Exhibit

Unsatisfied
Transaction Price
(in billions)

Weighted Average Recognition Timing (years) (1)

LNG revenues

Regasification revenues

Total revenues

Exhibit 99.1


ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

CHENIERE ENERGY, INC. AND SUBSIDIARIES




Report of Independent Registered Public Accounting Firm	2
Consolidated Balance Sheets	3
Consolidated Statements of Operations	4
Consolidated Statements of Stockholders’ Equity	5
Consolidated Statements of Cash Flows	6
Notes to Consolidated Financial Statements	7

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and Board of Directors

Cheniere Energy, Inc.:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Cheniere Energy, Inc. and subsidiaries (the Company) as of December 31, 2017 and 2016, the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2017, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 20, 2018 (not included herein) expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Change in Accounting Principle

As discussed in Note 2 to the consolidated financial statements, the Company has changed its method of accounting for revenue recognition in 2017, 2016 and 2015 due to the adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ KPMG LLP

KPMG LLP

We have served as the Company’s auditor since 2014.

Houston, Texas

February 20, 2018, except as to Note 13 which is as of May 23, 2018

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in millions, except share data)



	December 31,
	2017			2016
ASSETS
Current assets
Cash and cash equivalents	$	722		$	876
Restricted cash	1,880			860
Accounts and other receivables	369			218
Accounts receivable—related party	2			—
Inventory	243			160
Derivative assets	57			24
Other current assets	96			100
Total current assets	3,369			2,238

Non-current restricted cash	11			91
Property, plant and equipment, net	23,978			20,635
Debt issuance costs, net	149			277
Non-current derivative assets	34			83
Goodwill	77			77
Other non-current assets, net	288			302
Total assets	$	27,906		$	23,703

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	25		$	49
Accrued liabilities	1,078			637
Current debt	—			247
Deferred revenue	111			73
Derivative liabilities	37			71
Total current liabilities	1,251			1,077

Long-term debt, net	25,336			21,688
Non-current deferred revenue	1			5
Non-current derivative liabilities	19			45
Other non-current liabilities	59			49

Commitments and contingencies (see Note 20)

Stockholders’ equity
Preferred stock, $0.0001 par value, 5.0 million shares authorized, none issued	—			—
Common stock, $0.003 par value
Authorized: 480.0 million shares at December 31, 2017 and 2016
Issued: 250.1 million shares at December 31, 2017 and 2016
Outstanding: 237.6 million shares and 238.0 million shares at December 31, 2017 and 2016, respectively	1			1
Treasury stock: 12.5 million shares and 12.2 million shares at December 31, 2017 and 2016, respectively, at cost	(386		)	(374		)
Additional paid-in-capital	3,248			3,211
Accumulated deficit	(4,627		)	(4,234		)
Total stockholders’ deficit	(1,764		)	(1,396		)
Non-controlling interest	3,004			2,235
Total equity	1,240			839
Total liabilities and equity	$	27,906		$	23,703

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per share data)



	Year Ended December 31,
	2017			2016			2015
Revenues
LNG revenues	$	5,317		$	1,016		$	—
Regasification revenues	260			259			259
Other revenues	21			8			12
Other—related party	3			—			—
Total revenues	5,601			1,283			271

Operating costs and expenses
Cost (cost recovery) of sales (excluding depreciation and amortization expense shown separately below)	3,120			582			(15		)
Operating and maintenance expense	446			216			95
Development expense	10			7			42
Selling, general and administrative expense	256			260			363
Depreciation and amortization expense	356			174			83
Restructuring expense	6			61			61
Impairment expense and loss on disposal of assets	19			13			91
Total operating costs and expenses	4,213			1,313			720

Income (loss) from operations	1,388			(30		)	(449		)

Other income (expense)
Interest expense, net of capitalized interest	(747		)	(488		)	(322		)
Loss on early extinguishment of debt	(100		)	(135		)	(124		)
Derivative gain (loss), net	7			(10		)	(204		)
Other income	18			—			2
Total other expense	(822		)	(633		)	(648		)

Income (loss) before income taxes and non-controlling interest	566			(663		)	(1,097		)
Income tax provision	(3		)	(2		)	—
Net income (loss)	563			(665		)	(1,097		)
Less: net income (loss) attributable to non-controlling interest	956			(55		)	(122		)
Net loss attributable to common stockholders	$	(393	)	$	(610	)	$	(975	)

Net loss per share attributable to common stockholders—basic and diluted (1)	$	(1.68	)	$	(2.67	)	$	(4.30	)

Weighted average number of common shares outstanding—basic and diluted	233.1			228.8			226.9


(1)	Earnings per share in the table may not recalculate exactly due to rounding because it is calculated based on whole numbers, not the rounded numbers presented.

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(in millions)



	Total Stockholders’ Equity
	Common Stock				Treasury Stock				Additional Paid-in Capital		Accumulated Deficit			Non-controlling Interest			Total Equity
	Shares		Par Value Amount		Shares	Amount			Additional Paid-in Capital		Accumulated Deficit			Non-controlling Interest			Total Equity
Balance at December 31, 2014	236.7		$	1	10.6	$	(293	)	$	2,777	$	(2,649	)	$	2,666		$	2,502
Exercise of stock options	0.1		—		—	—			2		—			—			2
Forfeitures of restricted stock	(0.2	)	—		—	—			—		—			—			—
Share-based compensation	—		—		—	—			90		—			—			90
Shares repurchased related to share-based compensation	(1.0	)	—		1.0	(61		)	—		—			—			(61		)
Excess tax benefit from share-based compensation	—		—		—	—			2		—			—			2
Loss attributable to non-controlling interest	—		—		—	—			—		—			(122		)	(122		)
Equity portion of convertible notes, net	—		—		—	—			205		—			—			205
Distributions to non-controlling interest	—		—		—	—			—		—			(80		)	(80		)
Net loss	—		—		—	—			—		(975		)	—			(975		)
Balance at December 31, 2015	235.6		1		11.6	(354		)	3,076		(3,624		)	2,464			1,563
Issuances of restricted stock	0.4		—		—	—			—		—			—			—
Issuance of stock to acquire additional interest in Cheniere Holdings	3.0		—		—	—			94		—			(94		)	—
Forfeitures of restricted stock	(0.4	)	—		—	—			—		—			—			—
Share-based compensation	—		—		—	—			40		—			—			40
Shares repurchased related to share-based compensation	(0.6	)	—		0.6	(20		)	—		—			—			(20		)
Loss attributable to non-controlling interest	—		—		—	—			—		—			(55		)	(55		)
Equity portion of convertible notes, net	—		—		—	—			1		—			—			1
Distributions to non-controlling interest	—		—		—	—			—		—			(80		)	(80		)
Net loss	—		—		—	—			—		(610		)	—			(610		)
Balance at December 31, 2016	238.0		1		12.2	(374		)	3,211		(4,234		)	2,235			839
Issuances of restricted stock	0.1		—		—	—			—		—			—			—
Issuance of stock to acquire additional interest in Cheniere Holdings	—		—		—	—			2		—			(2		)	—
Forfeitures of restricted stock	(0.2	)	—		—	—			—		—			—			—
Share-based compensation	—		—		—	—			34		—			—			34
Shares repurchased related to share-based compensation	(0.3	)	—		0.3	(12		)	—		—			—			(12		)
Net income attributable to non-controlling interest	—		—		—	—			—		—			956			956
Equity portion of convertible notes, net	—		—		—	—			1		—			—			1
Distributions to non-controlling interest	—		—		—	—			—		—			(185		)	(185		)
Net loss	—		—		—	—			—		(393		)	—			(393		)
Balance at December 31, 2017	237.6		$	1	12.5	$	(386	)	$	3,248	$	(4,627	)	$	3,004		$	1,240

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)



	Year Ended December 31,
	2017			2016			2015
Cash flows from operating activities
Net income (loss)	$	563		$	(665	)	$	(1,097	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Non-cash LNG inventory write-downs	—			—			18
Depreciation and amortization expense	356			174			83
Share-based compensation expense	91			101			172
Non-cash interest expense	75			77			59
Amortization of debt issuance costs, deferred commitment fees, premium and discount	69			62			48
Loss on early extinguishment of debt	100			135			124
Total losses (gains) on derivatives, net	62			(28		)	168
Net cash used for settlement of derivative instruments	(106		)	(45		)	(100		)
Impairment expense and loss on disposal of assets	19			13			91
Other	(4		)	4			1
Changes in operating assets and liabilities:
Accounts and other receivables	(139		)	(207		)	(1		)
Accounts receivable—related party	(2		)	—			—
Inventory	(73		)	(119		)	(28		)
Accounts payable and accrued liabilities	225			64			2
Deferred revenue	34			42			(4		)
Other, net	(39		)	(12		)	(19		)
Net cash provided by (used in) operating activities	1,231			(404		)	(483		)

Cash flows from investing activities
Property, plant and equipment, net	(3,357		)	(4,356		)	(6,853		)
Investment in equity method investment	(41		)	—			—
Other	17			(57		)	(131		)
Net cash used in investing activities	(3,381		)	(4,413		)	(6,984		)

Cash flows from financing activities
Proceeds from issuances of debt	6,854			12,865			7,073
Repayments of debt	(3,632		)	(7,671		)	—
Debt issuance and deferred financing costs	(89		)	(172		)	(513		)
Debt extinguishment costs	—			(14		)	—
Distributions and dividends to non-controlling interest	(185		)	(80		)	(80		)
Proceeds from exercise of stock options	—			—			2
Payments related to tax withholdings for share-based compensation	(12		)	(20		)	(61		)
Other	—			—			2
Net cash provided by financing activities	2,936			4,908			6,423

Net increase (decrease) in cash, cash equivalents and restricted cash	786			91			(1,044		)
Cash, cash equivalents and restricted cash—beginning of period	1,827			1,736			2,780
Cash, cash equivalents and restricted cash—end of period	$	2,613		$	1,827		$	1,736

Balances per Consolidated Balance Sheets:



	December 31,
	2017		2016
Cash and cash equivalents	$	722	$	876
Restricted cash	1,880		860
Non-current restricted cash	11		91
Total cash, cash equivalents and restricted cash	$	2,613	$	1,827

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

Cheniere, a Delaware corporation, is a Houston-based energy company primarily engaged in LNG-related businesses. We own and operate the Sabine Pass LNG terminal in Louisiana through our ownership interest in and management agreements with Cheniere Partners, which is a publicly traded limited partnership that we created in 2007. We own 100% of the general partner interest in Cheniere Partners and 82.7% of Cheniere Holdings, which is a publicly traded limited liability company formed in 2013 that owns a 48.6% limited partner interest in Cheniere Partners. We are currently developing and constructing two natural gas liquefaction and export facilities.

The Sabine Pass LNG terminal is located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. Cheniere Partners is developing, constructing and operating natural gas liquefaction facilities (the “SPL Project”) at the Sabine Pass LNG terminal adjacent to the existing regasification facilities (described below) through a wholly owned subsidiary, SPL. Cheniere Partners plans to construct up to six Trains, which are in various stages of development, construction and operations. Trains 1 through 4 are operational, Train 5 is under construction and Train 6 is being commercialized and has all necessary regulatory approvals in place. Each Train is expected to have a nominal production capacity, which is prior to adjusting for planned maintenance, production reliability and potential overdesign, of approximately 4.5 mtpa and an adjusted nominal production capacity of approximately 4.3 to 4.6 mtpa of LNG. The Sabine Pass LNG terminal has operational regasification facilities owned by Cheniere Partners’ wholly owned subsidiary, SPLNG, that include pre-existing infrastructure of five LNG storage tanks with aggregate capacity of approximately 16.9 Bcfe, two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. Cheniere Partners also owns a 94-mile pipeline that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines (the “Creole Trail Pipeline”) through a wholly owned subsidiary, CTPL.

We are developing and constructing a second natural gas liquefaction and export facility at the Corpus Christi LNG terminal, which is on nearly 2,000 acres of land that we own or control near Corpus Christi, Texas, and a pipeline facility (collectively, the “CCL Project”) through wholly owned subsidiaries CCL and CCP, respectively. The CCL Project is being developed for up to three Trains, with expected aggregate nominal production capacity, which is prior to adjusting for planned maintenance, production reliability and potential overdesign, of approximately 13.5 mtpa of LNG, three LNG storage tanks with aggregate capacity of approximately 10.1 Bcfe and two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters. The CCL Project is being developed in stages. The first stage includes Trains 1 and 2, two LNG storage tanks, one complete marine berth and a second partial berth and all of the CCL Project’s necessary infrastructure facilities (“Stage 1”). The second stage includes Train 3, one LNG storage tank and the completion of the second partial berth (“Stage 2”). The CCL Project also includes a 23-mile natural gas supply pipeline that will interconnect the Corpus Christi LNG terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline”), which is being constructed concurrently with the first stage. Trains 1 and 2 are currently under construction, and Train 3 is being commercialized and has all necessary regulatory approvals in place. The construction of the Corpus Christi Pipeline is nearing completion.

Additionally, we are developing an expansion of the Corpus Christi LNG terminal adjacent to the CCL Project and recently amended our regulatory filings with FERC to incorporate a project design change, from two Trains with an expected aggregate nominal production capacity of approximately 9.0 mtpa to up to seven midscale Trains with an expected aggregate nominal production capacity of approximately 9.5 mtpa. We remain focused on leveraging infrastructure through the expansion of our existing sites. We are also in various stages of developing other projects, including infrastructure projects in support of natural gas supply and LNG demand, which, among other things, will require acceptable commercial and financing arrangements before we make a final investment decision (“FID”).

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Our Consolidated Financial Statements have been prepared in accordance with GAAP. The Consolidated Financial Statements include the accounts of Cheniere, its majority owned subsidiaries and entities in which it holds a controlling interest, including the accounts of Cheniere Holdings and Cheniere Partners and its wholly owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. Investments in non-controlled entities, over which Cheniere has the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method. In

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

applying the equity method of accounting, the investments are initially recognized at cost, and subsequently adjusted for our proportionate share of earnings, losses and distributions. Investments in non-controlled entities, over which Cheniere does not have the ability to exercise significant influence, are accounted for using the cost method. Under the cost method the investments are initially recognized at cost and dividends received from the accumulated earnings of an investee are recorded as income. Dividends received in excess of the accumulated earnings of an investee are recorded as a reduction in the investment. We periodically assess our cost method investments for indicators of impairment. An impairment is recorded if an indicator is identified, the carrying value of our investment exceeds its fair value, and the impairment is considered to be other than temporary. Investments accounted for using the equity method and cost method are reported as a component of other assets.

We make a determination at the inception of each arrangement whether an entity in which we have made an investment or in which we have other variable interests is considered a variable interest entity (“VIE”). Generally, a VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, whose equity investors lack any characteristics of a controlling financial interest or which was established with non-substantive voting. We consolidate VIEs when we are deemed to be the primary beneficiary. The primary beneficiary of a VIE is the party that both: (1) has the power to make decisions that most significantly affect the economic performance of the VIE and (2) has the obligation to absorb losses or the right to receive benefits that in either case could potentially be significant to the VIE. If we are not deemed to be the primary beneficiary of a VIE, we account for the investment or other variable interests in a VIE in accordance with applicable GAAP.

Certain reclassifications have been made to conform prior period information to the current presentation. The reclassifications did not have a material effect on our consolidated financial position, results of operations or cash flows.

On January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto (“ASC 606”) using the full retrospective method. We have elected to adopt the new accounting standard retrospectively and have recast the accompanying consolidated financial statements to reflect the adoption of ASC 606 for all periods presented. The adoption of ASC 606 did not impact our previously reported consolidated financial statements in any prior period nor did it result in a cumulative effect adjustment to retained earnings.

Use of Estimates

The preparation of 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. Management evaluates its estimates and related assumptions regularly, including those related to the value of property, plant and equipment, goodwill, derivative instruments, asset retirement obligations (“AROs”), income taxes including valuation allowances for deferred tax assets, share-based compensation and fair value measurements. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Fair Value

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation approaches used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Hierarchy Level 3 inputs are inputs that are not observable in the market.

