ITEM 1A. RISK FACTORS
The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates or expectations contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, results of operations, financial condition, liquidity and prospects.
The risk factors in this report are grouped into the following categories:
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Risks Relating to Our Financial Matters;
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Risks Relating to Our LNG Terminal Business;
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Risks Relating to Our Natural Gas Pipeline Business;
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Risks Relating to Our LNG and Natural Gas Marketing Business;
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Risks Relating to Our LNG Businesses in General; and
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Risks Relating to Our Business in General.
Risks Relating to Our Financial Matters
Our existing level of cash resources, negative operating cash flow and significant debt could cause us to have inadequate liquidity and could materially and adversely affect our business, financial condition and prospects.
As of December 31, 2011, we had $459.2 million of cash and cash equivalents and $185.1 million of restricted cash and cash equivalents, and we had $3.0 billion of total debt outstanding on a consolidated basis (before debt discounts), although we repaid $298.0 million of this debt in January 2012. We incur significant interest expense relating to the assets at the Sabine Pass LNG terminal, and we anticipate needing to incur additional debt and issue equity to finance the construction of Cheniere Partners' proposed liquefaction project. Our ability to fund our capital expenditures and refinance our indebtedness will depend on our ability to access capital markets. In addition, if we do not make a final investment decision to construct LNG trains 1 and 2 by December 31, 2012, we may not be able to refinance our existing indebtedness when it matures, including the Convertible Senior Unsecured Notes and the Senior Notes. Our costs could increase or future borrowings or equity offerings may be unavailable to us or unsuccessful, which could cause us to be unable to pay or refinance our indebtedness or to fund our other liquidity needs.
We have not been profitable historically, and we have not had positive operating cash flow. Our ability to achieve profitability and generate positive operating cash flow in the future is subject to significant uncertainty.
We had net losses of $198.8 million, $76.2 million and $161.5 million for the years ended December 31, 2011, 2010 and 2009, respectively. In addition, our net cash flow used in operating activities was $42.8 million, $16.9 million and $97.9 million for the years ended December 31, 2011, 2010 and 2009, respectively. In the future, we may incur operating losses and experience negative operating cash flow. We may not be able to reduce costs, increase revenues, or reduce our debt service obligations sufficiently to maintain our cash resources, which could cause us to have inadequate liquidity to continue our business.
In order to generate needed amounts of cash, we may sell equity or equity-related securities or assets, including equity interests in Cheniere Partners. Such sales could dilute our stockholders' proportionate indirect interests in the assets, business operations and proposed liquefaction and other projects of Cheniere Partners or other subsidiaries, and could adversely affect the market price of our common stock.
We have pursued and are pursuing a number of alternatives in order to generate needed amounts of cash, including potential issuances and sales of additional equity or equity-related securities by us, Cheniere Partners, or both, and potential sales of assets, including units of limited partner interest that we currently hold in Cheniere Partners. Such sales, in one or more transactions, could dilute our stockholders' proportionate indirect interests in the assets, business operations and proposed projects of Cheniere Partners, including its proposed liquefaction project, or in other subsidiaries. In addition, such sales, or the anticipation of such sales, could adversely affect the market price of our common stock.
Our ability to generate needed amounts of cash is substantially dependent upon the performance by customers under long-term contracts that we have entered into, and we could be materially and adversely affected if any customer fails to perform its contractual obligations for any reason.
Our future results and liquidity are substantially dependent upon performance by Chevron and Total, each of which has entered into a TUA with Sabine Pass LNG and agreed to pay us approximately $125 million annually, and, upon satisfaction of the conditions precedent to payment thereunder, by BG, Gas Natural Fenosa, GAIL, and KOGAS, each of which has entered into an SPA with Sabine Pass Liquefaction and agreed to pay us approximately $723 million, $454 million, $548 million and $548 million annually, respectively. We are dependent on each customer's continued willingness and ability to perform its obligations under its contract. We are also exposed to the credit risk of any guarantor of these customers' obligations under their respective contracts in the event that we must seek recourse under a guaranty. If any customer fails to perform its obligations under its contract, our business, results of operations, financial condition and prospects could be materially and adversely affected, even if we were ultimately successful in seeking damages from that customer or its guarantor for a breach of the contract.
Each customer's contract at the Sabine Pass LNG terminal is subject to termination under certain circumstances.
Each of Sabine Pass LNG's long-term TUAs and Sabine Pass Liquefaction's SPAs contains various termination rights. For example, each of Sabine Pass LNG's customers may terminate its TUA if the Sabine Pass LNG terminal experiences a force majeure delay for longer than 18 months, fails to redeliver a specified amount of natural gas in accordance with the customer's redelivery nominations or fails to accept and unload a specified number of the customer's proposed LNG cargoes. Each of Sabine Pass Liquefaction's customers may terminate its SPA under the circumstances described under "Items 1. and 2. Business and Properties-LNG Terminal Business-Sabine Pass LNG Terminal-Liquefaction Facilities-Customers." We may not be able to replace these TUAs or SPAs on desirable terms, or at all, if they are terminated.
Sabine Pass LNG may be restricted under the terms of the Sabine Pass Indenture from making distributions under certain circumstances, which may limit Cheniere Partners' ability to pay or increase distributions to us, which could materially and adversely affect us.
The Sabine Pass Indenture restricts payments that Sabine Pass LNG can make to Cheniere Partners in certain events and limits the indebtedness that Sabine Pass LNG can incur. Sabine Pass LNG is permitted to pay distributions to Cheniere Partners only after the following payments have been made:
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an operating account has been funded with amounts sufficient to cover the succeeding 45 days of operating and maintenance expenses, maintenance capital expenditures and obligations, if any, under an assumption agreement and a state tax sharing agreement;
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one-sixth of the amount of interest due on the Senior Notes on the next interest payment date (plus any shortfall from any such month subsequent to the preceding interest payment date) has been transferred to a debt payment account;
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outstanding principal on the Senior Notes then due and payable has been paid;
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taxes payable by Sabine Pass LNG or the guarantors of the Senior Notes and permitted payments in respect of taxes have been paid; and
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the debt service reserve account has on deposit the amount required to make the next interest payment on the Senior Notes.
In addition, Sabine Pass LNG will only be able to make distributions to Cheniere Partners in the event that it could, among other things, incur at least $1.00 of additional indebtedness under the fixed charge coverage ratio test of 2:1 at the time of payment and after giving pro forma effect to the distribution. Sabine Pass LNG is also prohibited under the Sabine Pass Indenture from paying distributions to Cheniere Partners or incurring additional indebtedness upon the occurrence of any of the following events, among others:
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a default for 30 days in the payment of interest on the Senior Notes;
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a failure to pay any principal of the Senior Notes;
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a failure by Sabine Pass LNG to comply with various covenants in the Sabine Pass Indenture;
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a failure to observe any other agreement in the Sabine Pass Indenture beyond any specified cure periods;
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a default under any mortgage, indenture or instrument governing any indebtedness for borrowed money by Sabine Pass LNG in excess of $25.0 million if such default results from a failure to pay principal or interest on, or results in the acceleration of, such indebtedness;
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a final money judgment or decree (not covered by insurance) in excess of $25.0 million is not discharged or stayed within 60 days following entry;
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a failure of any material representation or warranty in the security documents entered into in connection with the Sabine Pass Indenture to be correct;
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the Sabine Pass LNG terminal project is abandoned; or
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certain events of bankruptcy or insolvency.
Sabine Pass LNG's inability to pay distributions to Cheniere Partners or to incur additional indebtedness as a result of the foregoing restrictions in the Sabine Pass Indenture may inhibit Cheniere Partners' ability to pay or increase distributions to us and its other unitholders.
The fixed charge coverage ratio test contained in the Sabine Pass Indenture could prevent Sabine Pass LNG from making cash distributions. As a result, Cheniere Partners may be prevented from making distributions to us, which could materially and adversely affect us.
