	$	—	$	372		$	—	$	372		$	—	$	1,216		$	—	$	1,216
Term Gas Supply Derivatives asset	—		—			342		342			—		—			342		342
Interest Rate Derivatives liability	—		(11,692		)	—		(11,692		)	—		(12,036		)	—		(12,036		)

The estimated fair values of our LNG Inventory 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 SPL’s Term Gas 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 SPL’s Term Gas Supply Derivatives is designated as Level 3 within the valuation hierarchy. The curves used to generate the fair value of the Term Gas 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 Term Gas Supply Derivative 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 March 31, 2015 and December 31, 2014, the majority of SPL’s Term Gas 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: (i) the inactive and unobservable market and (ii) 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 Term Gas 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 for the three months ended March 31, 2015 and 2014. As all of SPL’s Term Gas 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 as of March 31, 2015:



	Net Fair Value Asset	Valuation Technique	Significant Unobservable Input	Significant Unobservable Inputs Range
Term Gas Supply Derivatives	$342	Income Approach	Basis Spread	$ (0.350) - $0.046

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 LNG Inventory Derivatives and Term Gas 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:



	March 31, 2015								December 31, 2014
	LNG Inventory Derivatives (1)		Term Gas Supply Derivatives			Total Commodity Derivatives			LNG Inventory Derivatives (1)		Term Gas Supply Derivatives			Total Commodity Derivatives
Balance Sheet Location
Prepaid expenses and other	$	372	$	190		$	562		$	1,216	$	76		$	1,292
Non-current derivative assets	—		472			472			—		586			586
Total derivative assets	372		662			1,034			1,216		662			1,878

Derivative liabilities	—		(133		)	(133		)	—		(53		)	(53		)
Other non-current liabilities	—		(187		)	(187		)	—		(267		)	(267		)
Total derivative liabilities	—		(320		)	(320		)	—		(320		)	(320		)

Net derivative assets	$	372	$	342		$	714		$	1,216	$	342		$	1,558


(1)	Does not include collateral calls of $0.2 million and $1.1 million for such contracts, which are included in prepaid expenses and other current assets in our Consolidated Balance Sheets as of March 31, 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 months ended March 31, 2015 and 2014:



		Three Months Ended March 31,
	Statement of Operations Location	2015		2014
LNG Inventory Derivatives loss	Revenues	$	—	$	(29	)
LNG Inventory Derivatives gain (loss)	Derivative loss, net	754		(435		)
Fuel Derivatives gain (1)	Derivative loss, net	—		242
Term Gas Supply Derivatives gain (loss) (2)	Operating and maintenance expense	—		—

(1)

Fuel Derivatives gain for the three months ended March 31, 2014 represents the changes in the fair value and settlements of certain Fuel Derivatives that were previously not elected to be accounted for under the normal purchase normal sale exception from derivative accounting. During the three months ended March 31, 2015, all settlements of Fuel Derivatives were recorded as operating and maintenance expense, as the normal purchase normal sale exception was elected for all Fuel Derivatives outstanding.


(2)	There were no 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.

LNG Inventory Derivatives

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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Term Gas Supply Derivatives

SPL has entered into index-based physical natural gas supply contracts to secure natural gas feedstock for the Liquefaction Project. The terms of these 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 SPL’s Term Gas Supply Derivatives as either assets or liabilities and measure those instruments at fair value. Changes in the fair value of SPL’s Term Gas Supply Derivatives are reported in earnings. As of March 31, 2015, SPL has secured up to approximately 2,161.9 million MMBtu of natural gas feedstock through long-term natural gas purchase agreements, of which the forward notional natural gas buy position of SPL’s Term Gas Supply Derivatives was approximately 1,249.4 million MMBtu.

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 2013 Liquefaction Credit Facilities. The Interest Rate Derivatives hedge a portion of the expected outstanding borrowings over the term of the 2013 Liquefaction Credit Facilities.

In March 2015, SPL settled a portion of its Interest Rate Derivatives and 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 Liquefaction Credit Facilities as discussed in Note 7—Long-Term Debt.

At March 31, 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

$691.0 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	March 31, 2015			December 31, 2014
Interest Rate Derivatives	Non-current derivative assets (Other non-current liabilities)	$	(4,573	)	$	11,158
Interest Rate Derivatives	Derivative liabilities	(7,119		)	(23,194		)

The following table (in thousands) shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in derivative loss, net on our Consolidated Statements of Operations during the three months ended March 31, 2015 and 2014:



	Three Months Ended March 31,
	2015			2014
Interest Rate Derivatives loss	$	(37,138	)	$	(34,479	)

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 March 31, 2015:
LNG Inventory Derivatives	$	372		$	—	$	372
Term Gas Supply Derivatives	662			—		662
Term Gas Supply Derivatives	(320		)	—		(320		)
Interest Rate Derivatives	(11,692		)	—		(11,692		)
As of December 31, 2014:
LNG Inventory Derivatives	1,216			1,132		84
Term Gas Supply Derivatives	662			—		662
Term Gas Supply Derivatives	(320		)	—		(320		)
Interest Rate Derivatives	11,158			—		11,158
Interest Rate Derivatives	(23,194		)	—		(23,194		)