In determining fair value, we use observable market data when available, or models that incorporate observable market data. In addition to market information, we incorporate transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value. We maximize the use of observable inputs and minimize our use of unobservable inputs in arriving at fair value estimates.

Recurring fair-value measurements are performed for derivative instruments as disclosed in Note 7—Derivative Instruments. The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and accounts payable reported on the Consolidated Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt in the open market, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note 12—Debt, are based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments using observable or

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

unobservable inputs. Non-financial assets and liabilities initially measured at fair value include certain assets and liabilities acquired in a business combination, intangible assets, goodwill and AROs.

Revenue Recognition

We recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration to which we expect to be entitled to in exchange for those goods or services. Revenues from the sale of LNG are recognized as LNG revenues, including LNG revenues generated by our integrated marketing function which are reported on a gross or net basis based on an assessment of whether it is acting as the principal or the agent in the transaction. LNG regasification capacity payments are recognized as regasification revenues. See Note 13—Revenues from Contracts with Customers for further discussion of revenues.

Cash and Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Restricted Cash

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

Accounts and Notes Receivable

Accounts and notes receivable are reported net of allowances for doubtful accounts. Notes receivable that are not classified as trade receivables are recorded within other current assets in our Consolidated Balance Sheets. Impaired receivables are specifically identified and evaluated for expected losses. The expected loss on impaired receivables is primarily determined based on the debtor’s ability to pay and the estimated value of any collateral. We did not recognize any impairment expense related to accounts and notes receivable during the years ended December 31, 2017 and 2016. During the year ended December 31, 2015, we recognized bad debt expense of $36 million which was primarily attributable to a reserve against funds loaned to Parallax Enterprises, LLC, as further discussed in Note 20—Commitments and Contingencies. This charge was recorded as impairment expense on our Consolidated Statements of Operations.

Inventory

LNG and natural gas inventory are recorded at the lower of weighted average cost and net realizable value. Materials and other inventory are recorded at the lower of cost and net realizable value and subsequently charged to expense when issued. During the year ended December 31, 2015, we recognized $18 million as operating and maintenance expense as a result of write-down for LNG inventory purchased to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal. We did not recognize any operating and maintenance expense related to inventory write-downs during the years ended December 31, 2017 and 2016.

Accounting for LNG Activities

Generally, we begin capitalizing the costs of our LNG terminals and related pipelines once the individual project meets the following criteria: (1) regulatory approval has been received, (2) financing for the project is available and (3) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a project are expensed as incurred. These costs primarily include professional fees associated with front-end engineering and design work, costs of securing necessary regulatory approvals and other preliminary investigation and development activities related to our LNG terminals and related pipelines.

Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land and lease option costs that are capitalized as property, plant and equipment and certain permits that are capitalized as other non-current assets. The costs of lease options are amortized over the life of the lease once obtained. If no lease is obtained, the costs are expensed.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

We capitalize interest and other related debt costs during the construction period of our LNG terminals and related pipelines. Upon commencement of operations, capitalized interest, as a component of the total cost, is amortized over the estimated useful life of the asset.

Property, Plant and Equipment

Property, plant and equipment are recorded at cost. Expenditures for construction and commissioning activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred. Interest costs incurred on debt obtained for the construction of property, plant and equipment are capitalized as construction-in-process over the construction period or related debt term, whichever is shorter. We depreciate our property, plant and equipment using the straight-line depreciation method. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses are recorded in other operating costs and expenses.

Management tests property, plant and equipment for impairment whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value.

During the year ended December 31, 2017, we recognized $6 million of impairment expense related to damaged infrastructure as an effect of Hurricane Harvey and $6 million of impairment expense related to write down of assets used in non-core operations outside of our liquefaction activities.

During the year ended December 31, 2016, we recorded $10 million of impairment expense related to a corporate airplane that was written down to fair value based on market-based appraisals, which was ultimately sold by the end of the year. The impairment was recognized due to the potential disposition of the airplane in connection with the Company having initiated organizational changes and the associated operational focus for financially disciplined investment.

During the year ended December 31, 2015, we recorded, primarily in relation to a liquid hydrocarbon export project in Texas along the Gulf Coast, $55 million of impairment expense as a result of our strategic focus to complete construction and commence operation of the first five Trains of the SPL Project and the first two Trains of the CCL Project.

Regulated Natural Gas Pipelines

The Creole Trail Pipeline and Corpus Christi Pipeline are subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. The economic effects of regulation can result in a regulated company recording as assets those costs that have been or are expected to be approved for recovery from customers, or recording as liabilities those amounts that are expected to be required to be returned to customers, in a rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated rate-making process that may not be recorded under GAAP for non-regulated entities. We continually assess whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, we believe the existing regulatory assets are probable of recovery. These regulatory assets and liabilities are primarily classified in our Consolidated Balance Sheets as other assets and other liabilities. We periodically evaluate their applicability under GAAP and consider factors such as regulatory changes and the effect of competition. If cost-based regulation ends or competition increases, we may have to reduce our asset balances to reflect a market basis less than cost and write off the associated regulatory assets and liabilities.

Items that may influence our assessment are:


•	inability to recover cost increases due to rate caps and rate case moratoriums;


•	inability to recover capitalized costs, including an adequate return on those costs through the rate-making process and the FERC proceedings;


•	excess capacity;

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED


•	increased competition and discounting in the markets we serve; and


•	impacts of ongoing regulatory initiatives in the natural gas industry.

Natural gas pipeline costs include amounts capitalized as an Allowance for Funds Used During Construction (“AFUDC”). The rates used in the calculation of AFUDC are determined in accordance with guidelines established by the FERC. AFUDC represents the cost of debt and equity funds used to finance our natural gas pipeline additions during construction. AFUDC is capitalized as a part of the cost of our natural gas pipelines. Under regulatory rate practices, we generally are permitted to recover AFUDC, and a fair return thereon, through our rate base after our natural gas pipelines are placed in service.

Derivative Instruments

We use derivative instruments to hedge our exposure to cash flow variability from interest rate, commodity price and foreign currency exchange (“FX”) rate risk. Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as assets or liabilities depending on the derivative position and the expected timing of settlement, unless they satisfy criteria for and we elect the normal purchases and sales exception. When we have the contractual right and intend to net settle, derivative assets and liabilities are reported on a net basis.

Changes in the fair value of our derivative instruments are recorded in earnings, unless we elect to apply hedge accounting and meet specified criteria, including completing contemporaneous hedge documentation. We did not have any derivative instruments designated as cash flow hedges during the years ended December 31, 2017, 2016 and 2015. See Note 7—Derivative Instruments for additional details about our derivative instruments.

Concentration of Credit Risk

Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash and cash equivalents and restricted cash. We maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred losses related to these balances to date.

The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Certain of our commodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. Collateral deposited for such contracts is recorded as other current asset. Our interest rate and FX derivative instruments are placed with investment grade financial institutions whom we believe are acceptable credit risks. We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our derivative instruments.

SPL has entered into six fixed price SPAs with terms of at least 20 years with six unaffiliated third parties. CCL has entered into eight fixed price SPAs with terms of at least 20 years with seven unaffiliated third parties. SPL and CCL are dependent on the respective customers’ creditworthiness and their willingness to perform under their respective SPAs. See Note 21—Customer Concentration for additional details about our customer concentration.

SPLNG has entered into two long-term TUAs with unaffiliated third parties for regasification capacity at the Sabine Pass LNG terminal. SPLNG is dependent on the respective customers’ creditworthiness and their willingness to perform under their respective TUAs. SPLNG has mitigated this credit risk by securing TUAs for a significant portion of its regasification capacity with creditworthy third-party customers with a minimum Standard & Poor’s rating of A.

Goodwill

Goodwill is the excess of acquisition cost of a business over the estimated fair value of net assets acquired. Goodwill is not amortized but is tested for impairment at least annually or more frequently if events or circumstances indicate goodwill is more likely than not impaired. Goodwill impairment evaluation requires a comparison of the estimated fair value of a reporting unit to its carrying value. Cheniere tests goodwill for impairment by either performing a qualitative assessment or a quantitative test. The qualitative assessment is an assessment of historical information and relevant events and circumstances to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill. Cheniere may

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

elect not to perform the qualitative assessment and instead perform a quantitative impairment test. Significant judgment is required in estimating the fair value of the reporting unit and performing goodwill impairment tests.

As a result of finalization of organizational changes to simplify our corporate structure, improve our operational efficiencies and implement a strategy for sustainable, long-term stockholder value creation through financially disciplined development, construction, operation and investment, we revised the way we manage our business, which resulted in a change in our reporting units. Accordingly, Cheniere reallocated goodwill to our single reporting unit following finalization of organizational changes. We performed our annual goodwill impairment test on October 1st using a quantitative assessment and concluded that the estimated fair value of our reporting unit substantially exceeded its carrying value and, therefore, goodwill was not impaired. Judgments and assumptions are inherent in our estimate of future cash flows used to determine the estimate of the reporting unit’s fair value. The use of alternate judgments and/or assumptions could result in the recognition of impairment charges in the Consolidated Financial Statements. A lower fair value estimate in the future for our reporting unit could result in an impairment of goodwill. Factors that could trigger a lower fair value estimate include significant negative industry or economic trends, cost increases, disruptions to our business, regulatory or political environment changes or other unanticipated events. There were no changes in the carrying value of goodwill during the year ended December 31, 2017.

Debt

Our debt consists of current and long-term secured debt securities, convertible debt securities and credit facilities with banks and other lenders. Debt issuances are placed directly by us or through securities dealers or underwriters and are held by institutional and retail investors.

Debt is recorded on our Consolidated Balance Sheets at par value adjusted for unamortized discount or premium and net of unamortized debt issuance costs related to term notes. Discounts, premiums and debt issuance costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest expense, net of capitalized interest using the effective interest method. Gains and losses on the extinguishment of debt are recorded in gains and losses on the extinguishment of debt on our Consolidated Statements of Operations.

Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees and printing costs. These costs are recorded as a direct deduction from the debt liability unless incurred in connection with a line of credit arrangement, in which case they are presented as an asset on our Consolidated Balance Sheet. Debt issuance costs are amortized to interest expense or property, plant and equipment over the term of the related debt facility. Upon early retirement of debt or amendment to a debt agreement, certain fees are written off to loss on early extinguishment of debt.

Asset Retirement Obligations

We recognize AROs for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset. Our assessment of AROs is described below.

We have not recorded an ARO associated with the Sabine Pass LNG terminal. Based on the real property lease agreements at the Sabine Pass LNG terminal, at the expiration of the term of the leases we are required to surrender the LNG terminal in good working order and repair, with normal wear and tear and casualty expected. Our property lease agreements at the Sabine Pass LNG terminal have terms of up to 90 years including renewal options. We have determined that the cost to surrender the Sabine Pass LNG terminal in good order and repair, with normal wear and tear and casualty expected, is immaterial.

We have not recorded an ARO associated with the Creole Trail Pipeline or the Corpus Christi Pipeline. We believe that it is not feasible to predict when the natural gas transportation services provided by the Creole Trail Pipeline or the Corpus Christi Pipeline will no longer be utilized. In addition, our right-of-way agreements associated with the Creole Trail Pipeline and the Corpus Christi Pipeline have no stipulated termination dates. We intend to operate the Creole Trail Pipeline and the Corpus Christi Pipeline as long as supply and demand for natural gas exists in the United States and intend to maintain it regularly.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Share-based Compensation

We have awarded share-based compensation in the form of stock, restricted stock, restricted stock units, performance stock units and phantom units that are more fully described in Note 16—Share-based Compensation. We recognize share-based compensation based upon the estimated fair value of awards. The recognition period for these costs begins at either the applicable service inception date or grant date and continues throughout the requisite service period. For equity-classified share-based compensation awards (which include stock, restricted stock, restricted stock units and performance stock units to employees and non-employee directors), compensation cost is recognized based on the grant-date fair value reduced by the present value of dividends expected to be paid on the underlying shares during the requisite service period, discounted at the appropriate risk-free interest rate and not subsequently remeasured. The fair value is recognized as expense (net of any capitalization) using the straight-line basis for awards that vest based solely on service conditions and using the accelerated recognition method for awards that vest based on performance conditions. For awards with both time and performance-based conditions, we generally recognize compensation cost based on the probable outcome of the performance condition at each reporting period. For liability-classified share-based compensation awards (which include phantom units), compensation cost is initially recognized on the grant date using estimated payout levels, and subsequently adjusted quarterly to reflect the updated estimated payout levels based on the changes in the our stock price. We account for forfeitures as they occur.

Non-controlling Interests

When we consolidate a subsidiary, we include 100% of the assets, liabilities, revenues and expenses of the subsidiary in our Consolidated Financial Statements, even if we own less than 100% of the subsidiary. Non-controlling interests represent third-party ownership in the net assets of our consolidated subsidiaries and are presented as a component of equity. Changes in our ownership interests in subsidiaries that do not result in deconsolidation are generally recognized within equity. See Note 10—Non-controlling Interest for additional details about our non-controlling interest.

Income Taxes

Provisions for income taxes are based on taxes payable or refundable for the current year and deferred taxes on temporary differences between the tax basis of assets and liabilities and their reported amounts in the Consolidated Financial Statements. Deferred tax assets and liabilities are included in the Consolidated Financial Statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the current period’s provision for income taxes. A valuation allowance is recorded to reduce the carrying value of our deferred tax assets when it is more likely than not that a portion or all of the deferred tax assets will expire before realization of the benefit or future deductibility is not probable.

We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the tax position.

Net Loss Per Share

Net loss per share (“EPS”) is computed in accordance with GAAP. Basic EPS excludes dilution and is computed by dividing net income (loss) by the weighted average number of common shares outstanding during the period. Diluted EPS reflects potential dilution and is computed by dividing net income (loss) by the weighted average number of common shares outstanding during the period increased by the number of additional common shares that would have been outstanding if the potential common shares had been issued and were dilutive. The dilutive effect of unvested stock is calculated using the treasury-stock method and the dilutive effect of convertible securities is calculated using the if-converted method.

Business Segment

During the first quarter of 2017, we finalized organizational changes to simplify our corporate structure, improve our operational efficiencies and implement a strategy for sustainable, long-term stockholder value creation through financially disciplined development, construction, operation and investment. As a result of these efforts, we revised the way we manage our business, which resulted in a change to our reportable segments. We previously had two reportable segments: LNG terminal segment and LNG and natural gas marketing segment. We have now determined that we operate as a single operating and reportable segment. Our chief operating decision maker makes resource allocation decisions and assesses performance based on financial information presented on a consolidated basis in the delivery of an integrated source of LNG to our customers.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 3—RESTRICTED CASH

Restricted cash consists of funds that are contractually restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. As of December 31, 2017 and 2016, restricted cash consisted of the following (in millions):



	December 31,
	2017		2016
Current restricted cash
SPL Project	$	544	$	358
Cheniere Partners and cash held by guarantor subsidiaries	1,045		247
CCL Project	227		197
Cash held by our subsidiaries restricted to Cheniere	64		58
Total current restricted cash	$	1,880	$	860

Non-current restricted cash
CCL Project	$	—	$	73
Other	11		18
Total non-current restricted cash	$	11	$	91

In February 2016, Cheniere Partners entered into the $2.8 billion credit facilities (the “2016 CQP Credit Facilities”). Cheniere Partners, as well as Cheniere Investments, SPLNG and CTPL as Cheniere Partners’ guarantor subsidiaries, are subject to limitations on the use of cash under the terms of the 2016 CQP Credit Facilities and the related depositary agreement governing the extension of credit to Cheniere Partners. Specifically, Cheniere Partners, Cheniere Investments, SPLNG and CTPL may only withdraw funds from collateral accounts held at a designated depositary bank on a monthly basis and for specific purposes, including for the payment of operating expenses. In addition, distributions and capital expenditures may only be made quarterly and are subject to certain restrictions.