Sabine Pass LNG is not permitted to make cash distributions if its consolidated cash flow is not at least twice its fixed charges, calculated as required in the Sabine Pass Indenture. In order to satisfy this fixed charge coverage ratio test, we estimate that Sabine Pass LNG's consolidated cash flow, as defined in the Sabine Pass Indenture, must be greater than approximately $375 million. Thus, TUA payments from Cheniere Investments are needed in addition to the TUA payments from Chevron and Total.
The fixed charge coverage ratio test contained in the Sabine Pass Indenture may not be met if Cheniere Investments' payments to Sabine Pass LNG cease to be recognizable as revenue under U.S. generally accepted accounting principles ("GAAP"), which could occur for future periods if, for example, GAAP guidelines for recognition of revenue from affiliates change or LNG trains 1 and 2 do not timely commence operations and Cheniere Investments changes its business such that it is not pursuing, and has no prospect of developing, any substantive business, thereby causing it to lack economic substance. If the fixed charge coverage ratio test is not satisfied, Sabine Pass LNG will not be permitted by the Sabine Indenture to make distributions to Cheniere Partners, which may prevent Cheniere Partners from making distributions to us and its other unitholders, which could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.
The Sabine Pass Indenture may prevent Sabine Pass LNG from engaging in certain beneficial transactions.
In addition to restrictions on the ability of Sabine Pass LNG to make distributions or incur additional indebtedness, the Sabine Pass Indenture also contains various other covenants that may prevent it from engaging in beneficial transactions, including limitations on the ability of Sabine Pass LNG or certain of its subsidiaries to:
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make certain investments;
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purchase, redeem or retire equity interests;
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issue preferred stock;
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sell or transfer assets;
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incur liens;
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enter into transactions with affiliates;
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consolidate, merge, sell or lease all or substantially all of its assets; and
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enter into sale and leaseback transactions.
Risks Relating to Our LNG Terminal Business
Operation of the Sabine Pass LNG terminal, and other facilities that we may construct, involves significant risks.
As more fully discussed in these Risk Factors, the Sabine Pass LNG terminal and our other existing and proposed facilities face operational risks, including the following:
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performing below expected levels of efficiency;
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breakdown or failures of equipment or systems;
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operational errors by vessel or tug operators or others;
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operational errors by us or any contracted facility operator or others;
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labor disputes; and
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weather-related interruptions of operations.
To maintain the cryogenic readiness of the Sabine Pass LNG terminal, Sabine Pass LNG may need to purchase and process LNG. Sabine Pass LNG's TUA customers have the obligation to procure LNG if necessary for the Sabine Pass LNG terminal to maintain its cryogenic state. If they fail to do so, Sabine Pass LNG may need to procure such LNG.
Sabine Pass LNG needs to maintain the cryogenic readiness of the Sabine Pass LNG terminal. Together with Cheniere Investments, the two third-party TUA customers have the obligation to maintain minimum inventory levels, and under certain circumstances, to procure LNG to maintain the cryogenic readiness of the terminal. In the event that aggregate minimum inventory levels are not maintained, Sabine Pass LNG has the right to procure a cryogenic readiness cargo, and to the extent that the TUA customers have failed to maintain their minimum inventory levels, be reimbursed by each TUA customer for their allocable share of the LNG acquisition costs. If Sabine Pass LNG is not able to obtain financing on acceptable terms, it will need to maintain sufficient working capital for such a purchase until it receives reimbursement for the allocable costs of the LNG from its TUA customers or sells the regasified LNG. Sabine Pass LNG may also bear the commodity price and other risks of purchasing LNG, holding it in its inventory for a period of time and selling the regasified LNG.
Sabine Pass LNG may be required to purchase natural gas to provide fuel at the Sabine Pass LNG terminal, which would increase operating costs and could have a material adverse effect on our results of operations.
Sabine Pass LNG's TUAs provide for an in-kind deduction of 2% of the LNG delivered to the Sabine Pass LNG terminal, which it uses primarily as fuel for revaporization and self-generated power and to cover natural gas unavoidably lost at the facility. There is a risk that this 2% in-kind deduction will be insufficient for these needs and that Sabine Pass LNG will have to purchase additional natural gas from third parties. Sabine Pass LNG will bear the cost and risk of changing prices for any such fuel.
Hurricanes or other disasters could adversely affect us.
In August and September of 2005, Hurricanes Katrina and Rita damaged coastal and inland areas located in Texas, Louisiana, Mississippi and Alabama. Construction at the Sabine Pass LNG terminal site was temporarily suspended in connection with Hurricane Katrina, as a precautionary measure. Approximately three weeks after the occurrence of Hurricane Katrina, the Sabine Pass LNG terminal site was again secured and evacuated in anticipation of Hurricane Rita, the eye of which made landfall to the east of the site. As a result of these 2005 storms and related matters, the Sabine Pass LNG terminal experienced construction delays and increased costs. In September 2008, Hurricane Ike struck the Texas and Louisiana coast, and the Sabine Pass LNG terminal experienced damage.
Future storms and related storm activity and collateral effects, or other disasters such as explosions, fires, floods or accidents, could result in damage to, or interruption of operations at, the Sabine Pass LNG terminal or related infrastructure, as well as delays or cost increases in the construction of Cheniere Partners' proposed liquefaction facilities or our other facilities. If there are changes in the global climate, storm frequency and intensity may increase; should it result in rising seas, our coastal operations would be impacted.
Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the development, construction and operation of our facilities could impede operations and construction and could have a material adverse effect on us.
The design, construction and operation of LNG terminals and other facilities, and the import and export of LNG, are highly regulated activities. The FERC's approval under Section 3 of the NGA, as well as several other material governmental and regulatory approvals and permits, are required in order to construct and operate an LNG facility. Although Sabine Pass LNG has obtained all of the necessary authorizations to operate the Sabine Pass LNG receiving terminal, Sabine Pass Liquefaction will need authorization from the FERC to construct and operate Cheniere Partners' proposed liquefaction facilities. Such authorizations are subject to ongoing conditions imposed by regulatory agencies, and additional approval and permit requirements may be imposed. There is no assurance that we will obtain and maintain these governmental permits, approvals and authorizations, and failure to obtain and maintain any of these permits, approvals or authorizations could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.
The construction of Cheniere Partners' project to add liquefaction capacity at the Sabine Pass LNG terminal will be subject to a number of development risks, which could cause cost increases and delays or prevent completion of the project.
Key factors that may affect the timing of, and our ability to complete, the project at the Sabine Pass LNG terminal to add liquefaction capacity include, but are not limited to:
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the issuance and/or continued availability of necessary permits, licenses and approvals from governmental agencies and third parties as are required to construct and operate liquefaction facilities;
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the availability of sufficient financing on reasonable terms, or at all;
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our ability to satisfy the conditions precedent in SPAs with customers by specified dates;
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our ability to meet the conditions precedent in our construction contract with Bechtel by December 31, 2012 in order to commence construction of the first two LNG trains;
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our ability to enter into additional satisfactory agreements with contractors and to maintain good relationships with these contractors in order to construct the proposed liquefaction facilities within the expected cost parameters, and the ability of those contractors to perform their obligations under the contracts and to maintain their creditworthiness;
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local and general economic conditions;
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catastrophes, such as explosions, fires and product spills;
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resistance in the local community to the project to add liquefaction capabilities at the Sabine Pass LNG terminal;
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labor disputes; and
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weather conditions, such as hurricanes.
Delays in the construction of the proposed liquefaction facilities at the Sabine Pass LNG terminal beyond the estimated development periods, as well as change orders to the EPC contract with Bechtel, could increase the cost of completion beyond the amounts that we estimate, which could require us to obtain additional sources of financing to fund our operations until the proposed liquefaction facilities are constructed (which could cause further delays). Any delay in completion of the proposed liquefaction facilities may also cause a delay in the receipt of revenues projected therefrom or cause a loss of one or more customers in the event of significant delays. As a result, any significant construction delay, whatever the cause, could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.
Cheniere Partners may not be successful in implementing its proposed business strategy to provide liquefaction capabilities at the Sabine Pass LNG terminal.