NOTE 6—ACCRUED LIABILITIES

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



	March 31,		December 31,
	2015		2014
Interest expense and related debt fees	$	165,679	$	112,858
Liquefaction Project costs	28,201		22,014
LNG terminal costs	9,352		1,077
Other accrued liabilities	1,229		647
Total accrued liabilities	$	204,461	$	136,596

NOTE 7—LONG-TERM DEBT

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



	March 31,			December 31,
	2015			2014
Long-term debt
2016 Sabine Pass LNG Senior Notes	$	1,665,500		$	1,665,500
2020 Sabine Pass LNG Senior Notes	420,000			420,000
2021 SPL Senior Notes	2,000,000			2,000,000
2022 SPL Senior Notes	1,000,000			1,000,000
2023 SPL Senior Notes	1,500,000			1,500,000
2024 SPL Senior Notes	2,000,000			2,000,000
2025 SPL Senior Notes	2,000,000			—
2017 CTPL Term Loan	400,000			400,000
Total long-term debt	10,985,500			8,985,500
Long-term debt premium (discount)
2016 Sabine Pass LNG Senior Notes	(7,824		)	(8,998		)
2021 SPL Senior Notes	9,819			10,177
2023 SPL Senior Notes	6,918			7,089
2017 CTPL Term Loan	(2,184		)	(2,435		)
Total long-term debt, net	$	10,992,229		$	8,991,333

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

For the three months ended March 31, 2015 and 2014, we incurred $160.1 million and $128.6 million of total interest cost, respectively, of which we capitalized and deferred $117.2 million and $88.3 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.

Sabine Pass LNG Senior Notes

As of both March 31, 2015 and December 31, 2014, Sabine Pass LNG had an aggregate principal amount of $1,665.5 million, before discount, of the 2016 Sabine Pass LNG Senior Notes and $420.0 million of the 2020 Sabine Pass LNG Senior Notes outstanding. Borrowings under the 2016 Sabine Pass LNG Senior Notes and 2020 Sabine Pass LNG Senior Notes accrue interest at a fixed rate of 7.50% and 6.50%, respectively. The terms of the 2016 Sabine Pass LNG Senior Notes and 2020 Sabine Pass LNG Senior Notes are substantially similar. Interest on the Sabine Pass LNG Senior Notes is payable semi-annually in arrears. Subject to permitted liens, the Sabine Pass LNG Senior Notes are secured on a first-priority basis by a security interest in all of Sabine Pass LNG’s equity interests and substantially all of its operating assets.

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


•	1.0% of the principal amount of the 2016 Sabine Pass LNG Senior Notes; or

•

the excess of: (a) the present value at such redemption date of (i) the redemption price of the 2016 Sabine Pass LNG Senior Notes plus (ii) all required interest payments due on the 2016 Sabine Pass LNG Senior Notes (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the treasury rate as of such redemption date plus 50 basis points; over (b) the principal amount of the 2016 Sabine Pass LNG Senior Notes, if greater.

Sabine Pass LNG may redeem all or part of the 2020 Sabine Pass LNG Senior Notes at any time on or after November 1, 2016, at fixed redemption prices specified in the indenture governing the 2020 Sabine Pass LNG Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. Sabine Pass LNG may also, at its option, redeem all or part of the 2020 Sabine Pass LNG Senior Notes at any time prior to November 1, 2016, at a “make-whole” price set forth in the indenture governing the 2020 Sabine Pass LNG Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. At any time before November 1, 2015, Sabine Pass LNG may redeem up to 35% of the aggregate principal amount of the 2020 Sabine Pass LNG Senior Notes at a redemption price of 106.5% of the principal amount of the 2020 Sabine Pass LNG 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 Sabine Pass LNG redeems the 2020 Sabine Pass LNG 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 Sabine Pass LNG Senior Notes originally issued remains outstanding after the redemption.

Under the Sabine Pass LNG Indentures, except for permitted tax distributions, Sabine Pass LNG may not make distributions until certain conditions are satisfied as described in Note 3—Restricted Cash and Cash Equivalents. During the three months ended March 31, 2015 and 2014, Sabine Pass LNG made distributions of $70.8 million and $63.4 million, respectively, after satisfying all the applicable conditions in the Sabine Pass LNG Indentures.

SPL Senior Notes

In February 2013 and April 2013, SPL issued an aggregate principal amount of $2.0 billion, before premium, of the 2021 SPL Senior Notes. In April 2013 and May 2014, SPL issued an aggregate principal amount of $1.5 billion, before premium, of the 2023 SPL Senior Notes. Borrowings under the 2021 SPL Senior Notes and 2023 SPL Senior Notes accrue interest at a fixed rate of 5.625%. In November 2013, SPL issued an aggregate principal amount of $1.0 billion of the 2022 SPL Senior Notes, for which borrowings accrue interest at a fixed rate of 6.25%. In May 2014, SPL issued an aggregate principal amount of $2.0 billion of the 2024 SPL Senior Notes, for which borrowings accrue interest at a fixed rate of 5.75%. 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%. Interest on the SPL Senior Notes is payable semi-annually in arrears.