NOTE 4—ACCOUNTS AND OTHER RECEIVABLES

As of December 31, 2017 and 2016, accounts and other receivables consisted of the following (in millions):



	December 31,
	2017		2016
Trade receivables
SPL	$	185	$	88
Cheniere Marketing	163		121
Other accounts receivable	21		9
Total accounts and other receivables	$	369	$	218

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

NOTE 5—INVENTORY

As of December 31, 2017 and 2016, inventory consisted of the following (in millions):



	December 31,
	2017		2016
Natural gas	$	17	$	15
LNG	44		50
LNG in-transit	130		58
Materials and other	52		37
Total inventory	$	243	$	160

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 6—PROPERTY, PLANT AND EQUIPMENT

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



	December 31,
	2017			2016
LNG terminal costs
LNG terminal	$	12,687		$	7,978
LNG terminal construction-in-process	11,932			12,995
LNG site and related costs	86			41
Accumulated depreciation	(882		)	(555		)
Total LNG terminal costs, net	23,823			20,459
Fixed assets and other
Computer and office equipment	14			13
Furniture and fixtures	19			17
Computer software	92			85
Leasehold improvements	41			43
Land	59			61
Other	16			22
Accumulated depreciation	(86		)	(65		)
Total fixed assets and other, net	155			176
Property, plant and equipment, net	$	23,978		$	20,635

Depreciation expense during the years ended December 31, 2017, 2016 and 2015 was $354 million, $173 million and $82 million, respectively.

We realized offsets to LNG terminal costs of $320 million and $214 million in the years ended December 31, 2017 and 2016, respectively, that were related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Train of the SPL Project, during the testing phase for its construction.

LNG Terminal Costs

The Sabine Pass LNG terminal is depreciated using the straight-line depreciation method applied to groups of LNG terminal assets with varying useful lives. The identifiable components of the Sabine Pass LNG terminal with similar estimated useful lives have a depreciable range between 6 and 50 years, as follows:



Components		Useful life (yrs)
LNG storage tanks		50
Natural gas pipeline facilities		40
Marine berth, electrical, facility and roads		35
Regasification processing equipment		30
Sendout pumps		20
Liquefaction processing equipment		6-50
Other		15-30

Fixed Assets and Other

Our fixed assets and other are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 7—DERIVATIVE INSTRUMENTS

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


•	interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under certain credit facilities (“Interest Rate Derivatives”);


•	commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the SPL Project and the CCL Project (“Physical Liquefaction Supply Derivatives”) and associated economic hedges (“Financial Liquefaction Supply Derivatives,” and collectively with the Physical Liquefaction Supply Derivatives, the “Liquefaction Supply Derivatives”);


•	financial derivatives to hedge the exposure to the commodity markets in which we have contractual arrangements to purchase or sell physical LNG (“LNG Trading Derivatives”); and


•	foreign currency exchange (“FX”) contracts to hedge exposure to currency risk associated with both LNG Trading Derivatives and operations in countries outside of the United States (“FX Derivatives”).

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

The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of December 31, 2017 and 2016, which are classified as derivative assets, non-current derivative assets, derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets (in millions).



	Fair Value Measurements as of
	December 31, 2017											December 31, 2016
	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
SPL Interest Rate Derivatives liability	$	—		$	—		$	—	$	—		$	—		$	(6	)	$	—	$	(6	)
CQP Interest Rate Derivatives asset	—			21			—		21			—			13			—		13
CCH Interest Rate Derivatives liability	—			(32		)	—		(32		)	—			(86		)	—		(86		)
Liquefaction Supply Derivatives asset (liability)	2			10			43		55			(4		)	(2		)	79		73
LNG Trading Derivatives asset (liability)	(13		)	5			—		(8		)	2			(5		)	—		(3		)
FX Derivatives liability	—			(1		)	—		(1		)	—			—			—		—

We value our Interest Rate Derivatives using an income-based approach utilizing observable inputs to the valuation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data. We value our LNG Trading Derivatives and our Liquefaction Supply Derivatives using market based approach incorporating present value techniques, as needed, using observable commodity price curves, when available, and other relevant data. We value our FX Derivatives with a market approach using observable FX rates and other relevant data.

The fair value of our Physical Liquefaction Supply Derivatives is predominantly driven by market commodity basis prices and our assessment of the associated conditions precedent, including evaluating whether the respective market is available as pipeline infrastructure is developed. Upon the satisfaction of conditions precedent, including completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow, we recognize a gain or loss based on the fair value of the respective natural gas supply contracts.

We include a portion of our Physical Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which may be impacted by inputs that are unobservable in the marketplace. The curves used to generate the fair value of our Physical Liquefaction Supply Derivatives are based on basis adjustments applied to forward curves for a liquid trading point. In addition, there may be observable liquid market basis information in the near term,

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

but terms of a Physical Liquefaction Supply Derivatives contract may exceed the period for which such information is available, resulting in a Level 3 classification. In these instances, the 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. As of December 31, 2017, some of our Physical Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure is under development to accommodate marketable physical gas flow.

The Level 3 fair value measurements of our Physical Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas market basis spreads due to the contractual notional amount represented by our Level 3 positions, which is a substantial portion of our overall Physical Liquefaction Supply portfolio. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of December 31, 2017:



	Net Fair Value Asset (in millions)	Valuation Approach	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$43	Market approach incorporating present value techniques	Basis Spread	$(0.703) - $0.432

The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the years ended December 31, 2017, 2016 and 2015 (in millions):



	Year Ended December 31,
	2017			2016			2015
Balance, beginning of period	$	79		$	32		$	—
Realized and mark-to-market gains (losses):
Included in cost of sales (1)	(37		)	48			32
Purchases and settlements:
Purchases	14			1			—
Settlements (1)	(12		)	(2		)	—
Transfers out of Level 3	(1		)	—			—
Balance, end of period	$	43		$	79		$	32
Change in unrealized gains relating to instruments still held at end of period	$	(37	)	$	49		$	32


(1)	Does not include the decrease in fair value of $1 million related to the realized gains capitalized during the year ended December 31, 2016.

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. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances when our derivative instruments are in an asset position. Additionally, we evaluate our own ability to meet our commitments in instances where our derivative instruments are in a liability position. Our derivative instruments are subject to contractual provisions which provide for the unconditional right of set-off for all derivative assets and liabilities with a given counterparty in the event of default.

Interest Rate Derivatives

SPL had entered into interest rate swaps (“SPL Interest Rate Derivatives”) to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the credit facilities it entered into in June 2015 (the “2015 SPL Credit Facilities”), based on a portion of the expected outstanding borrowings over the term of the 2015 SPL Credit Facilities. In March 2017, SPL settled the SPL Interest Rate Derivatives and recognized a derivative loss of $7 million in conjunction with the termination of approximately $1.6 billion of commitments under the 2015 SPL Credit Facilities, as discussed in Note 12—Debt.

CCH has entered into interest rate swaps (“CCH Interest Rate Derivatives”) to protect against volatility of future cash flows and hedge a portion of the variable interest payments on its credit facility (the “2015 CCH Credit Facility”), based on a portion of the expected outstanding borrowings over the term of the 2015 CCH Credit Facility. In May 2017, CCH settled a portion of the CCH Interest Rate Derivatives and recognized a derivative loss of $13 million in conjunction with the termination of approximately $1.4 billion of commitments under the 2015 CCH Credit Facility, as discussed in Note 12—Debt.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Cheniere Partners has entered into interest rate swaps (“CQP Interest Rate Derivatives”) to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the 2016 CQP Credit Facilities, based on a portion of the expected outstanding borrowings over the term of the 2016 CQP Credit Facilities.

As of December 31, 2017, we 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

CQP Interest Rate Derivatives

$225 million

$1.3 billion

March 22, 2016

February 29, 2020

1.19%

One-month LIBOR

CCH Interest Rate Derivatives

$29 million

$4.9 billion

May 20, 2015

May 31, 2022

2.29%

One-month LIBOR

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



	December 31, 2017										December 31, 2016
	SPL Interest Rate Derivatives		CQP Interest Rate Derivatives		CCH Interest Rate Derivatives			Total			SPL Interest Rate Derivatives			CQP Interest Rate Derivatives			CCH Interest Rate Derivatives			Total
Balance Sheet Location
Derivative assets	$	—	$	7	$	—		$	7		$	—		$	—		$	—		$	—
Non-current derivative assets	—		14		3			17			—			16			—			16
Total derivative assets	—		21		3			24			—			16			—			16

Derivative liabilities	—		—		(20		)	(20		)	(4		)	(3		)	(43		)	(50		)
Non-current derivative liabilities	—		—		(15		)	(15		)	(2		)	—			(43		)	(45		)
Total derivative liabilities	—		—		(35		)	(35		)	(6		)	(3		)	(86		)	(95		)

Derivative asset (liability), net	$	—	$	21	$	(32	)	$	(11	)	$	(6	)	$	13		$	(86	)	$	(79	)

The following table shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in derivative gain (loss), net on our Consolidated Statements of Operations during the years ended December 31, 2017, 2016 and 2015 (in millions):



	Year Ended December 31,
	2017			2016			2015
SPL Interest Rate Derivatives loss	$	(2	)	$	(6	)	$	(42	)
CQP Interest Rate Derivatives gain	6			12			—
CCH Interest Rate Derivatives gain (loss)	3			(16		)	(162		)

Commodity Derivatives

Liquefaction Supply Derivatives

SPL and CCL have entered into index-based physical natural gas supply contracts and associated economic hedges, if applicable, to purchase natural gas for the commissioning and operation of the SPL Project and the CCL Project. The terms of the noncurrent physical natural gas supply contracts range from approximately one to seven years, most of which commence upon the satisfaction of certain conditions precedent, if not already met, such as the date of first commercial delivery of specified Trains of the SPL Project and the CCL Project.

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

LNG Trading Derivatives

We have entered into, and may from time to time enter into, financial LNG Trading Derivatives in the form of swaps, forwards, options or futures to economically hedge exposure to the commodity markets in which we have contractual arrangements to purchase or sell physical LNG. We have entered into LNG Trading Derivatives to secure a fixed price position to minimize future cash flow variability associated with LNG purchase and sale transactions.

The following table shows the fair value and location of our Liquefaction Supply Derivatives and LNG Trading Derivatives (collectively, “Commodity Derivatives”) on our Consolidated Balance Sheets (in millions, except notional amount):



	December 31, 2017									December 31, 2016
	Liquefaction Supply Derivatives (1)			LNG Trading Derivatives (2)			Total			Liquefaction Supply Derivatives (1)			LNG Trading Derivatives (2)			Total
Balance Sheet Location
Derivative assets	$	41		$	9		$	50		$	13		$	7		$	20
Non-current derivative assets	17			—			17			67			—			67
Total derivative assets	58			9			67			80			7			87

Derivative liabilities	—			(17		)	(17		)	(7		)	(10		)	(17		)
Non-current derivative liabilities	(3		)	—			(3		)	—			—			—
Total derivative liabilities	(3		)	(17		)	(20		)	(7		)	(10		)	(17		)

Derivative asset (liability), net	$	55		$	(8	)	$	47		$	73		$	(3	)	$	70

Notional amount (in TBtu) (3)	2,539			25						1,117			—


(1)	Does not include collateral call of $1 million and collateral deposit of $6 million for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of December 31, 2017 and 2016, respectively.


(2)	Does not include collateral of $28 million and $10 million deposited for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of December 31, 2017 and 2016, respectively.

(3)

SPL had secured up to approximately 2,214 TBtu and 1,994 TBtu of natural gas feedstock through natural gas supply contracts as of December 31, 2017 and 2016, respectively. CCL has secured up to approximately 2,024 TBtu and zero TBtu of natural gas feedstock through natural gas supply contracts, a portion of which is subject to the achievement of certain project milestones and other conditions precedent, as of December 31, 2017 and 2016, respectively.

The following table shows the changes in the fair value, settlements and location of our Commodity Derivatives recorded on our Consolidated Statements of Operations during the years ended December 31, 2017, 2016 and 2015 (in millions):



	Statement of Operations Location (1)	Year Ended December 31,
	Statement of Operations Location (1)	2017			2016			2015
LNG Trading Derivatives gain (loss)	LNG revenues	$	(44	)	$	(4	)	1
Liquefaction Supply Derivatives loss (gain) (2)	Cost (cost recovery) of sales	24			(42		)	(33	)


(1)	Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.


(2)	Does not include the realized value associated with derivative instruments that settle through physical delivery.

FX Derivatives

Cheniere Marketing has entered into FX Derivatives to protect against the volatility in future cash flows attributable to changes in international currency exchange rates. The FX Derivatives economically hedge the foreign currency exposure arising from cash flows expended for both physical and financial LNG transactions and selling, general and administrative expenses related to operations in countries outside of the United States.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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



		Fair Value Measurements as of
	Balance Sheet Location	December 31, 2017			December 31, 2016
FX Derivatives	Derivative assets	$	—		$	4
FX Derivatives	Derivative liabilities	—			(4		)
FX Derivatives	Non-current derivative liabilities	(1		)	—

The total notional amount of our FX Derivatives was $27 million and $11 million as of December 31, 2017 and 2016, respectively.

The following table shows the changes in the fair value of our FX Derivatives recorded on our Consolidated Statements of Operations during the years ended December 31, 2017, 2016 and 2015 (in millions):



		Year Ended December 31,
	Statement of Operations Location	2017			2016			2015
FX Derivatives loss	LNG revenues	$	(1	)	$	—		$	—
FX Derivatives loss	Other income	—			(1		)	—

Balance Sheet Presentation

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



	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
As of December 31, 2017
CQP Interest Rate Derivatives	$	21		$	—		$	21
CCH Interest Rate Derivatives	3			—			3
CCH Interest Rate Derivatives	(35		)	—			(35		)
Liquefaction Supply Derivatives	64			(6		)	58
Liquefaction Supply Derivatives	(3		)	—			(3		)
LNG Trading Derivatives	9			—			9
LNG Trading Derivatives	(37		)	20			(17		)
FX Derivatives	(1		)	—			(1		)
As of December 31, 2016
SPL Interest Rate Derivatives	$	(6	)	$	—		$	(6	)
CQP Interest Rate Derivatives	16			—			16
CQP Interest Rate Derivatives	(3		)	—			(3		)
CCH Interest Rate Derivatives	(95		)	9			(86		)
Liquefaction Supply Derivatives	82			(2		)	80
Liquefaction Supply Derivatives	(11		)	4			(7		)
LNG Trading Derivatives	21			(15		)	6
LNG Trading Derivatives	(17		)	8			(9		)
FX Derivatives	5			(1		)	4
FX Derivatives	(4		)	—			(4		)

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 8—OTHER NON-CURRENT ASSETS

As of December 31, 2017 and 2016, other non-current assets, net consisted of the following (in millions):



	December 31,
	2017		2016
Advances made under EPC and non-EPC contracts	$	26	$	69
Advances made to municipalities for water system enhancements	97		99
Advances and other asset conveyances to third parties to support LNG terminals	48		53
Tax-related payments and receivables	29		31
Equity method investments	64		10
Other	24		40
Total other non-current assets, net	$	288	$	302

Equity Method Investments

As of December 31, 2016, our equity method investments consisted of interests in privately-held companies. During the second quarter of 2017, we acquired an equity interest in Midship Holdings, LLC (“Midship Holdings”), which manages the business and affairs of Midship Pipeline Company, LLC (“Midship Pipeline”). Midship Pipeline is pursuing the development, construction, operation and maintenance of an approximately 230-mile natural gas pipeline project (the “Midship Project”) that connects new production in the Anadarko Basin to Gulf Coast markets. Midship Holdings entered into agreements with investment funds managed by EIG Global Energy Partners (“EIG”) under which EIG-managed funds committed to make an investment of up to $500 million (the “EIG Investment”) in the Midship Project, subject to the terms and conditions contained in the applicable agreements. The EIG Investment, when combined with equity contributed by us, is intended to ensure the Midship Project has the equity funding expected to be required to develop and construct the project. Midship Holdings requires acceptable financing arrangements and regulatory and other approvals before construction of the proposed Midship Project commences.

