Cheniere Energy, Inc. Annual report pursuant to Section 13 and 15(d)

Annual report pursuant to Section 13 and 15(d)

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Policies)

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2012

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. Our investments are primarily in commercial paper and are made in accordance with corporate policy, which, among other things, stipulates minimum acceptable credit ratings of commercial paper issuers.

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: (i) regulatory approval has been received, (ii) financing for the project is available and (iii) 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 costs that are capitalized as property, plant and equipment and certain permits that are capitalized as intangible LNG assets.

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

Revenue Recognition

LNG regasification capacity reservation fees are recognized as revenue over the term of the respective terminal use agreements ("TUAs"). Advance capacity reservation fees are initially deferred and amortized over a 10-year period as a reduction of a customer’s regasification capacity reservation fees payable under its TUA. The retained 2% of LNG delivered for each customer’s account at the Sabine Pass LNG terminal is recognized as revenues as Sabine Pass LNG, L.P. ("Sabine Pass LNG"), a subsidiary of Cheniere Partners, performs the services set forth in each customer’s TUA.

LNG and Natural Gas Marketing

We have determined that our LNG and natural gas marketing business activities are energy trading and risk management activities for trading purposes and have elected to present these activities on a net basis on our Consolidated Statements of Operations. Marketing and trading revenues represent the margin earned on the purchase and transportation of LNG purchases and subsequent sales of natural gas to third parties. These energy trading and risk management activities include, but are not limited to: purchase of LNG and natural gas, transportation contracts, and derivatives. Below is a brief description of our accounting treatment of each type of energy trading and risk management activity and how we account for it:

Purchases of LNG and natural gas

Purchase of LNG and natural gas

The purchase value of LNG or natural gas inventory is recorded as an asset on our Consolidated Balance Sheets at the cost to acquire the product. Our inventory is subject to lower of cost or market adjustment each quarter. Recoveries of losses resulting from interim period lower of cost or market adjustments are made due to market price recoveries on the same inventory in the same fiscal year and are recognized as gains in later interim periods with such gains not exceeding previously recognized losses. Any adjustment to our inventory is recorded on a net basis as LNG and natural gas marketing revenue on our Consolidated Statements of Operations.

Transportation Contracts

Transportation contracts

We enter into transportation contracts with respect to the transport of LNG or natural gas to a specific location for storage or sale. Transportation costs that are incurred during the purchase of LNG or natural gas are capitalized as part of the acquisition costs of the product. Transportation costs incurred to sell LNG or natural gas are recorded on a net basis as LNG and natural gas marketing revenue on our Consolidated Statements of Operations.

Derivatives

LNG Inventory Derivatives

We use derivative instruments to hedge cash flows attributable to the future sale of LNG inventory. Gains and losses in positions to hedge the cash flows attributable to the future sale of LNG inventory are classified as marketing and trading revenues on our Consolidated Statements of Operations.

Derivatives

We use derivative instruments from time to time to hedge the exposure to variability in expected future cash flows attributable to the future sale of our LNG inventory, to hedge the exposure to price risk attributable to future purchases of natural gas to be utilized as fuel to operate the Sabine Pass LNG terminal, and to hedge the exposure to volatility in a portion of the floating-rate interest payments under the Liquefaction Credit Facility. We do not offset the fair value amounts of our LNG inventory, fuel and interest rate derivatives, and collateral deposited for such contracts are not netted within the derivative fair value. We have disclosed certain information regarding these derivative positions, including the fair value of our derivative positions, in Note 11—"Financial Instruments" of our Notes to Consolidated Financial Statements.

Accounting guidance for derivative instruments and hedging activities establishes accounting and reporting standards requiring that derivative instruments be recorded at fair value and included in the consolidated balance sheet as assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. We record changes in the fair value of our derivative positions based on the value for which the derivative instrument could be exchanged between willing parties. To date, all of our derivative positions fair value determinations have been made by management using quoted prices in active markets for similar assets or liabilities. The ultimate fair value of our derivative instruments is uncertain, and we believe that it is possible that a change in the estimated fair value will occur in the near future as commodity prices and interest rates change.