A significant element of our strategy to monetize our reserved capacity at the Sabine Pass LNG terminal is to develop liquefaction facilities at the terminal, construction of which has not yet commenced. Cheniere Partners' proposed liquefaction facilities will require very significant financial resources, which may not be available on terms reasonably acceptable to us or at all. Our contract with Bechtel to construct the first two LNG trains requires that we secure financing in the amount of the contract price by March 31, 2012 or Bechtel has the right to submit change orders, which may result in higher costs. Our SPAs with BG, Gas Natural Fenosa, GAIL and KOGAS also contain certain conditions precedent, including, but not limited to, receiving regulatory
approvals, securing necessary financing arrangements and making a final investment decision to construct the liquefaction facilities. If these conditions are not met by December 31, 2012 with respect to BG (for LNG train 1) and Gas Natural Fenosa and June 30, 2013 with respect to GAIL and KOGAS, either party may terminate the contract. In addition, if Sabine Pass Liquefaction has not made a positive final investment decision regarding the Train 2 Tranche, the Train 3 Tranche or the Train 4 Tranche by June 30, 2013, then BG may cancel such tranche(s) that are not yet decided affirmatively. If we are unable to obtain adequate and timely financing on satisfactory terms, Bechtel, BG, Gas Natural Fenosa, GAIL and KOGAS may terminate their respective contracts with us, and we may not be able to enter into contracts with another contractor or customer on similar terms or at all.
It will take several years to construct the liquefaction facilities, and we do not expect the first LNG train to be operational until at least 2015. Even if successfully constructed, the liquefaction facilities would be subject to many of the same operating risks described herein with respect to the Sabine Pass LNG terminal. Accordingly, there are many risks associated with Cheniere Partners' proposed liquefaction facilities, and if we are not successful in implementing our business strategy, we may not be able to generate additional cash flows, which could have a material adverse impact on our business, results of operations, financial condition, liquidity and prospects.
The cost of constructing Cheniere Partners' proposed liquefaction facilities will be dependent on several items, including change orders. As a result, if completed, the actual construction cost of these facilities may be significantly higher than our current estimates, which are before financing costs and contingencies.
As construction progresses, we may decide or be forced to submit change orders to Bechtel that could result in a longer construction period and higher construction costs. Our contract with Bechtel to construct the first two LNG trains requires that we secure financing in the amount of the contract price by March 31, 2012 or Bechtel has the right to submit change orders, which may result in higher costs. As a result, any significant change orders or increases in commodity prices could increase our anticipated costs and could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.
We are dependent on Bechtel and other contractors for the successful completion of Cheniere Partners' proposed liquefaction facilities.
Timely and cost-effective completion of Cheniere Partners' proposed LNG liquefaction facilities in compliance with agreed specifications is central to our business strategy and is highly dependent on contractors' performance under their agreements. Our contractors' ability to perform successfully under their contracts is dependent on a number of factors, including their ability to:
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design and engineer Cheniere Partners' proposed LNG liquefaction facilities to operate in accordance with specifications;
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engage and retain third-party subcontractors and procure equipment and supplies;
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respond to difficulties such as equipment failure, delivery delays, schedule changes and failure to perform by subcontractors, some of which are beyond their control;
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attract, develop and retain skilled personnel, including engineers;
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post required construction bonds and comply with the terms thereof;
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manage the construction process generally, including coordinating with other contractors and regulatory agencies; and
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maintain their own financial condition, including adequate working capital.
Although some contracts may provide for liquidated damages, if the contractor fails to perform in the manner required with respect to certain of its obligations, the events that trigger a requirement to pay liquidated damages may delay or impair the operation of the applicable LNG liquefaction facility, and any liquidated damages that we receive may not be sufficient to cover the damages that we suffer as a result of any such delay or impairment. Furthermore, we may have disagreements with our contractors about different elements of the construction process, which could lead to the assertion of rights and remedies under their contracts and increase the cost of the project or result in a contractor's unwillingness to perform further work on the project. If any contractor is unable or unwilling to perform according to the negotiated terms and timetable of its respective agreement for any reason or terminates its agreement, we would be required to engage a substitute contractor. This would likely result in significant project delays and increased costs, which could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.
We may not be able to purchase natural gas on economical terms or at all to satisfy our delivery obligations under the SPAs, which could have a material adverse effect on us.
Under the SPAs with our liquefaction customers, we are required to deliver to them a specified amount of LNG at specified times. However, we may not be able to purchase sufficient quantities of natural gas to satisfy those delivery obligations, which may provide affected SPA customers with the right to terminate their SPAs. Even if we are able to purchase sufficient quantities of natural gas, our cost to do so may be greater than the price that our SPA customers have agreed to pay for LNG under their SPAs. Our failure to purchase sufficient quantities of natural gas or to purchase natural gas at prices below what our SPA customers have agreed to pay for LNG could have a material adverse effect on our business, results of operations, financial condition and prospects.
Sabine Pass LNG terminal operations are and will be subject to significant operating hazards and uninsured risks, one or more of which may create significant liabilities and losses that could have a material adverse effect on us.
The operation of the Sabine Pass LNG terminal's regasification facilities is, and the proposed liquefaction facilities will be, subject to the inherent risks associated with these types of operations, including explosions, pollution, release of toxic substances, fires, hurricanes and adverse weather conditions, and other hazards, each of which could result in significant delays in commencement or interruptions of operations and/or in damage to or destruction of the Sabine Pass LNG terminal site and assets or damage to persons and property. In addition, operations at the Sabine Pass LNG terminal site and the facilities and vessels of third parties on which our operations are dependent face possible risks associated with acts of aggression or terrorism.
We do not, nor do we intend to, maintain insurance against all of these risks and losses. We may not be able to maintain desired or required insurance in the future at rates that we consider reasonable. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.
Risks Relating to Our Natural Gas Pipeline Business
Our existing and proposed pipelines will be dependent upon a few potential customers, and our pipeline business could be materially and adversely affected if we lost any one of those customers.
We do not currently have any third-party, firm transportation customers for our existing or proposed pipelines. We anticipate increased usage of the Creole Trail Pipeline to transport natural gas to the proposed liquefaction facilities at the Sabine Pass LNG terminal once construction of the liquefaction facilities is completed and the Creole Trail Pipeline has been modified. Failure to construct the Sabine Pass LNG liquefaction facilities, failure to make the capital improvements necessary to provide transportation to the Sabine Pass LNG liquefaction facilities, or failure to obtain any third-party, firm transportation customers could have a material adverse impact on our natural gas pipeline business.
Our natural gas pipelines, including their FERC gas tariffs, are subject to FERC regulation.
Our FERC tariffs contain pro forma transportation agreements, which must be filed and approved by the FERC. Before we enter into a transportation agreement with a shipper that contains a term that materially deviates from our tariff, we must seek FERC approval. The FERC may approve the material deviation in the transportation agreement; however, in that case, the materially deviating terms must be made available to our other similarly-situated customers. If we fail to seek FERC approval of a transportation agreement that materially deviates from our tariff, or if the FERC audits our contracts and finds deviations that appear to be unduly discriminatory, the FERC could conduct a formal enforcement investigation, resulting in serious penalties and/or onerous ongoing compliance obligations.
Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the EPAct, the FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1.0 million per day for each violation.
The FERC could change its current ratemaking policies, and those changes could have adverse effects on our pipelines.
Pipeline safety integrity programs and repairs may impose significant costs and liabilities on us.
The Federal Office of Pipeline Safety requires pipeline operators to develop integrity management programs to comprehensively evaluate certain areas along their pipelines and to take additional measures to protect pipeline segments located in “high consequence areas” where a leak or rupture could potentially do the most harm. As an operator, we are required to:
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perform ongoing assessments of pipeline integrity;
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identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
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improve data collection, integration and analysis;
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repair and remediate the pipeline as necessary; and
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implement preventative and mitigating actions.
We are required to maintain pipeline integrity testing programs that are intended to assess pipeline integrity. Any repair, remediation, preventative or mitigating actions may require significant capital and operating expenditures. Should we fail to comply with the Office of Pipeline Safety's rules and related regulations and orders, we could be subject to penalties and fines.
Any reduction in the capacity of, or the allocations to, interconnecting, third-party pipelines could cause a reduction of volumes transported in our pipelines, which would adversely affect our revenues and cash flow.