We have determined that Midship Holdings is a variable interest entity (“VIE”) because it is thinly capitalized at formation such that the total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support. We do not consolidate Midship Holdings because we do not have power to direct the activities that most significantly impact its economic performance. We continually monitor both consolidated and unconsolidated VIEs to determine if any events have occurred that could cause a change in our identification of a VIE or determination of the primary beneficiary to a VIE. We account for our investment in Midship Holdings under the equity method as we have the ability to exercise significant influence over the operating and financial policies of Midship Holdings through our non-controlling voting rights on its board of managers. Our investment in Midship Holdings at December 31, 2017 was $55 million. Obligations to make additional investments in Midship Holdings are not significant and we have not provided financial support to Midship Holdings beyond amounts contractually required.

Cheniere LNG O&M Services, LLC (“O&M Services”), our wholly owned subsidiary, provides the development, construction, operation and maintenance services associated with the Midship Project pursuant to agreements in which O&M Services receives an agreed upon fee and reimbursement of costs incurred. O&M Services recorded $3 million of income in other—related party during the year ended December 31, 2017 and $2 million of accounts receivable—related party as of December 31, 2017 for services provided to Midship Pipeline under these agreements. CCL has entered into transportation precedent agreements with Midship Pipeline to secure firm pipeline transportation capacity for a period of 10 years following commencement of the Midship Project.

NOTE 9—VARIABLE INTEREST ENTITIES

Cheniere Holdings

Cheniere Holdings is a limited liability company formed by us in 2013 to hold our Cheniere Partners limited partner interests. As of December 31, 2017 and 2016, we owned 82.7% and 82.6%, respectively, of Cheniere Holdings as well as the director voting share. The director voting share is the sole share entitled to vote in the election of Cheniere Holdings’ board of directors and allows us to remove members of the board of directors at any time and for any reason. If we cease to own greater than 25% of the common shares of Cheniere Holdings or if we choose to relinquish the director voting share, the director voting share will be extinguished.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

The board of directors makes all major operating and financial decisions on behalf of Cheniere Holdings. Because ownership of the director voting share allows us to control Cheniere Holdings, irrespective of our majority ownership interest, and the director voting share cannot be removed from our control by the other equity holders of Cheniere Holdings, we have determined that Cheniere Holdings is a variable interest entity. We consolidate Cheniere Holdings in our Consolidated Financial Statements as we have determined that we are its primary beneficiary.

Cheniere Partners

Cheniere Partners is a limited partnership formed by us in 2006 to own and operate the Sabine Pass LNG terminal and related assets. As a result of the mandatory conversion of Cheniere Partners’ Class B units (“Class B units”) on August 2, 2017, as of December 31, 2017, Cheniere Holdings owned a 48.6% limited partner interest in Cheniere Partners in the form of 104.5 million common units and 135.4 million subordinated units, with the remaining non-controlling interest held by Blackstone CQP Holdco LP (“Blackstone CQP Holdco”) and the public. Prior to the conversion, as of December 31, 2016, Cheniere Holdings owned a 55.9% limited partner interest in Cheniere Partners in the form of 12.0 million common units, 45.3 million Class B units and 135.4 million subordinated units, with the remaining non-controlling interest held by Blackstone CQP Holdco and the public. We also own 100% of the general partner interest and the incentive distribution rights in Cheniere Partners.

Cheniere Partners GP, our wholly owned subsidiary, is the general partner of Cheniere Partners. In 2012, Cheniere Partners, Cheniere and Blackstone CQP Holdco entered into a unit purchase agreement (the “Blackstone Unit Purchase Agreement”) whereby Cheniere Partners sold 100.0 million Class B units to Blackstone CQP Holdco in a private placement. The board of directors of Cheniere Partners GP was modified to include three directors appointed by Blackstone CQP Holdco, four directors appointed by us and four independent directors mutually agreed upon by Blackstone CQP Holdco and us and appointed by us. In addition, we provided Blackstone CQP Holdco with a right to maintain one board seat on our Board of Directors (our “Board”). A quorum of Cheniere Partners GP directors consists of a majority of all directors, including at least two directors appointed by Blackstone CQP Holdco, two directors appointed by us and two independent directors. Blackstone CQP Holdco will no longer be entitled to appoint Cheniere Partners GP directors in the event that Blackstone CQP Holdco’s ownership in Cheniere Partners is less than: (1) 20% of outstanding common units, subordinated units and Class B units and (2) 50.0 million Class B units.

As a result of contractual changes in the governance of Cheniere Partners GP in connection with the Blackstone Unit Purchase Agreement, we have determined that Cheniere Partners GP is a variable interest entity and that we, as the holder of the equity at risk, do not have a controlling financial interest due to the rights held by Blackstone CQP Holdco. However, we continue to consolidate Cheniere Partners as a result of Blackstone CQP Holdco’s right to maintain one board seat on our Board which creates a de facto agency relationship between Blackstone CQP Holdco and us. GAAP requires that when a de facto agency relationship exists, one of the members of the de facto agency relationship must consolidate the variable interest entity based on certain criteria. As a result, we consolidate Cheniere Partners in our Consolidated Financial Statements.

NOTE 10—NON-CONTROLLING INTEREST

Cheniere Holdings was formed by us in 2013 to hold our Cheniere Partners limited partner interests. As of December 31, 2017 and 2016, we owned 82.7% and 82.6%, respectively, of Cheniere Holdings as well as the director voting share, with the remaining non-controlling interest held by the public. In December 2016, we increased our ownership percentage of Cheniere Holdings by acquiring additional publicly-owned shares of Cheniere Holdings in exchange with unregistered shares of our common stock.

Our ownership of Cheniere Partners interests is further discussed in Note 9—Variable Interest Entity.

NOTE 11—ACCRUED LIABILITIES

As of December 31, 2017 and 2016, accrued liabilities consisted of the following (in millions):



	December 31,
	2017		2016
Interest costs and related debt fees	$	397	$	273
Compensation and benefits	141		56
LNG terminals and related pipeline costs	490		284
Other accrued liabilities	50		24
Total accrued liabilities	$	1,078	$	637

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 12—DEBT

As of December 31, 2017 and 2016, our debt consisted of the following (in millions):



	December 31,
	2017			2016
Long-term debt:
SPL
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”), net of unamortized premium of $6 and $7	$	2,006		$	2,007
6.25% Senior Secured Notes due 2022 (“2022 SPL Senior Notes”)	1,000			1,000
5.625% Senior Secured Notes due 2023 (“2023 SPL Senior Notes”), net of unamortized premium of $5 and $6	1,505			1,506
5.75% Senior Secured Notes due 2024 (“2024 SPL Senior Notes”)	2,000			2,000
5.625% Senior Secured Notes due 2025 (“2025 SPL Senior Notes”)	2,000			2,000
5.875% Senior Secured Notes due 2026 (“2026 SPL Senior Notes”)	1,500			1,500
5.00% Senior Secured Notes due 2027 (“2027 SPL Senior Notes”)	1,500			1,500
4.200% Senior Secured Notes due 2028 (“2028 SPL Senior Notes”), net of unamortized discount of $1 and zero	1,349			—
5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)	800			—
2015 SPL Credit Facilities	—			314
Cheniere Partners
5.250% Senior Notes due 2025 (“2025 CQP Senior Notes”)	1,500			—
2016 CQP Credit Facilities	1,090			2,560
CCH
7.000% Senior Secured Notes due 2024 (“2024 CCH Senior Notes”)	1,250			1,250
5.875% Senior Secured Notes due 2025 (“2025 CCH Senior Notes”)	1,500			1,500
5.125% Senior Secured Notes due 2027 (“2027 CCH Senior Notes”)	1,500			—
2015 CCH Credit Facility	2,485			2,381
CCH HoldCo II
11.0% Convertible Senior Notes due 2025 (“2025 CCH HoldCo II Convertible Senior Notes”)	1,305			1,171
Cheniere
4.875% Convertible Unsecured Notes due 2021 (“2021 Cheniere Convertible Unsecured Notes”), net of unamortized discount of $121 and $146	1,040			960
4.25% Convertible Senior Notes due 2045 (“2045 Cheniere Convertible Senior Notes”), net of unamortized discount of $314 and $317	311			308
$750 million Cheniere Revolving Credit Facility (“Cheniere Revolving Credit Facility”)	—			—
Unamortized debt issuance costs	(305		)	(269		)
Total long-term debt, net	25,336			21,688

Current debt:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	—			224
$350 million CCH Working Capital Facility (“CCH Working Capital Facility”)	—			—
Cheniere Marketing trade finance facilities	—			23
Total current debt	—			247

Total debt, net	$	25,336		$	21,935

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Below is a schedule of future principal payments that we are obligated to make, based on current construction schedules, on our outstanding debt at December 31, 2017 (in millions):



Years Ending December 31,	Principal Payments
2018	$	—
2019	55
2020	1,035
2021	3,161
2022	3,485
Thereafter	18,330
Total	$	26,066

Senior Notes

SPL Senior Notes

In February 2017, SPL issued an aggregate principal amount of $800 million of the 2037 SPL Senior Notes on a private placement basis in reliance on the exemption from registration provided for under Section 4(a)(2) of the Securities Act of 1933, as amended. In March 2017, SPL issued an aggregate principal amount of $1.35 billion, before discount, of the 2028 SPL Senior Notes. Net proceeds of the offerings of the 2037 SPL Senior Notes and the 2028 SPL Senior Notes were $789 million and $1.33 billion, respectively, after deducting the initial purchasers’ commissions (for the 2028 SPL Senior Notes) and estimated fees and expenses. The net proceeds of the 2037 SPL Senior Notes, after provisioning for incremental interest required during construction, were used to prepay the then outstanding borrowings of $369 million under the 2015 SPL Credit Facilities and, along with the net proceeds of the 2028 SPL Senior Notes, the remainder is being used to pay a portion of the capital costs in connection with the construction of Trains 1 through 5 of the SPL Project in lieu of the terminated portion of the commitments under the 2015 SPL Credit Facilities.

In connection with the issuance of the 2037 SPL Senior Notes and the 2028 SPL Senior Notes, SPL terminated the remaining available balance of $1.6 billion under the 2015 SPL Credit Facilities, resulting in a write-off of debt issuance costs associated with the 2015 SPL Credit Facilities of $42 million during the year ended December 31, 2017.

The terms of the 2021 SPL Senior Notes, 2022 SPL Senior Notes, 2023 SPL Senior Notes, 2024 SPL Senior Notes, 2025 SPL Senior Notes, 2026 SPL Senior Notes, 2027 SPL Senior Notes and 2028 SPL Senior Notes (collectively with the 2037 SPL Senior Notes, the “SPL Senior Notes”) are governed by a common indenture (the “SPL Indenture”) and the terms of the 2037 SPL Senior Notes are governed by a separate indenture (the “2037 SPL Senior Notes Indenture”). Both the SPL Indenture and the 2037 SPL Senior Notes Indenture contain 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 or issue preferred stock, make certain investments or pay dividends or distributions on capital stock or subordinated indebtedness or purchase, redeem or retire capital stock, sell or transfer assets, including capital stock of SPL’s restricted subsidiaries, restrict dividends or other payments by restricted subsidiaries, incur liens, enter into transactions with affiliates, dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of SPL’s assets and enter into certain LNG sales contracts. Subject to permitted liens, the SPL Senior Notes are secured on a pari passu first-priority basis by a security interest in all of the membership interests in SPL and substantially all of SPL’s assets. SPL may not make any distributions until, among other requirements, deposits are made into debt service reserve accounts as required and a debt service coverage ratio test of 1.25:1.00 is satisfied. Semi-annual principal payments for the 2037 SPL Senior Notes are due on March 15 and September 15 of each year beginning September 15, 2025. Interest on the SPL Senior Notes is payable semi-annually in arrears.

At any time prior to three months before the respective dates of maturity for each series of the SPL Senior Notes (except for the 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes and 2037 SPL Senior Notes, in which case the time period is six months before the respective dates of maturity), SPL may redeem all or part of such series of the SPL Senior Notes at a redemption price equal to the “make-whole” price (except for the 2037 SPL Senior Notes, in which case the redemption price is equal to the “optional redemption” price) set forth in the respective indentures governing the SPL Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. SPL may also, at any time within three months of the respective maturity dates for each series of the SPL Senior Notes (except for the 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes and 2037 SPL Senior Notes, in which case the time period is within six months of the respective dates of maturity),

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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.

2025 CQP Senior Notes

In September 2017, Cheniere Partners issued an aggregate principal amount of $1.5 billion of the 2025 CQP Senior Notes, which are jointly and severally guaranteed by each of Cheniere Partners’ subsidiaries other than SPL and, subject to certain conditions governing the release of its guarantee, Sabine Pass LNG-LP, LLC (collectively, the “CQP Guarantors”). Net proceeds of the offering of approximately $1.5 billion, after deducting the initial purchasers’ commissions and estimated fees and expenses, were used to prepay a portion of the outstanding indebtedness under the 2016 CQP Credit Facilities, resulting in a write-off of debt issuance costs associated with the 2016 CQP Credit Facilities of $25 million during the year ended December 31, 2017.

Borrowings under the 2025 CQP Senior Notes accrue interest at a fixed rate of 5.250%, and interest on the 2025 CQP Senior Notes is payable semi-annually in arrears. The 2025 CQP Senior Notes are governed by an indenture (the “CQP Indenture”), which contains customary terms and events of default and certain covenants that, among other things, limit the ability of Cheniere Partners and the CQP Guarantors to incur liens and sell assets, enter into transactions with affiliates, enter into sale-leaseback transactions and consolidate, merge or sell, lease or otherwise dispose of all or substantially all of the applicable entity’s properties or assets.

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

The 2025 CQP Senior Notes are Cheniere Partners’ senior obligations, ranking equally in right of payment with Cheniere Partners’ other existing and future unsubordinated debt and senior to any of its future subordinated debt. The 2025 CQP Senior Notes will be secured alongside the 2016 CQP Credit Facilities on a first-priority basis (subject to permitted encumbrances) with liens on (1) substantially all the existing and future tangible and intangible assets and rights of Cheniere Partners and the CQP Guarantors and equity interests in the CQP Guarantors (except, in each case, for certain excluded properties set forth in the 2016 CQP Credit Facilities) and (2) substantially all of the real property of SPLNG (except for excluded properties referenced in the 2016 CQP Credit Facilities). The liens securing the 2025 CQP Senior Notes would be released if (1) the aggregate principal amount of all indebtedness then outstanding under the term loans under the 2016 CQP Credit Facilities secured by such liens does not exceed $1.0 billion and (2) the aggregate amount of Cheniere Partners’ secured indebtedness and the secured indebtedness of the CQP Guarantors (other than the 2025 CQP Senior Notes or any other series of notes issued under the CQP Indenture) outstanding at any one time, together with all Attributable Indebtedness (as defined in the CQP Indenture) from sale-leaseback transactions (subject to certain exceptions), does not exceed the greater of (1) $1.5 billion and (2) 10% of net tangible assets. Upon the release of the liens securing the 2025 CQP Senior Notes, the limitation on liens covenant under the CQP Indenture will continue to govern the incurrence of liens by Cheniere Partners and the CQP Guarantors.