The terms of the SPL Senior Notes are governed by a common indenture (the “SPL Indenture”). The SPL Indenture contains customary terms and events of default and certain covenants that, among other things, limit SPL’s ability and the ability of SPL’s restricted subsidiaries to: incur additional indebtedness; issue preferred stock, make certain investments or pay dividends or distributions on capital stock or subordinated indebtedness; purchase, redeem or retire capital stock; sell or transfer assets, including

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

capital stock of SPL’s restricted subsidiaries; restrict dividends or other payments by restricted subsidiaries; incur liens; enter into transactions with affiliates; consolidate, merge, sell or lease all or substantially all of SPL’s assets; and enter into certain LNG sales contracts. Subject to permitted liens, the SPL Senior Notes are secured on a pari passu first-priority basis by a security interest in all of the membership interests in SPL and substantially all of SPL’s assets. SPL may not make any distributions until, among other requirements, substantial completion of Trains 1 and 2 has occurred, deposits are made into debt service reserve accounts and a debt service coverage ratio for the prior 12-month period and a projected debt service coverage ratio for the upcoming 12-month period of 1.25:1.00 are satisfied.

At any time prior to 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 SPL Indenture, 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.

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 Liquefaction Registration Rights Agreement”). Under the terms of the 2025 Liquefaction 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 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. SPL has agreed, and any future guarantors of the 2025 SPL Senior Notes will agree, to use commercially reasonable efforts to cause such registration statement to become effective within 360 days after March 3, 2015. 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.

2013 Liquefaction Credit Facilities

In May 2013, SPL entered into the 2013 Liquefaction Credit Facilities aggregating $5.9 billion. The 2013 Liquefaction Credit Facilities are being used to fund a portion of the costs of developing, constructing and placing into operation the first four Trains of the Liquefaction Project. The 2013 Liquefaction Credit Facilities will mature on the earlier of May 28, 2020 or the second anniversary of the completion date of the first four Trains of the Liquefaction Project, as defined in the 2013 Liquefaction Credit Facilities. Borrowings under the 2013 Liquefaction Credit Facilities may be refinanced, in whole or in part, at any time without premium or penalty, except for interest rate hedging and interest rate breakage costs. As of March 31, 2015 and December 31, 2014, SPL had $0.9 billion and $2.7 billion, respectively, of available commitments, and no outstanding borrowings as of both dates, under the 2013 Liquefaction Credit Facilities.

SPL made an initial $100.0 million borrowing under the 2013 Liquefaction Credit Facilities in June 2013 after meeting the required conditions precedent. In November 2013, in conjunction with SPL’s issuance of the 2022 SPL Senior Notes, SPL terminated approximately $885 million of commitments under the 2013 Liquefaction Credit Facilities. In May 2014, SPL repaid its borrowings under the 2013 Liquefaction Credit Facilities upon the issuance of the Additional 2023 SPL Senior Notes and the 2024 SPL Senior Notes, as well as terminated approximately $2.1 billion of commitments under the 2013 Liquefaction 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 Liquefaction Credit Facilities. This termination resulted in a write-off of debt issuance costs and deferred commitment fees associated with the 2013 Liquefaction Credit Facilities of $89.0 million in March 2015.

Borrowings under the 2013 Liquefaction 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 margins for LIBOR loans range from 2.3% to 3.0% prior to the completion of Train 4 and from 2.3% to 3.25% after such completion, depending on the applicable 2013 Liquefaction Credit Facility. Interest on LIBOR loans is due and payable at the end of each LIBOR period. The 2013 Liquefaction Credit Facilities require SPL to pay certain up-front fees to the agents and lenders in the aggregate amount of approximately $144 million and provide for a commitment fee calculated at a rate per annum equal to 40% of the applicable margin for LIBOR loans, multiplied

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

by the average daily amount of the undrawn commitment due quarterly in arrears. Annual administrative fees must also be paid to the agent and the trustee. The principal of the loans made under the 2013 Liquefaction Credit Facilities must be repaid in quarterly installments, commencing with the earlier of the last day of the first full calendar quarter after the Train 4 completion date, as defined in the 2013 Liquefaction Credit Facilities, or September 30, 2018. Scheduled repayments are based upon an 18-year amortization profile, with the remaining balance due upon the maturity of the 2013 Liquefaction Credit Facilities.

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

The 2013 Liquefaction Credit Facilities contain conditions precedent for any subsequent borrowings, as well as customary affirmative and negative covenants. The obligations of SPL under the 2013 Liquefaction 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 2013 Liquefaction Credit Facilities, SPL is required to hedge not less than 75% of the variable interest rate exposure of its projected outstanding borrowings, calculated on a weighted average basis in comparison to its anticipated draw of principal. See Note 5— Derivative Instruments.

2017 CTPL Term Loan

In May 2013, CTPL entered into the 2017 CTPL Term Loan, which is being used to fund modifications to the Creole Trail Pipeline and for general business purposes. CTPL incurred $10.0 million of direct lender fees that were recorded as a debt discount. The 2017 CTPL Term Loan matures in 2017 when the full amount of the outstanding principal obligations must be repaid. CTPL’s loans may be repaid, in whole or in part, at any time without premium or penalty. As of March 31, 2015, CTPL had borrowed the full amount of $400.0 million available under the 2017 CTPL Term Loan.

Borrowings under the 2017 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.

Under the terms and conditions of the 2017 CTPL Term Loan, all cash reserved to pay interest during construction is controlled by a collateral agent. These funds can only be released by the collateral agent upon satisfaction of certain terms and conditions, and are classified as restricted cash and cash equivalents on our Consolidated Balance Sheets. CTPL is also required to pay annual fees to the administrative and collateral agents.