Changes in fair value of contracts that do not qualify as hedges or are not designated as hedges are recognized currently in earnings. Gains and losses in positions to hedge the cash flows attributable to the future sale of LNG inventory are classified as marketing and trading revenues on our Consolidated Statements of Operations. Gains or losses in the positions to mitigate the price risk from future purchases of natural gas to be utilized as fuel to operate the Sabine Pass LNG terminal are classified as derivative gain (loss) on our Consolidated Statements of Operations.

We have elected cash flow hedge accounting for derivatives that we use to hedge the exposure to volatility in floating-rate interest payments. Changes in fair value of derivative instruments designated as cash flow hedges, to the extent the hedge is effective, are recognized in accumulated other comprehensive loss on our Consolidated Balance Sheets. We reclassify gains and losses on the hedges from accumulated other comprehensive loss into interest expense in our Consolidated Statements of Operations as the hedged item is recognized. Any change in the fair value resulting from ineffectiveness is recognized immediately as derivative gain (loss) on our Consolidated Statements of Operations. We use regression analysis to determine whether we expect a derivative to be highly effective as a cash flow hedge prior to electing hedge accounting and also to determine whether all derivatives designated as cash flow hedges have been effective. We perform these effectiveness tests prior to designation for all new hedges and on a quarterly basis for all existing hedges. We calculate the actual amount of ineffectiveness on our cash flow hedges using the "dollar offset" method, which compares changes in the expected cash flows of the hedged transaction to changes in the value of expected cash flows from the hedge. We discontinue hedge accounting when our effectiveness tests indicate that a derivative is no longer highly effective as a hedge; when the derivative expires or is sold, terminated or exercised; when the hedged item matures, is sold or repaid; or when we determine that the occurrence of the hedged forecasted transaction is not probable. When we discontinue hedge accounting but continue to hold the derivative, we begin to apply mark-to-market accounting at that time.

Fair Value of Financial Instruments

The carrying amounts of cash and cash equivalents, restricted cash and cash equivalents, restricted certificates of deposit, accounts receivable, and accounts payable approximate fair value because of the short maturity of those instruments. We use available market data and valuation methodologies to estimate the fair value of debt.

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. 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 an other current asset and not netted within the derivative fair value. Our interest rate 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.

Regulated Natural Gas Pipelines

Our natural gas pipeline is subject to the jurisdiction of the Federal Energy Regulatory Commission ("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 accounting principles generally accepted in the United States of America ("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 the 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;


•	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.

Property, Plant and Equipment

Property, plant and equipment are recorded at cost. Expenditures for construction activities, major renewals and betterments are capitalized, while expenditures for maintenance and repairs and general and administrative activities are charged to expense 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 operations.

Management reviews property, plant and equipment for impairment periodically and whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. We have recorded no significant impairments related to property, plant and equipment for 2012, 2011 or 2010.

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 provided for deferred tax assets if it is more likely than not that such asset will not be realized.

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. Actual results could differ from the estimates and assumptions used.

Estimates used in the assessment of impairment of our long-lived assets, including goodwill, are the most significant of our estimates. There are numerous uncertainties inherent in estimating future cash flows of assets or business segments. The accuracy of any cash flow estimate is a function of judgment used in determining the amount of cash flows generated. As a result, cash flows may be different from the cash flows that we use to assess impairment of our assets. Management reviews its estimates of cash flows on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. Significant negative industry or economic trends, including a significant decline in the market price of our common stock, reduced estimates of future cash flows for our business segments or disruptions to our business could lead to an impairment charge of our long-lived assets, including goodwill and other intangible assets. Our valuation methodology for assessing impairment requires management to make judgments and assumptions based on historical experience and to rely heavily on projections of future operating performance. Projections of future operating results and cash flows may vary significantly from results. In addition, if our analysis results in an impairment of our long-lived assets, including goodwill, we may be required to record a charge to earnings in our consolidated financial statements during a period in which such impairment is determined to exist, which may negatively impact our results of operations.

Other items subject to estimates and assumptions include asset retirement obligations, valuation allowances for net deferred tax assets, valuations of derivative instruments, valuations of noncash compensation and collectability of accounts receivable and other assets.