We will be dependent upon third-party pipelines and other facilities to provide delivery options to and from our pipelines. If any pipeline connection were to become unavailable for volumes of natural gas due to repairs, damage to the facility, lack of capacity or any other reason, our ability to continue shipping natural gas to end markets could be restricted, thereby reducing our revenues. Any permanent interruption at any key pipeline interconnect which caused a material reduction in volumes transported on our pipelines could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.
Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the development and operation of our natural gas pipelines would have a detrimental effect on us and our pipeline projects.
The design, construction and operation of natural gas pipelines and the transportation of natural gas are all highly regulated activities. FERC approval under Section 7 of the NGA, as well as several other material state governmental and regulatory approvals and permits, are required in order to construct and operate a pipeline. We must also obtain several other material governmental and regulatory approvals and permits in order to construct and operate pipelines, including several under the CAA and the CWA from the U.S. Army Corps of Engineers and state environmental agencies. We have no control over the timing of the review and approval process nor can we predict the outcome of the process. We do not know whether or when any such approvals or permits can be obtained, or whether or not any third parties will attempt to interfere with our ability to obtain and maintain such permits or approvals. If we are unable to obtain and maintain the necessary approvals and permits, we may not be able to recover our investment in the projects. Failure to obtain and maintain any of these approvals and permits could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.
Our pipeline business could be materially and adversely affected if we lose the right to situate our pipelines on property owned by third parties.
We do not own the land on which our pipelines are situated, and we are subject to the possibility of increased costs to retain necessary land use rights. If we were to lose these rights or be required to relocate our pipelines, our business could be materially and adversely affected.
Risks Relating to Our LNG and Natural Gas Marketing Business
Our use of hedging arrangements may adversely affect our future results of operations or liquidity.
To reduce our exposure to fluctuations in the price, volume and timing risk associated with the marketing of LNG and natural gas, we use futures, swaps and option contracts traded or cleared on the Intercontinental Exchange ("ICE") and NYMEX, or over-the-counter options and swaps with other natural gas merchants and financial institutions. Hedging arrangements would expose us to risk of financial loss in some circumstances, including when:
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expected supply is less than the amount hedged;
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the counterparty to the hedging contract defaults on its contractual obligations; or
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there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.
Our hedging arrangements may also limit the benefit that we would receive from increases in the prices for natural gas. The use of derivatives also may require the posting of cash collateral with counterparties, which can impact working capital when commodity prices change.
The limited capital resources and credit available to our LNG and natural gas marketing business may limit our ability to develop that business.
We have limited capital available to our LNG and natural gas marketing business. The business also currently has limited access to third-party sources of financing. Other investment-grade marketing companies have greater financial resources than we do. Our LNG and natural gas marketing business continues to develop and implement its business strategy and may not generate sufficient revenues and cash flows to cover the significant fixed costs of the business.
Our exposure to the performance and credit risks of counterparties under agreements may adversely affect our results of operations, liquidity and access to financing.
Our LNG and natural gas marketing business involves our entering into various purchase and sale, hedging and other transactions with numerous third parties (commonly referred to as "counterparties"). In such arrangements, we are exposed to the performance and credit risks of our counterparties, including the risk that one or more counterparties fails to perform its obligation to make deliveries of commodities and/or to make payments. These risks may increase during periods of commodity price volatility. Defaults by suppliers and other counterparties may adversely affect our results of operations, liquidity and access to financing.
Risks Relating to Our LNG Businesses in General
We may not construct or operate any additional LNG facilities beyond those currently planned, which could limit our growth prospects.
We may not construct some of our proposed LNG facilities, including the proposed Corpus Christi LNG terminal or natural gas pipelines, whether due to lack of commercial interest or inability to obtain financing or otherwise. Our ability to develop additional regasification or liquefaction facilities will also depend on the availability and pricing of LNG and natural gas in North America and other places around the world. Competitors may have longer operating histories, more development experience, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources and access to sources of natural gas and LNG than we do. If we are unable or unwilling to construct and operate additional LNG facilities, our prospects for growth will be limited.
Decreases in the demand for and price of natural gas could lead to reduced development of LNG projects worldwide, which could adversely affect the regasification component of our LNG businesses and the performance of our TUA customers and could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.
The development of domestic LNG facilities and LNG projects generally is based on assumptions about the future price of natural gas and the availability of natural gas. Natural gas prices have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to one or more of the following factors:
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relatively minor changes in the supply of, and demand for, natural gas in relevant markets;
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political conditions in natural gas producing regions;
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the extent of domestic production and importation of natural gas in relevant markets;
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the level of demand for LNG and natural gas in relevant markets, including the effects of economic downturns or upturns;
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weather conditions;
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the competitive position of natural gas as a source of energy compared with other energy sources; and
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the effect of government regulation on the production, transportation and sale of natural gas.
Adverse trends or developments affecting any of these factors could result in decreases in the price of natural gas, leading to reduced development of LNG projects worldwide. Such reductions could adversely affect the regasification component of our LNG businesses and the performance of our TUA customers and could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.
Cyclical or other changes in the demand for LNG capacity may adversely affect our LNG businesses and the performance of our customers and could reduce our operating revenues and may cause us operating losses.
The economics of our LNG businesses could be subject to cyclical swings, reflecting alternating periods of under-supply and over-supply of LNG import or export capacity and available natural gas, principally due to the combined impact of several factors, including:
•
additions to competitive regasification capacity in North America, Europe, Asia and other markets, which could divert LNG from the Sabine Pass LNG terminal;
•
competitive liquefaction capacity in North America, which could divert natural gas from Cheniere Partners' proposed liquefaction facilities at our existing and proposed LNG terminals;
•
insufficient or oversupply of LNG liquefaction or receiving capacity worldwide;
•
insufficient LNG tanker capacity;
•
reduced demand and lower prices for natural gas;
•
increased natural gas production deliverable by pipelines, which could suppress demand for LNG;
•
cost improvements that allow competitors to offer LNG regasification services or provide liquefaction capabilities at reduced prices;
•
changes in supplies of, and prices for, alternative energy sources such as coal, oil, nuclear, hydroelectric, wind and solar energy, which may reduce the demand for natural gas;
•
changes in regulatory, tax or other governmental policies regarding imported or exported LNG, natural gas or alternative energy sources, which may reduce the demand for imported or exported LNG and/or natural gas;
•
adverse relative demand for LNG compared to other markets, which may decrease LNG imports into or exports from North America; and
•
cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.
These factors could materially and adversely affect our ability, and the ability of our current and prospective customers, to procure supplies of LNG to be imported into North America and to procure customers for LNG or regasified LNG at economical prices, or at all.
Various economic and political factors could negatively affect the continued development of LNG facilities, including Cheniere Partners' proposed liquefaction facilities which could adversely affect our LNG businesses and could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.
Commercial development of an LNG facility takes a number of years, requires a substantial capital investment and may be delayed by factors such as:
•
increased construction costs;
•
economic downturns, increases in interest rates or other events that may affect the availability of sufficient financing for LNG projects on commercially reasonable terms;
•
decreases in the price of LNG and natural gas, which might decrease the expected returns relating to investments in LNG projects;
•
the inability of project owners or operators to obtain governmental approvals to construct or operate LNG facilities;
•
political unrest or local community resistance to the siting of LNG facilities due to safety, environmental or security concerns; and
•
any significant explosion, spill or similar incident involving an LNG facility or LNG vessel.
There may be shortages of LNG vessels worldwide, which could adversely affect our LNG businesses and could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.
The construction and delivery of LNG vessels require significant capital and long construction lead times, and the availability of the vessels could be delayed to the detriment of our LNG businesses and our customers because of:
•
an inadequate number of shipyards constructing LNG vessels and a backlog of orders at these shipyards;
•
political or economic disturbances in the countries where the vessels are being constructed;
•
changes in governmental regulations or maritime self-regulatory organizations;
•
work stoppages or other labor disturbances at the shipyards;
•
bankruptcy or other financial crisis of shipbuilders;
•
quality or engineering problems;
•
weather interference or a catastrophic event, such as a major earthquake, tsunami or fire; and
•
shortages of or delays in the receipt of necessary construction materials.