The 2017 CTPL Term Loan contains customary affirmative and negative covenants. The obligations of CTPL under the 2017 CTPL Term Loan are secured by a first priority lien on substantially all of the personal property of CTPL and all of the general partner and limited partner interests in CTPL.

Cheniere Partners has guaranteed (i) the obligations of CTPL under the 2017 CTPL Term Loan if the maturity of the CTPL loans is accelerated following the termination by SPL of a transportation precedent agreement in limited circumstances and (ii) the obligations of Cheniere Investments, Cheniere Partners’ wholly owned subsidiary, in connection with its obligations under an equity contribution agreement (a) to pay operating expenses of CTPL until CTPL receives revenues under a service agreement with SPL and (b) to fund interest payments on the CTPL loans after the funds in an interest reserve account have been exhausted.

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 (a) 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 (b) 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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

at a rate of 2.0% plus the base rate as defined in the SPL LC Agreement. As of March 31, 2015 and December 31, 2014, SPL had issued letters of credit in an aggregate amount of $72.5 million and $9.5 million, respectively, and as of both March 31, 2015 and December 31, 2014, no draws had been made upon any letters of credit issued under the SPL LC Agreement.

Fair Value Disclosures

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



	March 31, 2015				December 31, 2014
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
2016 Sabine Pass LNG Senior Notes, net of discount (1)	$	1,657,676	$	1,757,136	$	1,656,502	$	1,718,621
2020 Sabine Pass LNG Senior Notes (1)	420,000		428,400		420,000		428,400
2021 SPL Senior Notes, net of premium (1)	2,009,819		2,024,893		2,010,177		1,985,050
2022 SPL Senior Notes (1)	1,000,000		1,030,000		1,000,000		1,020,000
2023 SPL Senior Notes, net of premium (1)	1,506,918		1,506,918		1,507,089		1,476,947
2024 SPL Senior Notes (1)	2,000,000		2,000,000		2,000,000		1,970,000
2025 SPL Senior Notes (1)	2,000,000		1,975,000		—		—
2017 CTPL Term Loan, net of discount (2)	397,816		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 March 31, 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 CTPL has the ability to call this debt 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 Sabine Pass LNG as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA with Sabine Pass LNG. SPL is obligated to make monthly capacity payments to Sabine Pass LNG 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 March 31, 2015 and 2014, we recorded expenses of $17.8 million and credits of $0.2 million, respectively, as operating and maintenance expense related to this obligation.

Cheniere Investments, SPL and Sabine Pass LNG entered into the terminal use rights assignment and agreement (“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 Sabine Pass LNG. However, the revenue earned by Sabine Pass LNG from the capacity payments made under the TUA and the loss incurred by Cheniere Investments under the TURA are eliminated upon consolidation of our financial statements. We have guaranteed the obligations of 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 months ended March 31, 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.

Services Agreements

As of March 31, 2015 and December 31, 2014, we had $21.8 million and $27.3 million of advances to affiliates, respectively, under the services agreements described below. During the three months ended March 31, 2015 and 2014, we recorded general and administrative expense—affiliate of $21.6 million and $27.2 million, respectively, and operating and maintenance expense—affiliate of $4.8 million and $4.4 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 compensated a quarterly non-accountable overhead reimbursement charge of $2.8 million (adjusted for inflation) for the provision of various general and administrative services for our benefit. In addition, we reimburse Cheniere Terminals for all audit, tax, legal and finance fees incurred by Cheniere Terminals that are necessary to perform the services under the agreement.

Sabine Pass LNG O&M Agreement

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

Sabine Pass LNG MSA

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

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.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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. In November 2013, the CTPL O&M Agreement was assigned by Cheniere Energy Partners GP, LLC to Cheniere Investments. 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 liquefaction facilities. CTPL pays a monthly fee equal to 3.0% of the capital expenditures to enable bi-directional natural gas flow on the Creole Trail Pipeline incurred in the previous month.

LNG Lease Agreement

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

As a result of Cheniere Investments assuming full price risk associated with the LNG Lease Agreement, LNG inventory purchased by Cheniere Marketing under this arrangement is classified as LNG inventory—affiliate, which is included in other—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. 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 March 31, 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 Sabine Pass LNG’s Cooperative Endeavor Agreements (“CEAs”)

In July 2007, Sabine Pass LNG executed CEAs with various Cameron Parish, Louisiana taxing authorities that allow them to collect certain annual property tax payments from Sabine Pass LNG from 2007 through 2016. This ten-year initiative represents an aggregate commitment of up to $25.0 million and Sabine Pass LNG will make resources available to the Cameron Parish taxing authorities on an accelerated basis in order to aid in their reconstruction efforts following Hurricane Rita. In exchange for Sabine