In connection with the closing of the sale of the 2025 CQP Senior Notes, Cheniere Partners and the CQP Guarantors entered into a registration rights agreement (the “CQP Registration Rights Agreement”). Under the CQP Registration Rights Agreement, Cheniere Partners and the CQP Guarantors have agreed to use commercially reasonable efforts to file with the SEC and cause to become effective a registration statement relating to an offer to exchange any and all of the 2025 CQP Senior Notes for a like aggregate principal amount of debt securities of Cheniere Partners with terms identical in all material respects to the 2025 CQP Senior Notes sought to be exchanged (other than with respect to restrictions on transfer or to any increase in annual interest rate), within 360 days after September 18, 2017. Under specified circumstances, Cheniere Partners and the CQP Guarantors have also agreed to use commercially reasonable efforts to cause to become effective a shelf registration statement relating to resales of the 2025 CQP Senior Notes. Cheniere Partners will be obligated to pay additional interest on the 2025 CQP Senior Notes if it fails to comply with its obligation to register the 2025 CQP Senior Notes within the specified time period.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

CCH Senior Notes

In May 2017, CCH issued an aggregate principal amount of $1.5 billion of the 2027 CCH Senior Notes. Net proceeds of the offering of approximately $1.4 billion, after deducting commissions, fees and expenses and provisioning for incremental interest required under the 2027 CCH Senior Notes during construction, were used to prepay a portion of the outstanding borrowings under the 2015 CCH Credit Facility, resulting in a write-off of debt issuance costs associated with the 2015 CCH Credit Facility of $33 million during the year ended December 31, 2017. Borrowings under the 2027 CCH Senior Notes accrue interest at a fixed rate of 5.125%.

The 2024 CCH Senior Notes, 2025 CCH Senior Notes and 2027 CCH Senior Notes (collectively, the “CCH Senior Notes”) are jointly and severally guaranteed by CCH’s subsidiaries, CCL, CCP and Corpus Christi Pipeline GP, LLC (the “CCH Guarantors”). The indenture governing the CCH Senior Notes (the “CCH Indenture”) contains customary terms and events of default and certain covenants that, among other things, limit CCH’s ability and the ability of CCH’s restricted subsidiaries to: incur additional indebtedness or issue preferred stock; make certain investments or pay dividends or distributions on membership interests or subordinated indebtedness or purchase, redeem or retire membership interests; sell or transfer assets, including membership or partnership interests of CCH’s restricted subsidiaries; restrict dividends or other payments by restricted subsidiaries to CCH or any of CCH’s restricted subsidiaries; incur liens; enter into transactions with affiliates; dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of the properties or assets of CCH and its restricted subsidiaries taken as a whole; or permit any CCH Guarantor to dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of its properties and assets. Interest on the CCH Senior Notes is payable semi-annually in arrears.

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

Credit Facilities

Below is a summary of our credit facilities outstanding as of December 31, 2017 (in millions):



	SPL Working Capital Facility		2016 CQP Credit Facilities		2015 CCH Credit Facility		CCH Working Capital Facility		Cheniere Revolving Credit Facility
Original facility size	$	1,200	$	2,800	$	8,404	$	350	$	750
Less:
Outstanding balance	—		1,090		2,485		—		—
Commitments prepaid or terminated	—		1,470		3,832		—		—
Letters of credit issued	730		20		—		164		—
Available commitment	$	470	$	220	$	2,087	$	186	$	750

Interest rate	LIBOR plus 1.75% or base rate plus 0.75%		LIBOR plus 2.25% or base rate plus 1.25% (1)		LIBOR plus 2.25% or base rate plus 1.25% (2)		LIBOR plus 1.50% - 2.00% or base rate plus 0.50% - 1.00%		LIBOR plus 3.25% or base rate plus 2.25%
Maturity date	December 31, 2020, with various terms for underlying loans		February 25, 2020, with principal payments due quarterly commencing on March 31, 2019		Earlier of May 13, 2022 or second anniversary of CCL Trains 1 and 2 completion date		December 14, 2021, with various terms for underlying loans		March 2, 2021


(1)	There is a 0.50% step-up for both LIBOR and base rate loans beginning on February 25, 2019.


(2)	There is a 0.25% step-up for both LIBOR and base rate loans following the completion of Trains 1 and 2 of the CCL Project as defined in the common terms agreement.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

SPL Working Capital Facility

In September 2015, SPL entered into the SPL Working Capital Facility, which is intended to be used for loans to SPL (“SPL Working Capital Loans”), the issuance of letters of credit on behalf of SPL, as well as for swing line loans to SPL (“SPL Swing Line Loans”), primarily for certain working capital requirements related to developing and placing into operation the SPL Project. SPL may, from time to time, request increases in the commitments under the SPL Working Capital Facility of up to $760 million and, upon the completion of the debt financing of Train 6 of the SPL Project, request an incremental increase in commitments of up to an additional $390 million.

Loans under the SPL Working Capital Facility accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of the senior facility agent’s published prime rate, the federal funds effective rate, as published by the Federal Reserve Bank of New York, plus 0.50% and one month LIBOR plus 0.50%), plus the applicable margin. The applicable margin for LIBOR loans under the SPL Working Capital Facility is 1.75% per annum, and the applicable margin for base rate loans under the SPL Working Capital Facility is 0.75% per annum. Interest on SPL Swing Line Loans and loans deemed made in connection with a draw upon a letter of credit (“SPL LC Loans”) is due and payable on the date the loan becomes due. Interest on LIBOR loans is due and payable at the end of each applicable LIBOR period, and interest on base rate loans is due and payable at the end of each fiscal quarter. However, if such base rate loan is converted into a LIBOR loan, interest is due and payable on that date. Additionally, if the loans become due prior to such periods, the interest also becomes due on that date.

SPL pays (1) a commitment fee equal to an annual rate of 0.70% on the average daily amount of the excess of the total commitment amount over the principal amount outstanding without giving effect to any outstanding SPL Swing Line Loans and (2) a letter of credit fee equal to an annual rate of 1.75% of the undrawn portion of all letters of credit issued under the SPL Working Capital Facility. If draws are made upon a letter of credit issued under the SPL Working Capital Facility and SPL does not elect for such draw (an “SPL LC Draw”) to be deemed an SPL LC Loan, SPL is required to pay the full amount of the SPL LC Draw on or prior to the business day following the notice of the SPL LC Draw. An SPL LC Draw accrues interest at an annual rate of 2.0% plus the base rate. As of December 31, 2017, no SPL LC Draws had been made upon any letters of credit issued under the SPL Working Capital Facility.

The SPL Working Capital Facility matures on December 31, 2020, and the outstanding balance may be repaid, in whole or in part, at any time without premium or penalty upon three business days’ notice. SPL LC Loans have a term of up to one year. SPL Swing Line Loans terminate upon the earliest of (1) the maturity date or earlier termination of the SPL Working Capital Facility, (2) the date 15 days after such SPL Swing Line Loan is made and (3) the first borrowing date for a SPL Working Capital Loan or SPL Swing Line Loan occurring at least three business days following the date the SPL Swing Line Loan is made. SPL is required to reduce the aggregate outstanding principal amount of all SPL Working Capital Loans to zero for a period of five consecutive business days at least once each year.

The SPL Working Capital Facility contains conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. The obligations of SPL under the SPL Working Capital Facility 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.

2016 CQP Credit Facilities

In February 2016, Cheniere Partners entered into the 2016 CQP Credit Facilities. The 2016 CQP Credit Facilities consist of: (1) a $450 million CTPL tranche term loan that was used to prepay the $400 million term loan facility (the “CTPL Term Loan”) in February 2016, (2) an approximately $2.1 billion SPLNG tranche term loan that was used to repay and redeem the approximately $2.1 billion of the senior notes previously issued by SPLNG in November 2016, (3) a $125 million debt service reserve credit facility (the “DSR Facility”) that may be used to satisfy a six-month debt service reserve requirement and (4) a $115 million revolving credit facility that may be used for general business purposes. In September 2017, Cheniere Partners issued the 2025 CQP Senior Notes and the net proceeds of the issuance were used to prepay $1.5 billion of the outstanding indebtedness under the 2016 CQP Credit Facilities.

The 2016 CQP Credit Facilities accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of the prime rate, the federal funds effective rate, as published by the Federal Reserve Bank of New York, plus 0.50% and adjusted one month LIBOR plus 1.0%), plus the applicable margin. The applicable margin for LIBOR loans is 2.25% per annum, and the applicable margin for base rate loans is 1.25% per annum, in each case with a 0.50% step-up beginning on February 25, 2019. Interest on LIBOR loans is due and payable at the end of each applicable LIBOR period (and at the end of every three

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

month period within the LIBOR period, if any), and interest on base rate loans is due and payable at the end of each calendar quarter.

Cheniere Partners pays a commitment fee equal to an annual rate of 40% of the margin for LIBOR loans multiplied by the average daily amount of the undrawn commitment, payable quarterly in arrears. The DSR Facility and the revolving credit facility are both available for the issuance of letters of credit, which incur a fee equal to an annual rate of 2.25% of the undrawn portion with a 0.50% step-up beginning on February 25, 2019.

The 2016 CQP Credit Facilities mature on February 25, 2020, with principal payments due quarterly commencing on March 31, 2019. The outstanding balance may be repaid, in whole or in part, at any time without premium or penalty, except for interest hedging and interest rate breakage costs. The 2016 CQP Credit Facilities contain conditions precedent for extensions of credit, as well as customary affirmative and negative covenants and limit Cheniere Partners’ ability to make restricted payments, including distributions, to once per fiscal quarter as long as certain conditions are satisfied. Under the 2016 CQP Credit Facilities, Cheniere Partners is required to hedge not less than 50% of the variable interest rate exposure on its projected aggregate outstanding balance, maintain a minimum debt service coverage ratio of at least 1.15x at the end of each fiscal quarter beginning March 31, 2019 and have a projected debt service coverage ratio of 1.55x in order to incur additional indebtedness to refinance a portion of the existing obligations.

The 2016 CQP Credit Facilities are unconditionally guaranteed by each subsidiary of Cheniere Partners other than (1) SPL and (2) certain subsidiaries of Cheniere Partners owning other development projects, as well as certain other specified subsidiaries and members of the foregoing entities.

2015 CCH Credit Facility

In May 2015, CCH entered into the 2015 CCH Credit Facility, which is being used to fund a portion of the costs associated with the development, construction, operation and maintenance of Stage 1 of the CCL Project. Borrowings under the 2015 CCH Credit Facility may be refinanced, in whole or in part, at any time without premium or penalty; however, interest rate hedging and interest rate breakage costs may be incurred.

The principal of the loans made under the 2015 CCH Credit Facility must be repaid in quarterly installments, commencing on the earlier of (1) the first quarterly payment date occurring more than three calendar months following project completion and (2) a set date determined by reference to the date under which a certain LNG buyer linked to Train 2 of the CCL Project is entitled to terminate its SPA for failure to achieve the date of first commercial delivery for that agreement. Scheduled repayments will be based upon a 19-year tailored amortization, commencing the first full quarter after the project completion and designed to achieve a minimum projected fixed debt service coverage ratio of 1.55:1.

Loans under the 2015 CCH Credit Facility accrue interest at a variable rate per annum equal to, at CCH’s election, LIBOR or the base rate, plus the applicable margin. The applicable margins for LIBOR loans are 2.25% prior to completion of Trains 1 and 2 of the CCL Project and 2.50% on completion and thereafter. The applicable margins for base rate loans are 1.25% prior to completion of Trains 1 and 2 of the CCL Project and 1.50% on completion and thereafter. Interest on LIBOR loans is due and payable at the end of each applicable interest period and interest on base rate loans is due and payable at the end of each quarter. The 2015 CCH Credit Facility also requires CCH to pay a commitment fee at a rate per annum equal to 40% of the margin for LIBOR loans, multiplied by the outstanding undrawn debt commitments.

The obligations of CCH under the 2015 CCH Credit Facility are secured by a first priority lien on substantially all of the assets of CCH and its subsidiaries and by a pledge by CCH HoldCo I of its limited liability company interests in CCH.

Under the 2015 CCH Credit Facility, CCH is required to hedge not less than 65% of the variable interest rate exposure of its senior secured debt. CCH is restricted from making distributions under agreements governing its indebtedness generally until, among other requirements, the completion of the construction of Trains 1 and 2 of the CCL Project, funding of a debt service reserve account equal to six months of debt service and achieving a historical debt service coverage ratio and fixed projected debt service coverage ratio of at least 1.25:1.00.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

CCH Working Capital Facility

In December 2016, CCH entered into the $350 million CCH Working Capital Facility, which is intended to be used for loans to CCH (“CCH Working Capital Loans”), the issuance of letters of credit on behalf of CCH, as well as for swing line loans to CCH (“CCH Swing Line Loans”) for certain working capital requirements related to developing and placing into operation the CCL Project. Loans under the CCH Working Capital Facility are guaranteed by the CCH Guarantors. CCH may, from time to time, request increases in the commitments under the CCH Working Capital Facility of up to the maximum allowed under the Common Terms Agreement that was entered into concurrently with the 2015 CCH Credit Facility.

Loans under the CCH Working Capital Facility, including CCH Working Capital Loans, CCH Swing Line Loans and loans made in connection with a draw upon any letter of credit (“CCH LC Loans” and collectively, the “Revolving Loans”) accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of (1) the federal funds rate, plus 0.50%, (2) the prime rate and (3) one month LIBOR plus 0.50%), plus the applicable margin. The applicable margin for LIBOR Revolving Loans ranges from 1.50% to 2.00% per annum, and the applicable margin for base rate Revolving Loans ranges from 0.50% to 1.00% per annum. Interest on CCH Working Capital Loans, CCH Swing Line Loans and CCH LC Loans is due and payable on the date the loan becomes due. Interest on LIBOR Revolving Loans is due and payable at the end of each LIBOR period, and interest on base rate Revolving Loans is due and payable at the end of each quarter.

CCH pays (1) a commitment fee equal to an annual rate of 40% of the applicable margin for LIBOR Revolving Loans on the average daily amount of the excess of the total commitment amount over the principal amount outstanding without giving effect to any outstanding CCH Swing Line Loans, (2) a letter of credit fee equal to an annual rate equal to the applicable margin for LIBOR Revolving Loans on the undrawn portion of all letters of credit issued under the CCH Working Capital Facility and (3) a letter of credit fronting fee equal to an annual rate of 0.20% of the undrawn portion of all letters of credit. Each of these fees is payable quarterly in arrears.

If draws are made upon a letter of credit issued under the CCH Working Capital Facility and CCH does not elect for such draw (a “CCH LC Draw”) to be deemed a CCH LC Loan, CCH is required to pay the full amount of the CCH LC Draw on or prior to the business day following the notice of the CCH LC Draw. A CCH LC Draw accrues interest at an annual rate of 2.00% plus the base rate.

The CCH Working Capital Facility matures on December 14, 2021, and CCH may prepay the Revolving Loans at any time without premium or penalty upon three business days’ notice and may re-borrow at any time. CCH LC Loans have a term of up to one year. CCH Swing Line Loans terminate upon the earliest of (1) the maturity date or earlier termination of the CCH Working Capital Facility, (2) the date that is 15 days after such CCH Swing Line Loan is made and (3) the first borrowing date for a CCH Working Capital Loan or CCH Swing Line Loan occurring at least four business days following the date the CCH Swing Line Loan is made. CCH is required to reduce the aggregate outstanding principal amount of all CCH Working Capital Loans to zero for a period of five consecutive business days at least once each year.

The CCH Working Capital Facility contains conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. The obligations of CCH under the CCH Working Capital Facility are secured by substantially all of the assets of CCH and the CCH Guarantors as well as all of the membership interests in CCH and each of the CCH Guarantors on a pari passu basis with the CCH Senior Notes and the 2015 CCH Credit Facility.

Cheniere Revolving Credit Facility

In March 2017, we entered into the Cheniere Revolving Credit Facility that may be used to fund, through loans and letters of credit, equity capital contributions to CCH HoldCo II and its subsidiaries for the development of the CCL Project and, provided that certain conditions are met, for general corporate purposes. No advances or letters of credit under the Cheniere Revolving Credit Facility were available until either (1) Cheniere’s unrestricted cash and cash equivalents are less than $500 million or (2) Train 4 of the SPL Project has achieved substantial completion. We incurred $16 million of debt issuance costs related to the Cheniere Revolving Credit Facility during the year ended December 31, 2017.