Terrorist attacks or military campaigns may adversely impact our LNG businesses.
A terrorist or military incident involving an LNG facility or LNG carrier may result in delays in, or cancellation of, construction of new LNG facilities, including our LNG terminals and related natural gas pipelines and proposed liquefaction facilities, which would increase our costs and decrease our cash flows. A terrorist incident may also result in temporary or permanent closure of existing LNG facilities, including ours, which could increase our costs and decrease our cash flows, depending on the duration of the closure. Operations at our LNG facilities could also become subject to increased governmental scrutiny that may result in additional security measures at a significant incremental cost to us. In addition, the threat of terrorism and the impact of military campaigns may lead to continued volatility in prices for natural gas that could adversely affect our LNG businesses and our customers, including their ability to satisfy their obligations to us under the commercial agreements.
Risks Relating to Our Business in General
We are subject to significant operating hazards and uninsured risks, one or more of which may create significant liabilities and losses for us.
The construction and operation of our LNG terminals, including Cheniere Partners' proposed liquefaction facilities, and pipelines are and will be subject to the inherent risks associated with these types of operations, including explosions, pollution, release of toxic substances, fires, hurricanes and adverse weather conditions, and other hazards, each of which could result in significant delays in commencement or interruptions of operations and/or in damage to or destruction of our facilities or damage to persons and property. In addition, our operations and the facilities and vessels of third parties on which our operations are dependent face possible risks associated with acts of aggression or terrorism.
We do not, nor do we intend to, maintain insurance against all of these risks and losses. We may not be able to maintain desired or required insurance in the future at rates that we consider reasonable. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.
Existing and future environmental and similar laws and regulations could result in increased compliance costs or additional operating costs or construction costs and restrictions.
Our business is and will be subject to extensive federal, state and local laws and regulations that control, among other things, discharges to air and water; the handling, storage and disposal of hazardous chemicals, hazardous waste, and petroleum products; and remediation associated with the release of hazardous substances. Many of these laws and regulations, such as the CAA, the Oil Pollution Act, the CWA and the RCRA, and analogous state laws and regulations, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with the construction and operation of our LNG terminals, including liquefaction facilities, and pipelines and require us to maintain permits and provide governmental authorities with access to our facilities for inspection and reports related to our compliance. Violation of these laws and regulations could lead to substantial fines and penalties or to capital expenditures related to pollution control equipment that could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects. Federal and state laws impose liability, without regard to fault or the lawfulness of the original conduct, for the release of certain types or quantities of hazardous substances into the environment. As the owner and operator of an LNG terminal, including a liquefaction facility, or pipeline, we could be liable for the costs of cleaning up hazardous substances released into the environment and for damage to natural resources.
There are numerous regulatory approaches currently in effect or being considered to address greenhouse gases, including possible future U.S. treaty commitments, new federal or state legislation that may impose a carbon emissions tax or establish a cap-and-trade program, and regulation by the EPA. For example, the adoption of frequently proposed legislation implementing a carbon tax on energy sources that emit carbon dioxide into the atmosphere may have a material adverse effect on the ability of our customers (i) to import LNG, if imposed on them as importers of potential emission sources, or (ii) to sell regasified LNG, if imposed on them or their customers as natural gas suppliers or consumers. In addition, as we consume retainage gas at the Sabine Pass LNG terminal, this carbon tax may also be imposed on us directly.
Other future legislation and regulations, such as those relating to the transportation and security of LNG imported to or exported from the Sabine Pass LNG terminal through the Sabine Pass Channel, could cause additional expenditures, restrictions and delays in our business and to our proposed construction, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances. Revised, reinterpreted or additional laws and regulations that result in increased compliance costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.
We may experience increased labor costs, and the unavailability of skilled workers or our failure to attract and retain key personnel could adversely affect us.
We are dependent upon the available labor pool of skilled employees. We compete with other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to construct and operate our LNG terminals, liquefaction facilities and pipelines and to provide our customers with the highest quality service. A shortage in the labor pool of skilled workers or other general inflationary pressures or changes in applicable laws and regulations could make it more difficult for us to attract and retain personnel and could require an increase in the wage and benefits packages that we offer, thereby increasing our operating costs. For example, in the aftermaths of Hurricanes Katrina and Rita, Bechtel and certain subcontractors temporarily experienced a shortage of available skilled labor necessary to meet the requirements of the Sabine Pass LNG terminal construction plan. As a result, we agreed to change orders with Bechtel concerning additional activities and expenditures to mitigate the hurricanes' effects on the construction of the Sabine Pass LNG terminal. Any increase in our operating costs could materially and adversely affect our business, results of operations, financial condition, liquidity and prospects.
We depend on our executive officers for various activities. We do not maintain key person life insurance policies on any of our personnel. Although we have arrangements relating to compensation and benefits with certain of our executive officers, we do not have any employment contracts or other agreements with key personnel binding them to provide services for any particular term. The loss of the services of any of these individuals could seriously harm us.
Our lack of diversification could have an adverse effect on our financial condition and results of operations.
Substantially all of our anticipated revenue in 2012 will be dependent upon one facility, the Sabine Pass LNG receiving terminal and related pipeline located in southern Louisiana. Due to our lack of asset and geographic diversification, an adverse development at the Sabine Pass LNG terminal or pipeline, or in the LNG industry, would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets and operating areas.
We may engage in operations or make substantial commitments and investments located, or enter into agreements with counterparties located, outside the United States, which would expose us to political, governmental and economic instability and foreign currency exchange rate fluctuations.
Conducting operations or making commitments and investments located, or entering into agreements with counterparties located, outside of the United States will cause us to be affected by economic, political and governmental conditions in the countries where we engage in business. Any disruption caused by these factors could harm our business. Risks associated with operations, commitments and investments outside of the United States include the risks of:
•
currency fluctuations;
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war;
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expropriation or nationalization of assets;
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renegotiation or nullification of existing contracts;
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changing political conditions;
•
changing laws and policies affecting trade, taxation and investment;
•
multiple taxation due to different tax structures; and
•
the general hazards associated with the assertion of sovereignty over certain areas in which operations are conducted.
Because our reporting currency is the United States dollar, any of our operations conducted outside the United States or denominated in foreign currencies would face additional risks of fluctuating currency values and exchange rates, hard currency shortages and controls on currency exchange. We would be subject to the impact of foreign currency fluctuations and exchange rate changes on our reporting for results from those operations in our consolidated financial statements.
We may incur impairments to goodwill or long-lived assets.
We review our long-lived assets, including goodwill and other intangible assets, for impairment annually in the fourth quarter or whenever events or changes in circumstances indicate that the carrying amount of these assets may not be recoverable. 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 to our 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.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. In the opinion of management, as of December 31, 2011, there were no threatened or pending legal matters that would have a material impact on our consolidated results of operations, financial position or cash flows.
ITEM 4.
ITEM 4. MINE SAFETY DISCLOSURE
None.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER
PURCHASES OF EQUITY SECURITIES
Our common stock has traded on the NYSE Amex Equities under the symbol LNG since March 24, 2003. The table below presents the high and low daily closing sales prices of the common stock, as reported by the NYSE Amex Equities, for each quarter during 2010 and 2011.
As of February 15, 2012, we had 129.6 million shares of common stock outstanding held by approximately 241 record owners.
We have never paid a cash dividend on our common stock. We currently intend to retain earnings to finance the growth and development of our business and do not anticipate paying any cash dividends on the common stock in the foreseeable future. Any future change in our dividend policy will be made at the discretion of our board of directors in light of our financial condition, capital requirements, earnings, prospects and any restrictions under any financing agreements, as well as other factors the board of directors deems relevant.
Issuer Purchases of Equity Securities
During the twelve months ended December 31, 2011, we purchased 1.9 million shares of restricted stock at an average cash price of $8.42 per share related to restricted stock that vested during 2011 and that was returned to the Company by employees to cover taxes.