As future events and their effects cannot be determined accurately, actual results could differ significantly from our estimates

Goodwill

Goodwill represents the excess of cost over fair value of the assets of businesses acquired. The goodwill on our Consolidated Balance Sheets as of December 31, 2012 and 2011 is associated with our LNG terminal reporting unit. We determine our reporting units by identifying each unit that engaged in business activities from which it may earn revenues and incur expenses, had operating results regularly reviewed by the entities' chief operating decision makers for purposes of resource allocation and performance assessment, and had discrete financial information.

Goodwill is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less often than annually. During the fourth quarters of 2012 and 2011, we performed a qualitative assessment of goodwill in accordance with FASB guidance which permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. If we fail the qualitative test, then we must compare our management's estimate of the fair value of a reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, a computation of the implied fair value of the goodwill is compared with its related carrying value. If the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in the amount of the excess.

The annual reviews of goodwill in 2012 and 2011 did not result in impairment charges. The fair value of the reporting unit substantially exceeds its carrying value for both periods and it was not "more likely than not" that the fair value of our LNG terminal segment was less than its carrying value. As discussed above regarding our use of estimates, our judgments and assumptions are inherent in our management’s 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 different levels of impairment charges in the consolidated financial statements.

Debt Issuance Costs

Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees and printing costs. These costs are capitalized and are being amortized to interest expense over the term of the related debt facility.

Share-based Compensation Expense

Share-Based Compensation Expense

We recognize compensation expense for all share-based payments using the Black-Scholes-Merton option valuation model. We recognize share-based compensation net of an estimated forfeiture rate and only recognize compensation cost for those shares expected to vest on a straight-line or accelerated basis over the requisite service period of the award.

Determining the appropriate fair value model and calculating the fair value of share-based payment awards requires the use of highly subjective assumptions, including the expected life of the share-based payment awards and stock price volatility. We believe that implied volatility, calculated based on traded options of our common stock, combined with historical volatility is an appropriate indicator of expected volatility and future stock price trends. Therefore, the expected volatility for the years ended December 31, 2012 and 2011 used in our fair value model was based on a combination of implied and historical volatilities. The assumptions used in calculating the fair value of share-based payment awards represent our best estimates, but these estimates involve inherent uncertainties and the application of management's judgment. As a result, if factors change and we use different assumptions, our share-based compensation expense could be materially different in the future. In addition, we are required to estimate the expected forfeiture rate and only recognize expense for those shares expected to vest. If our actual forfeiture rate is materially different from our estimate, future share-based compensation expense could be significantly different from what we have recorded in the current period (See Note 14—"Share-Based Compensation" of our Notes to Consolidated Financial Statements).

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 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. Basic and diluted EPS for all periods presented are the same since the effect of our options and unvested stock is anti-dilutive to our net loss per share. Stock options, warrants and unvested stock representing securities that could potentially dilute basic EPS in the future that were not included in the diluted computation because they would have been anti-dilutive for the years 2012, 2011 and 2010, were 4.4 million shares, 2.4 million shares and 5.8 million shares, respectively. Common shares of 7.5 million on a weighted average basis, issuable upon conversion of the 2008 Loans and the Convertible Senior Unsecured Notes (described in Note 9—"Debt and Debt—Related Parties"), were not included in the computation of diluted net loss per share for 2011 and 2010, because the computation of diluted net loss per share utilizing the "if-converted" method would be anti-dilutive. No adjustments were made to reported net loss in the computation of EPS.

Asset Retirement Obligations

We recognize asset retirement obligations ("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 recognition of asset retirement obligations is described below:

Currently, the Sabine Pass LNG terminal is our only constructed and operating 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 zero. Therefore, we have not recorded an asset retirement obligation associated with the Sabine Pass LNG terminal.

Currently, the Creole Trail Pipeline is our only constructed and operating natural gas pipeline. We believe that it is not feasible to predict when the natural gas transportation services provided by the Creole Trail Pipeline will no longer be utilized. In addition, our right-of-way agreements associated with the Creole Trail Pipeline have no stipulated termination dates. Therefore, we have concluded that due to advanced technology associated with current natural gas pipelines and our intent to operate the Creole Trail Pipeline as long as supply and demand for natural gas exists in the United States, we have not recorded an ARO associated with the Creole Trail Pipeline.