Loans under the Cheniere Revolving Credit Facility accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of (1) the prime rate, (2) the federal funds rate plus 0.50% and (3) one month LIBOR plus 1.00%), plus the applicable margin. The applicable margin for LIBOR loans is 3.25% per annum, and the applicable margin for base rate loans is 2.25% per annum. Interest on LIBOR loans is due and payable at the end of each LIBOR period, and interest on base rate loans

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

is due and payable at the end of each calendar quarter. We will also pay (1) a commitment fee on the average daily amount of undrawn commitments at an annual rate of 0.75%, payable quarterly in arrears and (2) a letter of credit fee at an annual rate equal to the applicable margin for LIBOR loans on the undrawn portion of all letters of credit issued under the Cheniere Revolving Credit Facility. Draws on any letters of credit will accrue interest at an annual rate equal to the base rate plus 2.0%.

The Cheniere Revolving Credit Facility matures on March 2, 2021 and contains representations, warranties and affirmative and negative covenants customary for companies like Cheniere with lenders of the type participating in the Cheniere Revolving Credit Facility that limit our ability to make restricted payments, including distributions, unless certain conditions are satisfied, as well as limitations on indebtedness, guarantees, hedging, liens, investments and affiliate transactions. Under the Cheniere Revolving Credit Facility, we are required to ensure that the sum of our unrestricted cash and the amount of undrawn commitments under the Cheniere Revolving Credit Facility is at least equal to the lesser of (1) 20% of the commitments under the Cheniere Revolving Credit Facility and (2) $100 million.

The Cheniere Revolving Credit Facility is secured by a first priority security interest (subject to permitted liens and other customary exceptions) in substantially all of our assets, including our interests in our direct subsidiaries (excluding CCH HoldCo II).

Convertible Notes

Below is a summary of our convertible notes outstanding as of December 31, 2017 (in millions):



	2021 Cheniere Convertible Unsecured Notes			2025 CCH HoldCo II Convertible Senior Notes			2045 Cheniere Convertible Senior Notes
Aggregate original principal	$	1,000		$	1,000		$	625
Debt component, net of discount	$	1,040		$	1,305		$	311
Equity component	$	206		$	—		$	194
Maturity date	May 28, 2021			March 1, 2025			March 15, 2045
Contractual interest rate	4.875		%	11.0		%	4.25		%
Effective interest rate (1)	8.3		%	11.9		%	9.4		%
Remaining debt discount and debt issuance costs amortization period (2)	3.4 years			2.8 years			27.2 years


(1)	Rate to accrete the discounted carrying value of the convertible notes to the face value over the remaining amortization period.


(2)	We amortize any debt discount and debt issuance costs using the effective interest over the period through contractual maturity except for the 2025 CCH HoldCo II Convertible Senior Notes, which are amortized through the date they are first convertible by holders into our common stock.

2021 Cheniere Convertible Unsecured Notes

In November 2014, we issued the 2021 Cheniere Convertible Unsecured Notes on a private placement basis in reliance on the exemption from registration provided for under section 4(a)(2) of the Securities Act and Regulation S promulgated thereunder. The 2021 Cheniere Convertible Unsecured Notes accrue interest at a rate of 4.875% per annum, which is payable in kind semi-annually in arrears by increasing the principal amount of the 2021 Cheniere Convertible Unsecured Notes outstanding. Beginning one year after the closing date, the 2021 Cheniere Convertible Unsecured Notes will be convertible at the option of the holder into our common stock at the then applicable conversion rate, provided that the closing price of our common stock is greater than or equal to the conversion price on the conversion date. The initial conversion price was $93.64 and is subject to adjustment upon the occurrence of certain specified events. We have the option to satisfy the conversion obligation with cash, common stock or a combination thereof.

Under GAAP, certain convertible debt instruments that may be settled in cash upon conversion are required to be separately accounted for as liability (debt) and equity (conversion option) components of the instrument in a manner that reflects the issuer’s non-convertible debt borrowing rate. We determined that the fair value of the debt component was $809 million and the residual value of the equity component was $191 million as of the issuance date. As of December 31, 2017 and 2016, the carrying value of the equity component was $206 million and $205 million, respectively. The debt component is accreted to the total principal amount due at maturity by amortizing the debt discount. The effective rate of interest to amortize the debt discount was

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

approximately 8.3% as of both December 31, 2017 and 2016. As of December 31, 2017, the if-converted value of the 2021 Cheniere Convertible Unsecured Notes did not exceed the principal balance.

2025 CCH HoldCo II Convertible Senior Notes

In May 2015, CCH HoldCo II issued the 2025 CCH HoldCo II Convertible Senior Notes on a private placement basis in reliance on the exemption from registration provided for under section 4(a)(2) of the Securities Act. The 2025 CCH HoldCo II Convertible Senior Notes were issued pursuant to the amended and restated note purchase agreement entered into among CCH HoldCo II, EIG Management Company, LLC, The Bank of New York Mellon, us and the note purchasers. The $1.0 billion principal of the 2025 CCH HoldCo II Convertible Senior Notes will be used to partially fund costs associated with Stage 1 of the CCL Project. The 2025 CCH HoldCo II Convertible Senior Notes bear interest at a rate of 11.0% per annum, which is payable quarterly in arrears. Prior to the substantial completion of Train 2 of the CCL Project, interest on the 2025 CCH HoldCo II Convertible Senior Notes will be paid entirely in kind. Following this date, the interest generally must be paid in cash; however, a portion of the interest may be paid in kind under certain specified circumstances. The 2025 CCH HoldCo II Convertible Senior Notes are secured by a pledge by us of 100% of the equity interests in CCH HoldCo II, and a pledge by CCH HoldCo II of 100% of the equity interests in CCH HoldCo I.

At CCH HoldCo II’s option, the outstanding 2025 CCH HoldCo II Convertible Senior Notes are convertible into our common stock, provided the total market capitalization of Cheniere at that time is not less than $10.0 billion, on or after the later of (1) 58 months from May 1, 2015 and (2) the substantial completion of Train 2 of the CCL Project (the “Eligible Conversion Date”). The conversion price for 2025 CCH HoldCo II Convertible Senior Notes converted at CCH HoldCo II’s option is the lower of (1) a 10% discount to the average of the daily volume-weighted average price (“VWAP”) of our common stock for the 90 trading day period prior to the date on which notice of conversion is provided and (2) a 10% discount to the closing price of our common stock on the trading day preceding the date on which notice of conversion is provided. At the option of the holders, the 2025 CCH HoldCo II Convertible Senior Notes are convertible on or after the six-month anniversary of the Eligible Conversion Date, provided the total market capitalization of Cheniere at that time is not less than $10.0 billion, at a conversion price equal to the average of the daily VWAP of our common stock for the 90 trading day period prior to the date on which notice of conversion is provided. Conversions are also subject to various limitations and conditions.

CCH HoldCo II is restricted from making distributions to Cheniere under agreements governing its indebtedness generally until, among other requirements, Trains 1 and 2 of the CCL Project are in commercial operation and a historical debt service coverage ratio and a projected fixed debt services coverage ratio of 1.20:1.00 are achieved.

2045 Cheniere Convertible Senior Notes

In March 2015, we issued the 2045 Cheniere Convertible Senior Notes to certain investors through a registered direct offering. The 2045 Cheniere Convertible Senior Notes were issued with an original issue discount of 20% and accrue interest at a rate of 4.25% per annum, which is payable semi-annually in arrears. We have the right, at our option, at any time after March 15, 2020, to redeem all or any part of the 2045 Cheniere Convertible Senior Notes at a redemption price payable in cash equal to the accreted amount of the 2045 Cheniere Convertible Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to such redemption date. The conversion rate will initially equal 7.2265 shares of our common stock per $1,000 principal amount of the 2045 Cheniere Convertible Senior Notes, which corresponds to an initial conversion price of approximately $138.38 per share of our common stock. The conversion rate is subject to adjustment upon the occurrence of certain specified events. We have the option to satisfy the conversion obligation with cash, common stock or a combination thereof.

We determined that the fair value of the debt component of the 2045 Cheniere Convertible Senior Notes was $304 million and the residual value of the equity component was $196 million as of the issuance date, excluding debt issuance costs. As of both December 31, 2017 and 2016, the carrying value of the equity component, net of debt issuance costs, was $194 million. The debt component is accreted to the total principal amount due at maturity by amortizing the debt discount. The effective rate of interest to amortize the debt discount was approximately 9.4% as of both December 31, 2017 and 2016. As of December 31, 2017, the if-converted value of the 2045 Cheniere Convertible Senior Notes did not exceed the principal balance.

Restrictive Debt Covenants

As of December 31, 2017, each of our issuers was in compliance with all covenants related to their respective debt agreements.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Interest Expense

Total interest expense, including interest expense related to our convertible notes, consisted of the following (in millions):



	Year Ended December 31,
	2017			2016			2015
Interest cost on convertible notes:
Interest per contractual rate	$	219		$	202		$	146
Amortization of debt discount	29			31			28
Amortization of debt issuance costs	7			5			3
Total interest cost related to convertible notes	255			238			177
Interest cost on debt excluding convertible notes	1,271			1,063			820
Total interest cost	1,526			1,301			997
Capitalized interest	(779		)	(813		)	(675		)
Total interest expense, net	$	747		$	488		$	322

Fair Value Disclosures

The following table shows the carrying amount and estimated fair value of our debt (in millions):



	December 31, 2017				December 31, 2016
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes, net of premium or discount (1)	$	18,610	$	20,075	$	14,263	$	15,210
2037 SPL Senior Notes (2)	800		871		—		—
Credit facilities (3)	3,575		3,575		5,502		5,502
2021 Cheniere Convertible Unsecured Notes, net of discount (2)	1,040		1,136		960		983
2025 CCH HoldCo II Convertible Senior Notes (2)	1,305		1,535		1,171		1,328
2045 Cheniere Convertible Senior Notes, net of discount (4)	311		447		308		375

(1)

Includes 2021 SPL Senior Notes, 2022 SPL Senior Notes, 2023 SPL Senior Notes, 2024 SPL Senior Notes, 2025 SPL Senior Notes, 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes, 2025 CQP Senior Notes, 2024 CCH Senior Notes, 2025 CCH Senior Notes and 2027 CCH Senior Notes. The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.


(2)	The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including our stock price and interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market.

(3)

Includes 2015 SPL Credit Facilities, SPL Working Capital Facility, 2016 CQP Credit Facilities, 2015 CCH Credit Facility, CCH Working Capital Facility, Cheniere Revolving Credit Facility and Cheniere Marketing trade finance facilities. The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.


(4)	The Level 1 estimated fair value was based on unadjusted quoted prices in active markets for identical liabilities that we had the ability to access at the measurement date.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 13—REVENUES FROM CONTRACTS WITH CUSTOMERS

The following table represents a disaggregation of revenue earned from contracts with customers during the years ended December 31, 2017, 2016 and 2015 (in millions):



	Year Ended December 31,
	2017			2016		2015
LNG revenues	$	5,342		$	1,015	$	—
Regasification revenues	260			259		259
Other revenues (losses)	21			8		(2		)
Other—related party	3			—		—
Total revenues from customers	5,626			1,282		257
Revenues (losses) from derivative instruments	(25		)	1		14
Total revenues	$	5,601		$	1,283	$	271

LNG Revenues

We have entered into numerous SPAs with third party customers for the sale of LNG on a Free on Board (“FOB”) (delivered to the customer at either the Sabine Pass or Corpus Christi LNG terminal) or Delivered at Terminal (“DAT”) (delivered to the customer at their LNG receiving terminal) basis. Our customers generally purchase LNG for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG equal to approximately 115% of Henry Hub. The fixed fee component is the amount payable to us regardless of a cancellation or suspension of LNG cargo deliveries by the customers. The variable fee component is the amount generally payable to us only upon delivery of LNG plus all future adjustments to the fixed fee 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 generally commences upon the date of first commercial delivery of a specified Train.

We intend to primarily use LNG sourced from our Sabine Pass or Corpus Christi terminal to provide contracted volumes to our customers. However, we supplement this LNG with volumes procured from third parties. We recognized $981 million, $236 million and zero in LNG revenues from LNG that was procured from third parties for the years ended December 31, 2017, 2016 and 2015, respectively.

Revenues from the sale of LNG are recognized at a point in time when the LNG is delivered to the customer, either at the Sabine Pass LNG terminal or at the customer’s LNG receiving terminal, based on the terms of the contract, which is the point legal title, physical possession and the risks and rewards of ownership transfer to the customer. Each individual molecule of LNG is viewed as a separate performance obligation. The stated contract price (including both fixed and variable fees) per MMBtu in each LNG sales arrangement is representative of the stand-alone selling price for LNG at the time the sale was negotiated. We have concluded that the variable fees meet the optional exception for allocating variable consideration. As such, the variable consideration for these contracts is allocated to each distinct molecule of LNG and recognized when that distinct molecule of LNG is delivered to the customer. Because of the use of the optional exception, variable consideration related to the sale of LNG is also not included in the transaction price.

When we sell LNG on a DAT basis, we consider all transportation costs, including vessel chartering, loading/unloading and canal fees, as fulfillment costs and not as separate services provided to the customer within the arrangement, regardless of whether or not such activities occur prior to, or after, the customer obtains control of the LNG. We expense fulfillment costs as incurred unless otherwise dictated by GAAP.

Fees received pursuant to SPAs are recognized as LNG revenues only after substantial completion of the respective Train. Prior to substantial completion, sales generated during the commissioning phase are offset against the cost of construction for the respective Train, as the production and removal of LNG from storage is necessary to test the facility and bring the asset to the condition necessary for its intended use.

Regasification Revenues

The Sabine Pass LNG terminal has operational regasification capacity of approximately 4.0 Bcf/d. Approximately 2.0 Bcf/d of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term TUAs with unaffiliated third-party customers, under which they are required to pay fixed monthly fees regardless of their use of the LNG terminal. Each

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

of the customers has reserved approximately 1.0 Bcf/d of regasification capacity. The customers are each obligated to make monthly capacity payments to SPLNG aggregating approximately $125 million annually for 20 years that commenced in 2009, which is representative of fixed consideration in the contract. A portion of this fee is adjusted annually for inflation which is considered variable consideration. The remaining capacity of the Sabine Pass LNG terminal has been reserved by SPL, for which the associated revenues are eliminated in consolidation.

Because SPLNG is continuously available to provide regasification service on a daily basis with the same pattern of transfer, we have concluded that SPLNG provides a single performance obligation to its customers on a continuous basis over time. We have determined that an output method of recognition based on elapsed time best reflects the benefits of this service to the customer and accordingly, LNG regasification capacity reservation fees are recognized as regasification revenues on a straight-line basis over the term of the respective TUAs. We have concluded that the inflation element within the contract meets the optional exception for allocating variable consideration and accordingly the inflation adjustment is not included in the transaction price and will be recognized over the year in which the inflation adjustment relates on a straight-line basis.

In 2012, SPL entered into a partial TUA assignment agreement with Total Gas & Power North America, Inc. (“Total”), whereby SPL would progressively gain access to Total’s capacity and other services provided under its TUA with SPLNG. This agreement provides SPL with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity, permit SPL to more flexibly manage its LNG storage capacity and accommodate the development of Trains 5 and 6.

Upon substantial completion of Train 3, which was in June 2017, SPL gained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG. Upon substantial completion of Train 5, SPL will gain access to substantially all of Total’s capacity. Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA and we continue to recognize the payments received from Total as revenue. During the year ended December 31, 2017, SPL recorded $23 million as operating and maintenance expense under this partial TUA assignment agreement.