Total Stockholder Return
The following graph compares the cumulative total stockholder return on our common stock against the S&P Oil and Gas Exploration and Production Index, and the Russell 2000 Index for the five years ended December 31, 2011. The graph was constructed on the assumption that $100 was invested in our common stock, the S&P Oil & Gas Exploration & Production Index and the Russell 2000 Index on December 31, 2006 and that any dividends were fully reinvested.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
Selected financial data set forth below are derived from our audited consolidated financial statements for the periods indicated. The financial data should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and our Consolidated Financial Statements and the accompanying notes thereto included elsewhere in this report.
(1)
General and administrative expense includes $24.4 million, $16.1 million, $19.2 million, $55.0 million, and $56.6 million share-based compensation expense recognized in the years ended December 31, 2011, 2010, 2009, 2008, and 2007 respectively.
(2)
In the second quarter of 2008, we announced a cost savings program in connection with the downsizing of our natural gas marketing business activities, the nearing completion of significant construction activities for both the Sabine Pass LNG terminal and Creole Trail Pipeline and the seeking of alternative arrangements for our time charter interest in two LNG vessels.
(3)
In 2010, our investment in Freeport LNG Development, L.P. ("Freeport LNG") was sold, generating net cash proceeds of $104.3 million and a gain to Cheniere of $128.3 million.
(4)
Amount in 2010 relates to the cost to amend certain provisions of our 2008 Loans (described below under "Debt Agreements"). Amount in 2009 relates to gains on the termination of $120.4 million of our Convertible Senior Unsecured Notes. Amount in 2008 relates to losses on the termination of a $95.0 million bridge loan in August 2008. See Note 15-"Debt and Debt-Related Parties" of our Notes to Consolidated Financial Statements.
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATION
Introduction
The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our Consolidated Financial Statements and the accompanying notes in "Financial Statements and Supplementary Data." This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future. Our discussion and analysis include the following subjects:
•
Overview of Business
•
Overview of Significant Events
•
Liquidity and Capital Resources
•
Contractual Obligations
•
Results of Operations
•
Off-Balance Sheet Arrangements
•
Inflation and Changing Prices
•
Summary of Critical Accounting Policies and Estimates
•
Recent Accounting Standards
Overview of Business
We own and operate the Sabine Pass LNG terminal in Louisiana through our 88.8% ownership interest in and management agreements with Cheniere Energy Partners, L.P. ("Cheniere Partners") (NYSE Amex Equities: CQP), which is a publicly traded partnership that we created in 2007. We also own and operate the Creole Trail Pipeline, which interconnects the Sabine Pass LNG terminal with natural gas markets in North America. One of our subsidiaries, Cheniere Marketing, LLC ("Cheniere Marketing"), is marketing LNG and natural gas on its own behalf and on behalf of Cheniere Partners, and is working to monetize LNG storage and regasification capacity reserved by Cheniere Partners at the Sabine Pass LNG terminal. Cheniere Partners is developing a project to add liquefaction capabilities at the Sabine Pass LNG terminal. We are in various stages of developing other projects, including LNG terminal and pipeline related projects, each of which, among other things, will require acceptable commercial and financing arrangements before we make a final investment decision.
Overview of Significant Events
Our significant accomplishments since January 1, 2011 include the following:
•
In January 2011, Sabine Pass Liquefaction, LLC ("Sabine Pass Liquefaction") and Sabine Pass LNG, L.P. ("Sabine Pass LNG"), each a wholly owned subsidiary of Cheniere Partners, submitted an application to the FERC requesting authorization to site, construct and operate liquefaction and export facilities at the Sabine Pass LNG terminal.
•
In January 2011, Cheniere Partners initiated an at-the-market program to sell up to 1.0 million of its common units, the proceeds from which are being used for general business purposes, including to fund development costs associated with its liquefaction project. As of December 31, 2011, Cheniere Partners had sold 0.5 million common units with net proceeds of $9.0 million.
•
In May 2011, Sabine Pass Liquefaction received an order from the U.S. Department of Energy ("DOE") with authorization to export domestically produced natural gas from the Sabine Pass LNG terminal as LNG to any country that has, or in the future develops, the capacity to import LNG and with which trade is permissible.
•
In June 2011, we sold 12.7 million shares of Cheniere common stock in an underwritten public offering for net cash proceeds of $123.1 million.
•
In September 2011, Cheniere Partners sold 3.0 million common units in an underwritten public offering and 1.1 million common units to Cheniere Common Units Holding, LLC, a wholly owned subsidiary of Cheniere, at a price of $15.25 per common unit. Cheniere Partners received net proceeds from this offering of approximately $60 million that it is using for general business purposes, including development costs of its project to add liquefaction capacity at the Sabine Pass LNG terminal.
•
In September 2011, we initiated an at-the-market program to sell up to 10.0 million shares of Cheniere common stock. As of December 31, 2011, we had sold 1.5 million shares with net proceeds of $14.4 million.
•
In October 2011, Sabine Pass Liquefaction entered into its first LNG sale and purchase agreement ("SPA") with BG Gulf Coast LNG, LLC ("BG"), an affiliate of BG Energy Holdings Limited, under which BG agreed to purchase 182.5 million MMBtu of LNG per year (approximately 3.5 mtpa). This agreement was amended in January 2012 to increase the amount of LNG that BG has agreed to purchase to 286.5 million MMBtu of LNG per year (approximately 5.5 mtpa).
•
In November 2011, Sabine Pass Liquefaction entered into an SPA with Gas Natural Aprovisionamientos SDG S.A. ("Gas Natural Fenosa"), an affiliate of Gas Natural SDG S.A., under which Gas Natural Fenosa has agreed to purchase 182.5 million MMBtu of LNG per year (approximately 3.5 mtpa).
•
In November 2011, Sabine Pass Liquefaction entered into a lump sum turnkey engineering, procurement and construction ("EPC") agreement with Bechtel Oil, Gas and Chemicals, Inc. ("Bechtel") for the first two LNG trains and related facilities at the Sabine Pass LNG terminal. The agreement provides that Sabine Pass Liquefaction will pay Bechtel a contract price of $3.9 billion, which is subject to adjustment by change order.
•
In December 2011, Sabine Pass Liquefaction entered into an SPA with GAIL (India) Limited ("GAIL"), under which GAIL has agreed to purchase 182.5 million MMBtu of LNG per year (approximately 3.5 mtpa). Prior to the commencement of LNG train 4 operations, GAIL will purchase bridge volumes of approximately 0.2 mtpa upon the commencement of operations of LNG train 2.
•
In December 2011, we sold 41.7 million shares of Cheniere common stock in an underwritten public offering for net cash proceeds of approximately $330.9 million.
•
In January 2012, we repaid in full the entire outstanding principal balance of the 2007 Term Loans due May 31, 2012. We used a portion of the net proceeds from the public offering of common stock in December 2011 to repay the 2007 Term Loan.
•
In January 2012, Sabine Pass Liquefaction entered into an SPA with Korea Gas Corporation ("KOGAS"), under which KOGAS agreed to purchase 182.5 million MMBtu of LNG per year (approximately 3.5 mtpa).
Liquidity and Capital Resources
Although consolidated for financial reporting, Cheniere, Sabine Pass LNG and Cheniere Partners operate with independent capital structures. We expect the cash needs for Sabine Pass LNG's operating activities for at least the next twelve months will be met through operating cash flows and existing unrestricted cash. We expect the cash needs for Cheniere Partners' operating activities for at least the next twelve months will be met through operating cash flows from Sabine Pass LNG and existing unrestricted cash. We expect the cash needs of Cheniere's operating activities for at least the next twelve months will be met by utilizing existing unrestricted cash, management fees from Sabine Pass LNG and Cheniere Partners, distributions from our investment in Cheniere Partners and operating cash flows from our pipeline and LNG and natural gas marketing businesses.
The following table presents (in thousands) Cheniere's restricted and unrestricted cash and cash equivalents for each portion of our capital structure as of December 31, 2011. All restricted and unrestricted cash and cash equivalents held by Cheniere Partners and Sabine Pass LNG are considered restricted as to usage or withdrawal by Cheniere:
(1)
All cash and cash equivalents presented above for Sabine Pass LNG are considered restricted to us, but $4.3 million is considered unrestricted for Sabine Pass LNG.