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Pass LNG’s advance payments of annual ad valorem taxes, Cameron Parish will grant Sabine Pass LNG a dollar-for-dollar credit against future ad valorem taxes to be levied against the Sabine Pass LNG terminal starting in 2019. In September 2007, Sabine Pass LNG entered into an agreement with Cheniere Marketing, pursuant to which Cheniere Marketing would pay Sabine Pass LNG additional TUA revenues equal to any and all amounts payable under the CEAs in exchange for a similar amount of credits against future TUA payments it would owe Sabine Pass LNG under its TUA starting in 2019. In June 2010, Cheniere Marketing assigned its TUA to Cheniere Investments and concurrently entered into a variable capacity rights agreement (“VCRA”), 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 Sabine Pass LNG utilized to make the ad valorem tax payments were recorded as a long-term obligation. As of March 31, 2015 and December 31, 2014, we had $22.1 million and $19.6 million, respectively, of other non-current assets resulting from Sabine Pass LNG’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

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

Sabine Pass LNG recorded operating and maintenance expense of $1.6 million and $0.5 million for natural gas purchased from Cheniere Marketing under these agreements in the three months ended March 31, 2015 and 2014, respectively. Sabine Pass LNG recorded revenues—affiliate of $1.3 million and zero for natural gas sold to Cheniere Marketing under these agreements in the three months ended March 31, 2015 and 2014, respectively.

Tug Boat Lease Sharing Agreement

In connection with its tug boat lease, Sabine Pass Tug Services, LLC, a wholly owned subsidiary of Sabine Pass LNG (“Tug Services”), entered into a tug sharing agreement with 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 March 31, 2015 and 2014.

State Tax Sharing Agreements

In November 2006, Sabine Pass LNG 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 Sabine Pass LNG 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, Sabine Pass LNG will pay to Cheniere an amount equal to the state and local tax that Sabine Pass LNG 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 Sabine Pass LNG under this agreement; therefore, Cheniere has not demanded any such payments from Sabine Pass LNG. 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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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 April 21, 2015, we declared a $0.425 distribution per common unit and the related distribution to our general partner to be paid on May 15, 2015 to unitholders of record as of May 1, 2015 for the period from January 1, 2015 to March 31, 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 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 months ended March 31, 2015 and 2014.

The following is a schedule by years, based on the capital structure as of March 31, 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	(594,390	)	2,004,209	(1,409,819	)

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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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 March 31, 2015
Net loss	$	(178,676	)
Declared distributions	24,754			24,259			—		—			495
Assumed allocation of undistributed net loss	$	(203,430	)	(59,125		)	—		(140,236		)	(4,070		)
Assumed allocation of net loss				$	(34,866	)	$	—	$	(140,236	)	$	(3,575	)

Weighted average units outstanding				57,080			145,333		135,384
Net loss per unit				$	(0.61	)	$	—	$	(1.04	)

Three Months Ended March 31, 2014
Net loss	$	(69,733	)
Declared distributions	24,754			24,259			—		—			495
Assumed allocation of undistributed net loss	$	(94,487	)	(27,462		)	—		(65,135		)	(1,890		)
Assumed allocation of net loss				$	(3,203	)	$	—	$	(65,135	)	$	(1,395	)

Weighted average units outstanding				57,079			145,333		135,384
Net loss per unit				$	(0.06	)	$	—	$	(0.48	)

NOTE 10—SUPPLEMENTAL CASH FLOW INFORMATION

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



	Three Months Ended March 31,
	2015		2014
Cash paid during the year for interest, net of amounts capitalized and deferred	$	—	$	16,567
Balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate)	147,538		67,768

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 position, results of operations and cash flows.

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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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 position, results of operations and cash flows.

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. Upon adoption of this standard, the balance of long-term debt, net will be reduced by the balance of debt issuance costs, net on our Consolidated Balance Sheets.


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 Sabine Pass LNG, 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 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, Sabine Pass LNG, we own and operate the regasification facilities at the Sabine Pass LNG terminal located on the Sabine Pass deep water shipping channel less than four miles from the Gulf Coast. The Sabine Pass LNG terminal includes existing infrastructure of five LNG storage tanks with capacity of approximately 16.9 Bcfe, two docks that can accommodate vessels with 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.

Liquidity and Capital Resources

Cash and Cash Equivalents

As of March 31, 2015, we had $171.5 million of cash and cash equivalents and $2,110.8 million of current and non-current restricted cash and cash equivalents (which included current and non-current restricted cash and cash equivalents available to us, SPL and Sabine Pass LNG) designated for the following purposes: $1,953.7 million for the Liquefaction Project; $28.1 million for CTPL; and $129.1 million for interest payments related to the Sabine Pass LNG 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 Sabine Pass LNG’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 Sabine Pass LNG 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 Sabine Pass LNG 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, Sabine Pass LNG is entitled to retain 2% of the LNG delivered to the Sabine Pass LNG terminal.

Liquefaction Facilities

The Liquefaction Project is being developed 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.

The U.S. Department of Energy (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 countries with which the United States has a free trade agreement providing for national treatment for trade in natural gas (“FTA countries”) for a 30-year term, beginning on the earlier of the date of first export or September 7, 2020; and to all countries without a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted (“non-FTA countries”) for a 20-year term, beginning on the earlier of the date of first export or August 7, 2017. 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 an additional 503.3 Bcf/yr in total of domestically produced LNG from the Sabine Pass LNG terminal to FTA countries for a 20-year term. SPL’s applications for authorization to export that same 503.3 Bcf/yr of domestically produced LNG from the Sabine Pass LNG terminal to non-FTA countries are currently pending at the DOE.