Deferred Revenue Reconciliation

The following table reflects the changes in our contract liabilities, which we classify as “Deferred revenue” and “Noncurrent deferred revenue” on our Consolidated Balance Sheets (in millions):



	Year Ended December 31,
	2017			2016			2015
Deferred revenues, beginning of period	$	78		$	36		$	40
Cash received but not yet recognized	110			71			25
Revenue recognized from prior period deferral	(76		)	(29		)	(29		)
Deferred revenues, end of period	$	112		$	78		$	36

We record deferred revenue when we receive consideration, or such consideration is unconditionally due from a customer, prior to transferring goods or services to the customer under the terms of a sales contract. Changes in deferred revenue during the years ended December 31, 2017 and 2016 are primarily attributable to differences between the timing of revenue recognition and the receipt of advance payments related to delivery of LNG under certain SPAs. Changes in deferred revenue during the years ended December 31, 2017, 2016 and 2015 are also attributable to differences between the timing of revenue recognition and the receipt of advance payments under our TUAs.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Transaction Price Allocated to Future Performance Obligations

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of December 31, 2017:


(1)	The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.

We have elected the following optional exemptions which omit certain potential future sources of revenue from the table above:


(1)	We omit from the table above all performance obligations that are part of a contract that has an original expected duration of one year or less.

(2)

We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The table above excludes all variable consideration under our SPAs and TUAs. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. The receipt of such variable consideration is considered constrained due to the uncertainty of ultimate pricing and receipt and we have not included such variable consideration in the transaction price. During the year ended December 31, 2017, approximately 56% of our LNG Revenues from contracts with a duration of over one year and approximately 2% of our Regasification Revenues were related to variable consideration received from customers.

We have entered into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching FID on a certain liquefaction Train or obtaining financing. These contracts are considered completed contracts for revenue recognition purposes and are included in the transaction price above when the conditions are considered probable of being met.

We have elected the practical expedient to omit the disclosure of the transaction price allocated to future performance obligations and an explanation of when the entity expects to recognize the amount as revenue as of December 31, 2016.

NOTE 14—RESTRUCTURING EXPENSE

During 2015 and 2016, we initiated and implemented certain organizational changes to simplify our corporate structure, improve our operational efficiencies and implement a strategy for sustainable, long-term stockholder value creation through financially disciplined development, construction, operation and investment. These organizational initiatives were completed as of the first quarter of 2017. As a result of these efforts, we recorded $6 million, $61 million and $61 million during the years ended December 31, 2017, 2016 and 2015, respectively, of restructuring charges and other costs associated with restructuring and operational efficiency initiatives for which the majority of these charges required cash expenditure. Included in these amounts were $3 million, $47 million and $58 million for share-based compensation during the years ended December 31, 2017, 2016 and 2015, respectively. All charges were recorded within the line item entitled “restructuring expense” on our Consolidated Statements of Operations and substantially all related to severance and other employee-related costs. As of December 31, 2016, we had $6 million of accrued restructuring charges and other costs that were recorded as part of accrued liabilities on our Consolidated Balance Sheets.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 15—INCOME TAXES

Income tax benefit (provision) included in our reported net loss consisted of the following (in millions):



	Year Ended December 31,
	2017			2016			2015
Current:
Federal	$	—		$	—		$	—
State	—			—			—
Foreign	(6		)	—			(2		)
Total current	(6		)	—			(2		)

Deferred:
Federal	—			—			—
State	—			—			—
Foreign	3			(2		)	2
Total deferred	3			(2		)	2
Total income tax provision	$	(3	)	$	(2	)	$	—

The reconciliation of the federal statutory income tax rate to our effective income tax rate is as follows:



	Year Ended December 31,
	2017		2016		2015
U.S. federal statutory tax rate	35.0	%	35.0	%	35.0	%
Non-controlling interest	2.9	%	(2.1	)%	(2.3	)%
State tax rate	(0.2	)%	1.8	%	1.9	%
U.S. tax reform rate change	71.4	%	—	%	—	%
Share-based compensation	(6.2	)%	—	%	—	%
Nondeductible interest expense	8.5	%	(6.6	)%	(2.6	)%
Other	(1.2	)%	(0.9	)%	(1.8	)%
Valuation allowance	(109.7	)%	(27.5	)%	(30.1	)%
Effective tax rate	0.5	%	(0.3	)%	0.1	%

Significant components of our deferred tax assets and liabilities at December 31, 2017 and 2016 are as follows (millions):



	December 31,
	2017			2016
Deferred tax assets
Net operating loss carryforwards and credits
Federal and foreign	$	960		$	1,060
State	188			183
Deferred gain	46			77
Share-based compensation expense	16			53
Derivative instruments	15			47
Long-term debt	16			18
Other	30			13
Less: valuation allowance	(806		)	(1,252		)
Total deferred tax assets	465			199

Deferred tax liabilities
Investment in limited partnership	(391		)	(76		)
Convertible debt	(65		)	(118		)
Property, plant and equipment	(6		)	(5		)
Total deferred tax liabilities	(462		)	(199		)

Net deferred tax assets	$	3		$	—

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

The federal deferred tax assets presented above do not include the state tax benefits as our net deferred state tax assets are offset with a full valuation allowance.

Effective January 1, 2017, we adopted ASU 2016-09 which requires excess tax benefits or deficiencies for share-based payments to be recognized as income tax expense or benefit in the period shares vest rather than within equity. The adoption of ASU 2016-09 may result in future volatility of our income tax expense (as the future tax effects of share-based awards will be dependent on the price of our common stock at the time of settlement). Excess tax benefits reduced our effective tax rate by 6.2% for the period ending December 31, 2017.

On December 22, 2017, the U.S. government enacted comprehensive tax legislation (Tax Cuts and Jobs Act), which reduced the top U.S. corporate income tax rate from 35% to 21%. As a result of the legislation, we remeasured our December 31, 2017 U.S. deferred tax assets and liabilities. The result of the remeasurement was a $404 million reduction to our U.S. net deferred tax assets and represents a 71.4% increase to our effective tax rate. A corresponding change, reducing the effective tax rate, was recorded to the valuation allowance, and therefore there was no impact to current period income tax expense.

At December 31, 2017, we had federal and state net operating loss (“NOL”) carryforwards of approximately $4.7 billion and $2.3 billion, respectively. These NOL carryforwards will expire between 2021 and 2037. At December 31, 2017, we had federal and state tax credit carryforwards of $18 million and $4 million, respectively. These tax credit carryforwards expire between 2027 and 2036.

Due to historical losses and other available evidence related to our ability to generate taxable income, we have established a valuation allowance to fully offset our federal and state net deferred tax assets as of December 31, 2017 and 2016. We will continue to evaluate the realizability of our deferred tax assets in the future. As a result of increased profitability in the U.K., we released the $9 million U.K. valuation allowance during 2017. The decrease in the valuation allowance was $446 million for the year ended December 31, 2017.

Changes in the balance of unrecognized tax benefits are as follows (in millions):



	Year Ended December 31,
	2017			2016
Balance at beginning of the year	$	103		$	104
Additions based on tax positions related to current year	—			—
Additions for tax positions of prior years	—			—
Reductions for tax positions of prior years	(1		)	(1		)
Settlements	—			—
U.S. tax reform rate change	(40		)	—
Balance at end of the year	$	62		$	103

Any settlement of uncertain tax positions would result in an adjustment to our NOL carryforward which, if utilized, will reduce taxable income in a future year. As a result, the tabular rollforward reflects the unrecognized tax benefits at the reduced corporate income tax rate of 21%.

Our effective tax rate will not be affected if the unrecognized federal income tax benefits provided above were recognized. Currently, we do not recognize any accrued liabilities, interest and penalties associated with the unrecognized tax benefits provided above in our Consolidated Statements of Operations or our Consolidated Balance Sheets. We recognize interest and penalties related to income tax matters as part of income tax expense.

We experienced an ownership change within the provisions of U.S. Internal Revenue Code (“IRC”) Section 382 in 2008, 2010 and 2012. An analysis of the annual limitation on the utilization of our NOLs was performed in accordance with IRC Section 382. It was determined that IRC Section 382 will not limit the use of our NOLs in full over the carryover period. We will continue to monitor trading activity in our shares which may cause an additional ownership change which could ultimately affect our ability to fully utilize our existing NOL carryforwards.

We are subject to tax in the U.S. and various state and foreign jurisdictions. We remain subject to periodic audits and reviews by taxing authorities; however, we do not expect these audits will have a material effect on our tax provision. Federal and state tax returns for the years after 2013 remain open for examination. Tax authorities may have the ability to review and adjust carryover attributes that were generated prior to these periods if utilized in an open tax year.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 16—SHARE-BASED COMPENSATION

We have granted restricted stock shares, restricted stock units, performance stock units and phantom units to employees and non-employee directors under the Amended and Restated 2003 Stock Incentive Plan, as amended (the “2003 Plan”), 2011 Incentive Plan, as amended (the “2011 Plan”), the 2015 Employee Inducement Incentive Plan (the “Inducement Plan”) and the 2015 Long-Term Cash Incentive Plan (the “2015 Plan”).

Total share-based compensation consisted of the following (in millions):



	Year Ended December 31,
	2017			2016			2015
Share-based compensation costs, pre-tax:
Equity awards	$	34		$	41		$	90
Liability awards	80			76			105
Total share-based compensation	114			117			195
Capitalized share-based compensation	(23		)	(16		)	(23		)
Total share-based compensation expense	$	91		$	101		$	172
Tax benefit associated with share-based compensation expense	$	5		$	—		$	—

The total unrecognized compensation cost at December 31, 2017 relating to non-vested share-based compensation arrangements consisted of the following:



	Unrecognized Compensation Cost (in millions)		Recognized over a weighted average period (years)
Restricted Stock Share Awards	$	7	1.5
Restricted Share Unit and Performance Stock Unit Awards	$	44	1.5
Phantom Units Awards	$	49	1.1

We have disclosed the deferred tax benefit realized from share-based compensation exercised during the annual period in Note 15—Income Taxes.

Restricted Stock Share Awards

Restricted stock share awards are awards of common stock that are subject to restrictions on transfer and to a risk of forfeiture if the recipient terminates employment with us prior to the lapse of the restrictions. These awards vest based on service conditions (one, two, three or four-year service periods) and performance conditions. All performance conditions of the awards have been achieved as of December 31, 2017.

The 2003 Plan and 2011 Plan provide for the issuance of 21.0 million shares and 35.0 million shares, respectively, of our common stock that may be in the form of various share-based performance awards deemed by the Compensation Committee of our Board (the “Compensation Committee”).

The Inducement Plan initially provided for the issuance of up to 1.0 million shares of our common stock in the form of stock-based awards deemed by the Compensation Committee to provide us with an opportunity to attract employees. As of December 31, 2017, 0.2 million shares of restricted stock have been granted under the Inducement Plan. In December 2016, the Compensation Committee recommended, and our Board approved, reducing the remaining shares available for issuance under the Inducement Plan to zero.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

The table below provides a summary of our restricted stock outstanding (in millions, except for per share information):



	Shares		Weighted Average Grant Date Fair Value Per Share
Non-vested at January 1, 2017	5.7		$	24.12
Granted	—		—
Vested	(3.3	)	23.80
Forfeited	(0.2	)	28.28
Non-vested at December 31, 2017	2.2		$	24.29

The fair value of restricted stock share awards vested for the years ended December 31, 2017, 2016 and 2015 were $78 million, $36 million and $50 million, respectively.

Restricted Share Unit and Performance Stock Unit Awards

Restricted share unit and performance stock unit awards are share awards that entitle the holder to receive shares of our common stock upon vesting, subject to restrictions on transfer and to a risk of forfeiture if the recipient terminates employment with us prior to the lapse of the restrictions. Restricted share units vest ratably over service conditions (two, three or four-year service periods). Performance stock units provide for three-year cliff vesting with payouts based on our cumulative distributable cash flow per share from January 1, 2018 through December 31, 2019 compared to a pre-established performance target. The number of shares that may be earned at the end of the vesting period ranges from 50 to 200 percent of the target award amount if the threshold performance is met.

In January 2017, the issuance of awards with respect to 7.8 million shares of common stock available for issuance under the 2011 Plan was approved at a special meeting of our shareholders.

The table below provides a summary of our restricted share unit and performance stock unit awards outstanding assuming payout at target for awards containing performance conditions (in millions, except for per unit information):



	Units		Weighted Average Grant Date Fair Value Per Unit
Non-vested at January 1, 2017	—		$	—
Granted (1)	1.4		47.16
Vested	—		—
Forfeited	(0.1	)	46.71
Non-vested at December 31, 2017	1.3		$	47.18


(1)	This number excludes 0.2 million performance stock units, which represent the maximum number of common units that would be issued if the maximum level of performance under the target awards amount is achieved.

The table below provides a summary of restricted share unit and performance stock unit awards issued:



	Year Ended December 31,
	2017		2016		2015
Units Issued (in millions)	1.4		—		—
Weighted Average Grant Date Fair Value Per Unit	$	47.16	$	—	$	—
Fair Value vested (in millions)	$	1	$	—	$	—

Phantom Units Awards

Phantom units are share-based awards granted to employees over a vesting period that entitle the grantee to receive the cash equivalent to the value of a share of our common stock upon each vesting. For the years ended December 31, 2017, 2016 and 2015, we issued zero, 1.8 million and 5.9 million phantom units, respectively, to our employees and non-employee directors. Phantom units are not eligible to receive quarterly distributions. These awards vest based on service conditions (two, three or four-year service periods).

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

The 2015 Plan generally provides for cash-settled awards. In April 2015, the Compensation Committee recommended and our Board approved the 2014-2018 Long-Term Cash Incentive Program (the “2014-2018 LTIP”) under the 2015 Plan. The Compensation Committee recommended and our Board approved the termination of the 2014-2018 LTIP in October 2016.

The table below provides a summary of our phantom units outstanding (in millions):



	Units
Non-vested at January 1, 2017	3.9
Granted	—
Vested	(1.8	)
Forfeited	(0.3	)
Non-vested at December 31, 2017	1.8

The value of phantom units vested during the years ended December 31, 2017, 2016 and 2015 was $86 million, $78 million, $50 million, respectively, of which $1 million was recorded as part of accrued liabilities on our Consolidated Balance Sheets as of December 31, 2016.

NOTE 17—EMPLOYEE BENEFIT PLAN

We have a defined contribution plan (“401(k) Plan”) which allows eligible employees to contribute up to 100% of their compensation up to the IRS maximum. We match each employee’s deferrals (contributions) up to 6% of compensation and may make additional contributions at our discretion. Employees are immediately vested in the contributions made by us. Our contributions to the 401(k) Plan were $7 million, $6 million and $5 million for the years ended December 31, 2017, 2016 and 2015, respectively. We have made no discretionary contributions to the 401(k) Plan to date.

NOTE 18—NET LOSS PER SHARE ATTRIBUTABLE TO COMMON STOCKHOLDERS

The following table reconciles basic and diluted weighted average common shares outstanding for the years ended December 31, 2017, 2016 and 2015 (in millions, except per share data):



	Year Ended December 31,
	2017			2016			2015
Weighted average common shares outstanding:
Basic	233.1			228.8			226.9
Dilutive unvested stock	—			—			—
Diluted	233.1			228.8			226.9

Basic and diluted net loss per share attributable to common stockholders	$	(1.68	)	$	(2.67	)	$	(4.30	)

Potentially dilutive securities that were not included in the diluted net loss per share computations because their effects would have been anti-dilutive were as follows (in millions):



	Year Ended December 31,
	2017	2016	2015
Stock options and unvested stock (1)	3.4	0.6	2.1
Convertible notes (2)	16.9	16.3	15.8
Total potentially dilutive common shares	20.3	16.9	17.9


(1)	Does not include 0.2 million shares, 5.0 million shares and 5.4 million shares for the years ended December 31, 2017, 2016 and 2015, respectively, of unvested stock because the performance conditions had not yet been satisfied as of December 31, 2017, 2016 and 2015, respectively.