(2)
All cash and cash equivalents presented above for Cheniere Partners are considered restricted to us, but $81.4 million is considered unrestricted for Cheniere Partners, including the $4.3 million considered unrestricted for Sabine Pass LNG.
As of December 31, 2011, we had unrestricted cash and cash equivalents of $459.2 million available to Cheniere. In addition, we had consolidated restricted cash and cash equivalents of $185.1 million (which included cash and cash equivalents and other working capital available to Cheniere Partners, in which we own an 88.8% interest, and Sabine Pass LNG) designated for the following purposes: $96.1 million for interest payments related to the Senior Notes described below; $4.3 million for Sabine Pass LNG's working capital; $77.1 million for Cheniere Partners' working capital; and $7.5 million for other restricted purposes.
During the second quarter of 2011, we reclassified $298.0 million of debt from a long-term liability to a current liability because our 2007 Term Loan described below was due within 12 months as of May 31, 2011. During the third quarter of 2011, we reclassified $190.7 million, net of discount, of debt from a long-term liability to a current liability because our Convertible Senior Unsecured Notes were due within 12 months as of August 15, 2011. In December 2011, we closed an underwritten public offering of 41,745,000 shares of our common stock, which were sold to the public at a price per share of $8.35, resulting in net proceeds of approximately $330.9 million. In January 2012, we used a portion of the net proceeds to repay in full the outstanding principal balance of the $298.0 million 2007 Term Loan due May 31, 2012. The aggregate repayment amount was $298.2 million, including the outstanding principal amount and accrued interest through January 5, 2012.
In September 2011, we initiated an at-the-market program to sell up to 10 million shares of our common stock. As of December 31, 2011, we had sold 1.5 million shares with net proceeds of $14.4 million. During the year ended December 31, 2011, we paid $0.4 million in commissions to Miller Tabak + Co., Inc., as sales agent, in connection with the at-the-market program.
We believe that we will have sufficient unrestricted cash, liquid assets, cash generated from our operations and proceeds from capital market transactions to satisfy our debt obligations and fund our operations for at least the next 12 months. In order to satisfy our principal payment due on our Convertible Senior Unsecured Notes in August 2012, we will need to extend, refinance or repay such indebtedness, which may be accomplished by refinancing our existing indebtedness, raising capital by issuing equity, debt or other securities or using cash generated from selling assets or through a combination of the foregoing and will be dependent on factors such as worldwide natural gas and capital market conditions.
LNG Terminal Business
Cheniere Partners
Our ownership interest in the Sabine Pass LNG terminal is held through Cheniere Partners. We own approximately 88.8% of Cheniere Partners in the form of 12.0 million common units, 135.4 million subordinated units and a 2% general partner interest. Cheniere Partners owns a 100% interest in Sabine Pass LNG, which is operating the Sabine Pass LNG terminal, and a 100% interest in Sabine Pass Liquefaction, which is developing a liquefaction project at the Sabine Pass LNG terminal.
We receive quarterly equity distributions from Cheniere Partners, and we receive management fees for managing Sabine Pass LNG and Cheniere Partners. For the year ended December 31, 2011, we received $19.0 million in distributions on our common units, no distributions on our subordinated units and $1.0 million in distributions on our general partner interest. During the year ended December 31, 2011, we received fees of $10.8 million and $8.1 million under our management agreements with Cheniere Partners and Sabine Pass LNG, respectively.
Cheniere Partners' common unit and general partner distributions are being funded from cash flows generated by Sabine Pass LNG's two third-party TUA customers. The subordinated unit distributions that we received in 2010 were funded from cash flows generated by Sabine Pass LNG's TUA with Cheniere Marketing. Effective July 1, 2010, Cheniere Marketing assigned its TUA with Sabine Pass LNG for 2.0 Bcf/d of regasification capacity at the Sabine Pass LNG terminal to Cheniere Energy Investments, LLC ("Cheniere Investments"), a wholly owned subsidiary of Cheniere Partners. As a result of Cheniere Marketing's assignment of its TUA to Cheniere Investments, we have not received distributions on our subordinated units since the distribution made with respect to the quarter ended March 31, 2010.
During the subordination period, the common units have the right to receive distributions of available cash from operating surplus in an amount equal to the initial quarterly distribution of $0.425 per quarter, plus any arrearages in the payment of the initial quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units that we own. As a result of Cheniere Marketing's assignment of its TUA to Cheniere Investments, Cheniere Marketing no longer makes the approximately $250 million per year of payments to Sabine Pass LNG, and Cheniere Partners will not make distributions on our subordinated units unless it generates additional cash flow from Sabine Pass LNG's excess capacity or new business. Therefore, distributions to us on our subordinated units and conversion of the subordinated units into common units will depend upon the future business development of Cheniere Partners. We expect that additional cash flows generated by Cheniere Partners' proposed liquefaction project or other new Cheniere Partners' business would be used to make quarterly distributions on our subordinated units before any increase in distributions to the common unitholders.
We and Cheniere Partners amended, effective as of July 1, 2010, the fee structure for the various general and administrative services provided by us for Cheniere Partners' benefit and changed it from a fixed fee to a variable fee. The amended and restated services agreement provides that fees will be paid quarterly from Cheniere Partners' unrestricted cash and cash equivalents remaining after making distributions to the common unitholders and the general partner in respect of each quarter and retaining certain reserves. Our ability to receive management fees from Cheniere Partners is dependent on our ability to, among other things, manage Cheniere Partners' and Sabine Pass LNG's operating and administrative expenses, monetize the 2.0 Bcf/d of regasification capacity under the Cheniere Investments TUA (as discussed below) and develop new projects through either internal development or acquisition to increase cash flow. The fixed management fees payable by Sabine Pass LNG remain unchanged.
Concurrently with the TUA assignment, Cheniere Investments entered into a Variable Capacity Rights Agreement ("VCRA") with Cheniere Marketing. Under the terms of the VCRA, Cheniere Marketing is responsible for monetizing Cheniere Investments' TUA capacity at the Sabine Pass LNG terminal and is obligated to pay Cheniere Investments 80% of the expected gross margin of each cargo of LNG it arranges for delivery to the Sabine Pass LNG terminal. To the extent payments from Cheniere Marketing to Cheniere Investments under the VCRA or new Cheniere Partners' business increase Cheniere Partners' available cash in excess of the common unit and general partner distributions and certain reserves, the cash would be distributed to us in the form of distributions on our subordinated units and related general partner distributions. During the term of the VCRA, Cheniere Marketing is responsible for the payment of taxes and new regulatory costs under Cheniere Investments' TUA. Cheniere has guaranteed all of Cheniere Marketing's payment obligations under the VCRA.
In January 2011, Cheniere Partners initiated an at-the-market program to sell up to 1.0 million common units, the proceeds from which are used primarily to fund development costs associated with its proposed liquefaction project at the Sabine Pass LNG terminal. As of December 31, 2011, Cheniere Partners had sold 0.5 million common units with net proceeds of $9.0 million.
In September 2011, Cheniere Partners sold 3.0 million common units in an underwritten public offering and 1.1 million common units to Cheniere Common Units Holding, LLC at a price of $15.25 per common unit. Cheniere Partners received net proceeds of approximately $60 million from this offering that it is using for general business purposes, including development costs associated with its proposed liquefaction project at the Sabine Pass LNG terminal.
Sabine Pass LNG Terminal
Approximately 2.0 Bcf/d of regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term third-party TUAs, under which Sabine Pass LNG’s customers are required to pay fixed monthly fees, whether or not they use the LNG terminal. Capacity reservation fee TUA payments are made by Sabine Pass LNG's third-party TUA customers as follows:
•
Total Gas and Power North America, Inc. ("Total") has reserved approximately 1.0 Bcf/d of regasification capacity and is obligated to make monthly capacity payments to Sabine Pass LNG aggregating approximately $125 million per year for 20 years that commenced April 1, 2009. Total, S.A. has guaranteed Total’s obligations under its TUA up to $2.5 billion, subject to certain exceptions; and
•
Chevron U.S.A. Inc. ("Chevron") has reserved approximately 1.0 Bcf/d of regasification capacity and is obligated to make monthly capacity payments to Sabine Pass LNG aggregating approximately $125 million per year for 20 years that commenced July 1, 2009. Chevron Corporation has guaranteed Chevron’s obligations under its TUA up to 80% of the fees payable by Chevron.