As of March 31, 2015, the overall project completion percentages for Trains 1 and 2 and Trains 3 and 4 of the Liquefaction Project were approximately 87.2% and 62.6%, 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, 3 and 4 are expected to commence operations on a staggered basis thereafter.

Customers

SPL has entered into four fixed price, 20-year SPAs with third parties that in the aggregate equate to 16 mtpa (approximately 803 Bcf/yr) of LNG that commence with the date of first commercial delivery for Trains 1 through 4, which are fully permitted. In addition, SPL has entered into two fixed price, 20-year SPAs with third parties for another 3.75 mtpa of LNG that commence with the date of first commercial delivery for Train 5. However, SPL has not yet received approval from the DOE for the export of LNG from Train 5 to non-FTA countries. These two SPAs contain certain conditions precedent, including, but not limited to, receiving regulatory approvals, securing necessary financing arrangements and making a final investment decision with respect to Train 5, which must be satisfied by June 30, 2015 or either party to the respective SPA may terminate its SPA. Under the 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 $2.3 billion annually for Trains 1 through 4, and $2.9 billion annually if we make a positive final investment decision with respect to Train 5, with the applicable fixed fees starting from the commencement of commercial operations 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, SPL 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 March 31, 2015, SPL has secured up to approximately 2,161.9 million MMBtu of natural gas feedstock through long-term natural gas purchase agreements.

Construction

Trains 1 through 4 are being designed, constructed and commissioned by Bechtel. SPL entered into lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of Trains 1 and 2 (the “EPC Contract (Trains 1 and 2)”) and Trains 3 and 4 (the “EPC Contract (Trains 3 and 4)”) 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 EPC Contract (Trains 1 and 2) and EPC Contract (Trains 3 and 4) are approximately $4.1 billion and $3.8 billion, respectively, reflecting amounts incurred under change orders through March 31, 2015. Total expected capital costs for Trains 1 through 4 are estimated to be between $9.0 billion and $10.0 billion before financing costs and between $12.0 billion and $13.0 billion after financing costs, including, in each case, estimated owner’s costs and contingencies.

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. We estimate that the capital costs to modify the Creole Trail Pipeline will be approximately $105 million. The modifications are expected to be in service in time for the commissioning and testing of Trains 1 and 2.

Final Investment Decision on Train 5 and Train 6

We will contemplate making a final investment decision to commence construction of Train 5 and Train 6 of the Liquefaction Project based upon, among other things, entering into EPC contracts, entering into acceptable commercial arrangements, receiving regulatory authorizations and obtaining adequate financing to construct the Trains.

Capital Resources

We currently expect that SPL’s capital resources requirements with respect to Trains 1 through 4 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 2013 Liquefaction Credit Facilities (as defined below) and cash flows from operations, we will have adequate financial resources available to complete Trains 1 through 4 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 late 2015, when Train 1 of the Liquefaction Project is anticipated to achieve initial LNG production.

Senior Secured Notes

As of March 31, 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 Sabine Pass LNG (the “2016 Sabine Pass LNG Senior Notes”);


•	$0.4 billion of 6.50% Senior Secured Notes due 2020 issued by Sabine Pass LNG (the “2020 Sabine Pass LNG Senior Notes” and collectively with the 2016 Sabine Pass LNG Senior Notes, the “Sabine Pass LNG 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 2025 SPL Senior Notes.

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

Sabine Pass LNG may redeem all or part of its 2016 Sabine Pass LNG 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 Sabine Pass LNG Senior Notes; or

•

Sabine Pass LNG may redeem all or part of the 2020 Sabine Pass LNG Senior Notes at any time on or after November 1, 2016 at fixed redemption prices specified in the indenture governing the 2020 Sabine Pass LNG Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. Sabine Pass LNG may also, at its option, redeem all or part of the 2020 Sabine Pass LNG Senior Notes at any time prior to November 1, 2016, at a “make-whole” price set forth in the indenture governing the 2020 Sabine Pass LNG Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. At any time before November 1, 2015, Sabine Pass LNG may redeem up to 35% of the aggregate principal amount of the 2020 Sabine Pass LNG Senior Notes at a redemption price of 106.5% of the principal amount of the 2020 Sabine Pass LNG 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 Sabine Pass LNG redeems the 2020 Sabine Pass LNG 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 Sabine Pass LNG 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 Sabine Pass LNG Senior Notes (the “Sabine Pass LNG Indentures”), except for permitted tax distributions, Sabine Pass LNG may not make distributions until, among other requirements, deposits are made into debt service reserve accounts and a fixed charge coverage ratio test of 2:1 is satisfied. Under the 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 three months ended March 31, 2015 and 2014, Sabine Pass LNG made distributions of $70.8 million and $63.4 million, respectively, after satisfying all the applicable conditions in the Sabine Pass LNG 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 2013 Liquefaction Credit Facilities and a $325.0 million senior letter of credit and reimbursement agreement (the “SPL LC Agreement”) described below.