(2)

Includes number of shares in aggregate issuable upon conversion of the 2021 Cheniere Convertible Unsecured Notes and the 2045 Cheniere Convertible Senior Notes. There were no shares included in the computation of diluted net loss per share for the 2025 CCH HoldCo II Convertible Senior Notes because substantive non-market-based contingencies underlying the eligible conversion date have not been met as of December 31, 2017.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 19—LEASES

During the years ended December 31, 2017, 2016 and 2015, we recognized rental expense for all operating leases of $199 million, $86 million and $41 million, respectively, related primarily to office space, land sites and LNG vessel time charters. Our land site leases for the Sabine Pass LNG terminal have initial terms varying up to 30 years with multiple options to renew up to an additional 60 years.

Future annual minimum lease payments, excluding inflationary adjustments, for operating leases are as follows (in millions):



Years Ending December 31,	Operating Leases (1)
2018 (2)	$	140
2019 (2)	127
2020	119
2021	76
2022	58
Thereafter	236
Total	$	756


(1)	Includes certain lease option renewals that are reasonably assured.


(2)	Does not include $19 million in aggregate payments we will receive from our LNG vessel time charter subleases.

Capital Leases

In December 2015, we entered into a lease agreement for tug services related to the CCL Project that was accounted for as a capital lease. As of December 31, 2017, we did not have any assets recorded under this obligation due to the service term of this lease commencing in 2018. We will record assets acquired under capital leases, net of accumulated amortization, in property, plant and equipment, net, on our Consolidated Balance Sheets upon commencement of the service term, and the related amortization expense on our Consolidated Statements of Operations.

Future annual minimum lease payments, excluding inflationary adjustments, for capital leases are as follows (in millions):



Years Ending December 31,	Capital Leases
2018	$	5
2019	10
2020	10
2021	10
2022	10
Thereafter	154
Total	$	199

NOTE 20—COMMITMENTS AND CONTINGENCIES

We have various contractual obligations which are recorded as liabilities in our Consolidated Financial Statements. Other items, such as certain purchase commitments and other executed contracts which do not meet the definition of a liability as of December 31, 2017, are not recognized as liabilities but require disclosures in our Consolidated Financial Statements.

LNG Terminal Commitments and Contingencies

Obligations under EPC Contracts

SPL has lump sum turnkey contract with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of Train 5 of the SPL Project. The EPC contract for SPL Train 5 provides that SPL will pay Bechtel a contract price of $3.1 billion, subject to adjustment by change order. SPL has the right to terminate the EPC contract for its convenience, in which case Bechtel will be paid (1) the portion of the contract price for the work performed, (2) costs reasonably incurred by

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Bechtel on account of such termination and demobilization and (3) a lump sum of up to $30 million depending on the termination date.

CCL has lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of Stage 1 and Stage 2 of the CCL Project. The EPC contract for Stage 2 of the CCL Project was amended and restated in December 2017. The EPC contract prices for Stage 1 of the CCL Project and Stage 2 of the CCL Project are approximately $7.8 billion and $2.4 billion, respectively, reflecting amounts incurred under change orders through December 31, 2017. CCL has the right to terminate each of the EPC contracts for its convenience, in which case Bechtel will be paid the portion of the contract price for the work performed plus costs reasonably incurred by Bechtel on account of such termination and demobilization. If the EPC contract for Stage 1 of the CCL Project is terminated, Bechtel will also be paid a lump sum of up to $30 million depending on the termination date. If the amended and restated EPC contract for Stage 2 of the CCL Project is terminated, Bechtel will be paid a lump sum of up to $2.5 million if the termination date is prior to the issuance of the notice to proceed, or Bechtel will be paid a lump sum of up to $30 million if the termination date is after the issuance of the notice to proceed, depending on the termination date.

Obligations under SPAs

SPL has third-party SPAs which obligate SPL to purchase and liquefy sufficient quantities of natural gas to deliver contracted volumes of LNG to the customers’ vessels, subject to completion of construction of specified Trains of the SPL Project.

CCL has third-party SPAs which obligate CCL to purchase and liquefy sufficient quantities of natural gas to deliver contracted volumes of LNG to the customers’ vessels, subject to completion of construction of specified Trains of the CCL Project.

Obligations under LNG TUAs

SPLNG has third-party TUAs with Total Gas & Power North America, Inc. and Chevron U.S.A. Inc. to provide berthing for LNG vessels and for the unloading, storage and regasification of LNG at the Sabine Pass LNG terminal.

Obligations under Natural Gas Supply, Transportation and Storage Service Agreements

SPL and CCL have index-based physical natural gas supply contracts to secure natural gas feedstock for the SPL Project and CCL Project, respectively. The terms of these contracts primarily range from approximately one to six years and commence upon the occurrence of conditions precedent, including declaration by SPL or CCL to the respective natural gas supplier that it is ready to commence the term of the supply arrangement in anticipation of the date of first commercial operation of the applicable, specified Trains of the SPL Project or CCL Project. As of December 31, 2017, SPL and CCL have secured up to approximately 2,214 TBtu and 2,024 TBtu, respectively, of natural gas feedstock through natural gas supply contracts, a portion of which are considered purchase obligations if the conditions precedent were met.

Additionally, SPL has transportation and storage service agreements for the SPL Project. The initial terms of the transportation agreements range from one to 20 years, with renewal options for certain contracts, and commences upon the occurrence of conditions precedent. The term of the SPL storage service agreements ranges from three to ten years.

As of December 31, 2017, our obligations under natural gas supply, transportation and storage service agreements for contracts in which conditions precedent were met were as follows (in millions):



Years Ending December 31,	Payments Due (1)
2018	$	2,274
2019	1,527
2020	1,397
2021	981
2022	336
Thereafter	1,169
Total	$	7,684


(1)	Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread. Amounts included are based on prices and basis spreads as of December 31, 2017.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Restricted Net Assets

At December 31, 2017, our restricted net assets of consolidated subsidiaries were approximately $3.4 billion.

Obligations under Certain Guarantee Contracts

Cheniere and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate transactions with third parties. These arrangements include financial guarantees, letters of credit and debt guarantees. As of December 31, 2017 and 2016, there were no liabilities recognized under these guarantee arrangements.

Other Commitments

In the ordinary course of business, we have entered into certain multi-year licensing and service agreements, none of which are considered material to our financial position. Additionally, we have various lease commitments, as disclosed in Note 19—Leases.

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.

Parallax Litigation

In 2015, our wholly owned subsidiary, Cheniere LNG Terminals, LLC (“CLNGT”), entered into discussions with Parallax Enterprises, LLC (“Parallax Enterprises”) regarding the potential joint development of two liquefaction plants in Louisiana (the “Potential Liquefaction Transactions”). While the parties negotiated regarding the Potential Liquefaction Transactions, CLNGT loaned Parallax Enterprises approximately $46 million, as reflected in a secured note dated April 23, 2015, as amended on June 30, 2015, September 30, 2015 and November 4, 2015 (the “Secured Note”). The Secured Note was secured by all assets of Parallax Enterprises and its subsidiary entities. On June 30, 2015, Parallax Enterprises’ parent entity, Parallax Energy LLC (“Parallax Energy”), executed a Pledge and Guarantee Agreement further securing repayment of the Secured Note by providing a parent guaranty and a pledge of all of the equity of Parallax Enterprises in satisfaction of the Secured Note (the “Pledge Agreement”). CLNGT and Parallax Enterprises never executed a definitive agreement to pursue the Potential Liquefaction Transactions. The Secured Note matured on December 11, 2015, and Parallax Enterprises failed to make payment. On February 3, 2016, CLNGT filed an action against Parallax Energy, Parallax Enterprises and certain of Parallax Enterprises’ subsidiary entities, styled Cause No. 4:16-cv-00286, Cheniere LNG Terminals, LLC v. Parallax Energy LLC, et al., in the United States District Court for the Southern District of Texas (the “Texas Federal Suit”). CLNGT asserted claims in the Texas Federal Suit for (1) recovery of all amounts due under the Secured Note and (2) declaratory relief establishing that CLNGT is entitled to enforce its rights under the Secured Note and Pledge Agreement in accordance with each instrument’s terms and that CLNGT has no obligations of any sort to Parallax Enterprises concerning the Potential Liquefaction Transactions. On March 11, 2016, Parallax Enterprises and the other defendants in the Texas Federal Suit moved to dismiss the suit for lack of subject matter jurisdiction. On August 2, 2016, the court denied the defendants’ motion to dismiss without prejudice and permitted the parties to pursue jurisdictional discovery.

On March 11, 2016, Parallax Enterprises filed a suit against us and CLNGT styled Civil Action No. 62-810, Parallax Enterprises LLP v. Cheniere Energy, Inc. and Cheniere LNG Terminals, LLC, in the 25th Judicial District Court of Plaquemines Parish, Louisiana (the “Louisiana Suit”), wherein Parallax Enterprises asserted claims for breach of contract, fraudulent inducement, negligent misrepresentation, detrimental reliance, unjust enrichment and violation of the Louisiana Unfair Trade Practices Act. Parallax Enterprises predicated its claims in the Louisiana Suit on an allegation that we and CLNGT breached a purported agreement to jointly develop the Potential Liquefaction Transactions. Parallax Enterprises sought $400 million in alleged economic damages and rescission of the Secured Note. On April 15, 2016, we and CLNGT removed the Louisiana Suit to the United States District Court for the Eastern District of Louisiana, which subsequently transferred the Louisiana Suit to the United States District Court for the Southern District of Texas, where it was assigned Civil Action No. 4:16-cv-01628 and transferred to the same judge presiding over the Texas Federal Suit for coordinated handling. On August 22, 2016, Parallax Enterprises voluntarily dismissed all claims asserted against CLNGT and us in the Louisiana Suit without prejudice to refiling.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

On July 27, 2017, the Parallax entities named as defendants in the Texas Federal Suit reurged their motion to dismiss and simultaneously filed counterclaims against CLNGT and third party claims against us for breach of contract, breach of fiduciary duty, promissory estoppel, quantum meruit and fraudulent inducement of the Secured Note and Pledge Agreement, based on substantially the same factual allegations Parallax Enterprises made in the Louisiana Suit. These Parallax entities also simultaneously filed an action styled Cause No. 2017-49685, Parallax Enterprises, LLC, et al. v. Cheniere Energy, Inc., et al., in the 61st District Court of Harris County, Texas (the “Texas State Suit”), which asserts substantially the same claims these entities asserted in the Texas Federal Suit. On July 31, 2017, CLNGT withdrew its opposition to the dismissal of the Texas Federal Suit without prejudice on jurisdictional grounds and the federal court subsequently dismissed the Texas Federal Suit without prejudice. We and CLNGT simultaneously filed an answer and counterclaims in the Texas State Suit, asserting the same claims CLNGT had previously asserted in the Texas Federal Suit. Additionally, CLNGT filed third party claims against Parallax principals Martin Houston, Christopher Bowen Daniels, Howard Candelet and Mark Evans, as well as Tellurian Investments, Inc., Driftwood LNG, LLC, Driftwood LNG Pipeline LLC and Tellurian Services LLC, formerly known as Parallax Services LLC, including claims for tortious interference with CLNGT’s collateral rights under the Secured Note and Pledge Agreement, fraudulent transfer, conspiracy/aiding and abetting. Discovery in the Texas State Suit is ongoing. Trial is currently set for September 2018.

We do not expect that the resolution of this litigation will have a material adverse impact on our financial results.

NOTE 21—CUSTOMER CONCENTRATION

The following table shows customers with revenues of 10% or greater of total third-party revenues and customers with accounts receivable balances of 10% or greater of total accounts receivable from third parties:



				Percentage of Accounts Receivable from Third Parties
	Year Ended December 31,			December 31,
	2017	2016	2015	2017	2016
Customer A	24%	39%	—%	28%	34%
Customer B	14%	*	—%	16%	21%
Customer C	14%	—%	—%	14%	—%
Customer D	17%	—%	—%	—%	—%
Customer E	*	13%	—%	—%	—%
Customer F	*	*	—%	15%	28%
Customer G	*	*	—%	—%	12%

* Less than 10%

During the year ended December 31, 2017, revenues from external customers that were derived from domestic customers was $1.6 billion and from customers outside of the United States was $4.0 billion, of which $1.2 billion, $787 million and $762 million were derived from customers in Japan, Ireland and South Korea, respectively. During the year ended December 31, 2016, revenues from external customers that were derived from domestic customers was $769 million and from customers outside of the United States was $514 million, of which $162 million was derived from a customer in Japan. Substantially all of our revenues from external customers for the year ended December 31, 2015 were attributed to the United States. We attribute revenues from external customers to the country in which the party to the applicable agreement has its principal place of business. Substantially all of our long-lived assets are located in the United States.

NOTE 22—SUPPLEMENTAL CASH FLOW INFORMATION

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



	Year Ended December 31,
	2017		2016		2015
Cash paid during the period for interest, net of amounts capitalized	$	305	$	66	$	123
Contribution of assets to equity method investee	14		—		—
Non-cash conveyance of assets	—		—		13

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities was $521 million, $395 million and $301 million as of December 31, 2017, 2016 and 2015, respectively.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 23—RECENT ACCOUNTING STANDARDS

The following table provides a brief description of recent accounting standards that had not been adopted by us as of December 31, 2017:



Standard	Description	Expected Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto	This standard provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to 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. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”).	January 1, 2018	We will adopt this standard on January 1, 2018 using the full retrospective approach. The adoption of this standard will not have a material impact upon our Consolidated Financial Statements but will result in significant additional disclosure regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers, including significant judgments and assumptions used in applying the standard. For the purpose of these Consolidated Financial Statements, we have retrospectively applied this standard and have included the additional disclosures at Note 13—Revenues from Contracts with Customers.
ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto	This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and must be adopted using a modified retrospective approach with certain available practical expedients.	January 1, 2019	We continue to evaluate the effect of this standard on our Consolidated Financial Statements. Preliminarily, we anticipate a material impact from the requirement to recognize all leases upon our Consolidated Balance Sheets. Because this assessment is preliminary and the accounting for leases is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact of the adoption of this standard upon our results of operations or cash flows. We expect to elect the practical expedient to retain our existing accounting for land easements which were not previously accounted for as leases. We have not yet determined whether we will elect any other practical expedients upon transition.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Additionally, the following table provides a brief description of recent accounting standards that were adopted by us during the reporting period:



Standard	Description	Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory	This standard requires inventory to be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This guidance may be early adopted and must be adopted prospectively.	January 1, 2017	The adoption of this guidance did not have a material impact on our Consolidated Financial Statements or related disclosures.
ASU 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting	This standard primarily requires the recognition of excess tax benefits for share-based awards in the statement of operations and the classification of excess tax benefits as an operating activity within the statement of cash flows. The guidance also allows an entity to elect to account for forfeitures when they occur. This guidance may be early adopted, but all of the guidance must be adopted in the same period.	January 1, 2017	Upon adoption of this guidance, we made a cumulative effect adjustment to accumulated deficit for all excess tax benefits not previously recognized, offset by the change in valuation allowance, and for our election to account for forfeitures as they occur. The adoption of this guidance did not have a material impact on our Consolidated Financial Statements or related disclosures.
ASU 2017-04, Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment	This standard simplifies the measurement of goodwill impairment by eliminating the requirement for an entity to perform a hypothetical purchase price allocation. An entity will instead measure the impairment as the difference between the carrying amount and the fair value of the reporting unit. This guidance may be early adopted beginning January 1, 2017, and must be adopted prospectively.	January 1, 2017	The adoption of this guidance did not have a material impact on our Consolidated Financial Statements or related disclosures.
ASU 2017-09, Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting	This standard clarifies when changes to the terms or conditions of a share-based payment award must be accounted for as modifications. An entity will not apply modification accounting to a share-based payment award if the award’s fair value, vesting conditions and classification as an equity or liability award are the same prior to and after the change. This guidance may be early adopted and must be adopted prospectively.	June 30, 2017	The adoption of this guidance did not have a material impact on our Consolidated Financial Statements or related disclosures.