2013 Liquefaction Credit Facilities

In May 2013, SPL entered into four credit facilities aggregating $5.9 billion (collectively, the “2013 Liquefaction Credit Facilities”). In conjunction with SPL’s issuances of the respective series of SPL Senior Notes in November 2013 and May 2014, SPL terminated approximately $885 million and $2.1 billion, respectively, of commitments under the 2013 Liquefaction Credit Facilities. In March 2015, in conjunction with SPL’s issuance of the 2025 SPL Senior Notes, SPL further terminated approximately $1.8 billion of commitments under the 2013 Liquefaction Credit Facilities. As a result, as of March 31, 2015, SPL has available commitments aggregating $0.9 billion under the 2013 Liquefaction Credit Facilities, which will be used to fund a portion of the costs of developing, constructing and placing into operation Trains 1 through 4 of the Liquefaction Project.

The principal of the loans made under the 2013 Liquefaction Credit Facilities must be repaid in quarterly installments, commencing with the earlier of the last day of the first full calendar quarter after the Train 4 completion date, as defined in the 2013 Liquefaction Credit Facilities, or September 30, 2018. Loans under the 2013 Liquefaction 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 margins for LIBOR loans range from 2.3% to 3.0% prior to the completion of Train 4 and from 2.3% to 3.25% after such completion, depending on the applicable 2013 Liquefaction Credit Facility. The 2013 Liquefaction Credit Facilities also require SPL to pay a commitment fee calculated at a rate per annum equal to 40% of the applicable margin for LIBOR loans, multiplied by the average daily amount of undrawn commitments. Interest on LIBOR loans and the commitment fees are due and payable at the end of each LIBOR period and quarterly, respectively.

2017 CTPL Term Loan

CTPL has a $400.0 million term loan facility (“2017 CTPL Term Loan”), which is being used to fund modifications to the Creole Trail Pipeline and for general business purposes. The 2017 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 March 31, 2015, CTPL had borrowed the full amount of $400.0 million available under the 2017 CTPL Term Loan. Borrowings under the 2017 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 (a) 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 (b) 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 March 31, 2015, SPL had issued letters of credit in an aggregate amount of $72.5 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 three months ended March 31, 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.



	Three Months Ended March 31,
	2015			2014
Sources of cash and cash equivalents
Proceeds from issuances of long-term debt	$	2,000,000		$	—
Use of restricted cash and cash equivalents for the acquisition of property, plant and equipment	572,434			761,378
Use of restricted cash and cash equivalents for financing activities	—			13,957
Total sources of cash and cash equivalents	2,572,434			775,335

Uses of cash and cash equivalents
Investment in restricted cash and cash equivalents	(1,949,338		)	—
Property, plant and equipment, net	(542,114		)	(751,808		)
Debt issuance and deferred financing costs	(50,662		)	(13,957		)
Distributions to owners	(24,754		)	(24,754		)
Operating cash flow	(52,424		)	(456		)
Other	(30,508		)	(10,050		)
Total uses of cash and cash equivalents	(2,649,800		)	(801,025		)

Net decrease in cash and cash equivalents	(77,366		)	(25,690		)
Cash and cash equivalents—beginning of period	248,830			351,032
Cash and cash equivalents—end of period	$	171,464		$	325,342

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

In March 2015, SPL issued the 2025 SPL Senior Notes for net proceeds of approximately $2.0 billion. Debt issuance costs in the three months ended March 31, 2015 primarily relate to up-front fees paid upon the closing of this offering and the payment of commitment fees for the 2013 Liquefaction Credit Facilities. Debt issuance costs in the three months ended March 31, 2014 related primarily to the payment of commitment fees for the 2013 Liquefaction Credit Facilities.

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

During the three months ended March 31, 2015 and 2014, we used $572.4 million and $761.4 million, respectively, of restricted cash and cash equivalents for investing activities to fund $542.1 million and $751.8 million, respectively, of construction costs for Trains 1 through 4 of the Liquefaction Project. The costs associated with the construction of Trains 1 through 4 of the Liquefaction Project are capitalized as construction-in-process.

Investment in (Use of) Restricted Cash and Cash Equivalents

In the three months ended March 31, 2015, we invested $1,949.3 million in restricted cash and cash equivalents primarily related to the net proceeds from the 2025 SPL Senior Notes, partially offset by the use of restricted cash related to payment of commitment fees for the 2013 Liquefaction Credit Facilities. In the three months ended March 31, 2014, we used $14.0 million of restricted cash and cash equivalents related to the payment of commitment fees for the 2013 Liquefaction Credit Facilities.

Operating Cash Flow

Cash used in operations was $52.4 million and $0.5 million in the three months ended March 31, 2015 and 2014, respectively. The increase in operating cash outflows primarily related to additional cash paid to purchase LNG to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal and the timing of receivables due from third parties.

Other

Other cash outflows increased from $10.0 million during the three months ended March 31, 2014 to $30.5 million during the three months ended March 31, 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 three months ended March 31, 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
February 13, 2015	October 1 - December 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 the Amended and Restated VCRA. The ending of the subordination period and conversion of the subordinated units into common units will depend upon future business development.

In 2012 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 April 21, 2015, we declared a $0.425 distribution per common unit and the related distribution to our general partner to be paid on May 15, 2015 to owners of record as of May 1, 2015 for the period from January 1, 2015 to March 31, 2015.

Results of Operations

Three Months Ended March 31, 2015 vs. Three Months Ended March 31, 2014

Our consolidated net loss increased $108.9 million, from $69.7 million of net loss in the three months ended March 31, 2014, to $178.7 million of net loss in the three months ended March 31, 2015. The increase in net loss was primarily a result of increased loss on early extinguishment of debt and increased operating and maintenance expense, partially offset by a decrease in general and administrative expense—affiliate. Loss on early extinguishment of debt increased $89.0 million in the three months ended March 31, 2015, as compared to the three months ended March 31, 2014, due to the 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 Liquefaction Credit Facilities in March 2015. Operating and maintenance expense increased $22.8 million in the three months ended March 31, 2015, as compared to the three months ended March 31, 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. General and administrative expense—affiliate decreased $5.6 million in the three months ended March 31, 2015, as compared to the three months ended March 31, 2014, primarily as a result of a decrease in management fees incurred pursuant to management services agreements, which are based on capital expenditures incurred during the period.

There was no significant change to interest expense, net in the three months ended March 31, 2015, as compared to the three months ended March 31, 2014, primarily as a result of our capitalization of interest costs incurred which were directly related to the construction of the first four Trains of the Liquefaction Project. For the three months ended March 31, 2015 and 2014, we incurred $160.1 million and $128.6 million of total interest cost, respectively, of which we capitalized and deferred $117.2 million and $88.3 million, respectively.

Off-Balance Sheet Arrangements

As of March 31, 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 variability in expected future cash flows attributable to the future sale of our LNG inventory (“LNG Inventory Derivatives”). We use one-day value at risk (“VaR”) with a 95% confidence interval and other methodologies for market risk measurement and control purposes of our LNG Inventory Derivatives. The VaR is calculated using the Monte Carlo simulation method. The VaR related to our LNG Inventory Derivatives was $0.5 million as of March 31, 2015.

We have entered into commodity derivatives consisting of natural gas purchase agreements to secure natural gas feedstock for the Liquefaction Project (“Term Gas Supply Derivatives”). In order to test the sensitivity of the fair value of the Term Gas 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 March 31, 2015, we estimated the fair value of our Term Gas Supply Derivatives to be $0.3 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 Term Gas Supply Derivatives of $0.4 million as of March 31, 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 2013 Liquefaction Credit Facilities (“Interest Rate Derivatives”). In order to test the sensitivity of the fair value of the Interest Rate Derivatives to changes in interest rates, management modeled a 10% change in the forward 1-month LIBOR curve across the full 7-year term of the Interest Rate Derivatives. This 10% change in interest rates would have resulted in a change in the fair value of our Interest Rate Derivatives of $3.8 million as of March 31, 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 March 31, 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 March 31, 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 March 31, 2015, we did not engage in any transactions with Iran or with persons or entities related to Iran.

Blackstone CQP Holdco LP, an affiliate of The Blackstone Group L.P. (“Blackstone Group”), is a holder of approximately 29% of the outstanding equity interests of Cheniere Partners and has three representatives on the Board of Directors of Cheniere Partners’ general partner. Accordingly, Blackstone Group may be deemed an “affiliate” of Cheniere Partners, as that term is defined in Exchange Act Rule 12b-2.

We have received notice from Blackstone Group that it may include in its Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2015 disclosures pursuant to ITRA regarding one of its portfolio companies that may be deemed to be an affiliate of Blackstone Group. Because of the broad definition of “affiliate” in Exchange Act Rule 12b-2, this portfolio company of Blackstone Group, through Blackstone Group’s ownership of Cheniere Partners, may also be deemed to be an affiliate of ours. We have received notice from Blackstone Group that Travelport Limited (“Travelport”) has engaged in the following activities: as part of its global business in the travel industry, Travelport provides certain passenger travel-related Travel Commerce Platform and airline IT services to Iran Air and airline IT services to Iran Air Tours. The gross revenues and net profits attributable to such activities during the quarter ended March 31, 2015 have not been reported by Travelport. Blackstone Group has informed us that Travelport intends to continue these business activities with Iran Air and Iran Air Tours as such activities are either exempt from applicable sanctions prohibitions or specifically licensed by the Office of Foreign Assets Control.

ITEM 6. EXHIBITS



Exhibit No.		Description
4.1		Sixth Supplemental Indenture, dated as of March 3, 2015, between Sabine Pass Liquefaction, LLC and The Bank of New York Mellon, as Trustee under the Indenture (Incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-33366), filed on March 3, 2015)
10.1		Registration Rights Agreement, dated as of March 3, 2015, between Sabine Pass Liquefaction, LLC and J.P. Morgan Securities LLC (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-33366), filed on March 3, 2015)
10.2		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00039 Increase to Existing Facility Labor Provisional Sum and Decrease to Sales and Use Tax Provisional Sum, dated February 12, 2015 and (ii) the Change Order CO-00040 Load Shedding and LNG Tank Tie-In Crane, dated February 24, 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 10.2 to Sabine Pass Liquefaction, LLC’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on April 30, 2015)
10.3		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 2 Liquefaction Facility, dated as of December 20, 2012, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00016 Louisiana Sales and Use Tax Provisional Sum Adjustment, dated February 12, 2015 and (ii) the Change Order CO-00017 Load Shedding Study and Scope Change, dated February 24, 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 10.3 to Sabine Pass Liquefaction, LLC’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on April 30, 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
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:	April 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:	April 30, 2015	By:	/s/ Leonard Travis
			Leonard Travis
			Chief Accounting Officer
			(on behalf of the registrant and as principal accounting officer)