Each of Total and Chevron previously paid Sabine Pass LNG $20.0 million in nonrefundable advance capacity reservation fees, which are being amortized over a 10-year period as a reduction of each customer's regasification capacity reservation fees payable under its respective TUA.
The remaining approximately 2.0 Bcf/d of regasification capacity has been reserved by Cheniere Partners through a TUA between Cheniere Investments and Sabine Pass LNG. Cheniere Investments is obligated to make monthly capacity payments to Sabine Pass LNG aggregating approximately $250 million per year through at least September 30, 2028; however, the revenue earned by Sabine Pass LNG from Cheniere Investments' capacity payments under the TUA is eliminated upon consolidation of our financial statements.
Under each of these TUAs, Sabine Pass LNG is entitled to retain 2% of the LNG delivered for the customer's account.
Cheniere Partners is also developing proposed liquefaction facilities at the Sabine Pass LNG terminal. As currently contemplated, the liquefaction facilities are designed for up to four LNG trains, each with a nominal production capacity of approximately 4.5 mtpa. We expect to commence construction of LNG trains 1 and 2 during the first half of 2012 and begin operations in 2015, with each LNG train commencing operations approximately six to nine months after the previous LNG train. We estimate that the aggregate total cost to complete construction of the proposed liquefaction facilities will be approximately $9.0 billion to $10.0 billion, before financing costs. Our cost estimates are subject to change due to such items as change orders, increased component and material costs, escalation of labor costs and increased spending to maintain our construction schedule.
In November 2011, Sabine Pass Liquefaction entered into a lump-sum turnkey EPC agreement with Bechtel for construction of LNG trains 1 and 2 of the liquefaction project for $3.9 billion. The contract price is only subject to adjustment by change order, including by Bechtel if it is adversely affected as a result of a delay in the commencement of construction beyond March 31, 2012.
As of December 31, 2011, Cheniere Partners had paid $45.9 million of development costs relating to the proposed liquefaction facilities using its cash from operations and equity proceeds from the issuance of 4.1 million common units in September 2011. We expect to finance the construction costs of the proposed liquefaction project from a combination of project financing and debt and equity offerings.
Other LNG terminals
We will contemplate making final investment decisions to construct our proposed Corpus Christi LNG terminal and any other LNG terminal project upon, among other things, entering into acceptable commercial and financing arrangements for the applicable project.
Natural Gas Pipeline Business
The Creole Trail Pipeline, consisting of 94 miles of natural gas pipeline, is currently in-service and operating. Cheniere Marketing and other third parties have entered into interruptible transportation agreements with Creole Trail Pipeline to transport natural gas from the Sabine Pass LNG terminal into North American natural gas markets. Although Cheniere Marketing and other third parties have entered into interruptible transportation agreements with Creole Trail Pipeline to transport natural gas from the Sabine Pass LNG terminal into North American natural gas markets, there are no significant cash flows generated from the Creole Trail Pipeline.
In connection with Cheniere Partners’ proposed liquefaction facilities at the Sabine Pass LNG terminal, we are developing a project to add additional capabilities to the Creole Trail Pipeline to be able to provide transportation services to the liquefaction facilities.
We will contemplate making a final investment decision to construct the remaining 59 miles of the Creole Trail Pipeline, the Corpus Christi Pipeline, the Cheniere Southern Trail Pipeline and the Burgos Hub project upon, among other things, receiving all required authorizations to construct and operate the applicable pipeline (and storage facility in the case of the Burgos Hub project), to the extent not already obtained, and entering into acceptable commercial and financing arrangements for the applicable project. We do not expect to spend significant funds on these projects in the near-term.
LNG and Natural Gas Marketing Business
The accounting treatment for LNG inventory differs from the treatment for derivative positions such that the economics of Cheniere Marketing's activities are not transparent in our consolidated financial statements until all LNG inventory is sold and all derivative positions are settled. Our LNG inventory is recorded as an asset at cost and is subject to lower of cost or market ("LCM") adjustments at the end of each reporting period. The LCM adjustment market price is based on period-end natural gas spot prices, and any gain or loss from an LCM adjustment is recorded in our earnings at the end of each period. Revenue and cost of goods sold are not recognized in our earnings until the LNG is sold. Generally, our unrealized derivatives positions at the end of each period extend into the future to hedge the cash flow from future sales of our LNG inventory or to take market positions and hedge exposure associated with LNG and natural gas. These positions are measured at fair value, and we record the gains and losses from the change in their fair value currently in earnings. Thus, earnings from changes in the fair value of our derivatives may not be offset by losses from LCM adjustments to our LNG inventory because the LCM adjustments that may be made to LNG inventory are based on period-end spot prices that are different from the time periods of the prices used to fair value our derivatives. Any losses from changes in the fair value of our derivatives will not be offset by gains until the LNG is actually sold.
LNGCo Agreements
In 2010, Cheniere Marketing entered into various agreements ("LNGCo Agreements") with JPMorgan LNG Co. ("LNGCo") under which Cheniere Marketing has agreed to develop and maintain commercial and trading opportunities in the LNG industry and present any such opportunities exclusively to LNGCo. Cheniere Marketing also agreed to provide, or arrange for the provision of, all of the operations and administrative services required by LNGCo in connection with any LNG cargoes purchased by LNGCo, including negotiating agreements and arranging for transporting, receiving, storing, hedging and regasifying LNG cargoes. Cheniere Marketing does not have the authority to contractually bind LNGCo under the LNGCo Agreements. In the event LNGCo declines to purchase an LNG cargo presented to it by Cheniere Marketing under the LNGCo Agreements, Cheniere Marketing may pursue the opportunity on its own behalf or present it to third parties. The term of the LNGCo Agreements expires in April 2012; however, either party may terminate the agreements without penalty prior to such date. In return for the services to be provided by Cheniere Marketing, LNGCo will pay a fixed fee to Cheniere Marketing and may pay additional fees depending upon the gross margins of each transaction and the aggregate gross margin earned during the term of the LNGCo Agreements.
During the years ended December 31, 2011 and 2010, we recognized $12.0 million and $10.1 million, respectively, of marketing and trading revenues from LNGCo. As of December 31, 2011, the carrying amount of Cheniere Marketing’s assets relating to LNGCo, which is equivalent to Cheniere Marketing's maximum exposure to loss, was $3.0 million. A portion of this $3.0 million represents our fixed fee receivable and is reported as accounts and interest receivable on our consolidated financial statements, and the remaining portion represents our margin deposit receivable and is reported as prepaid expense and other current assets on our consolidated financial statements and is to be paid to Cheniere Marketing upon the completion or termination of the LNGCo Agreements.
Corporate and Other Activities
We are required to maintain corporate general and administrative functions to serve our business activities described above.
Sources and Uses of Cash
The following table summarizes (in thousands) the sources and uses of our cash and cash equivalents for the years ended December 31, 2011, 2010 and 2009. The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, that are referred to elsewhere in this report. Additional discussion of these items follows the table.
Sale of Common Stock, net
In June 2011, we sold 12.7 million shares of Cheniere common stock in an underwritten public offering at a price of $10.35 per share. In December 2011, we sold 41.7 million shares of common stock in an underwritten public offering at a price of $8.35 per share. The Company intends to use the net proceeds from the offerings for general corporate purposes, including repayment of indebtedness.
Sale of Common Units by Cheniere Partners
In January 2011, Cheniere Partners initiated an at-the-market program to sell up to 1.0 million common units, the proceeds from which have primarily been used to fund development costs associated with Cheniere Partners' proposed liquefaction project at the Sabine Pass LNG terminal. As of December 31, 2011, Cheniere Partners had received $9.0 million in net proceeds from its sale of common units related to this at-the-market program.
In September 2011, Cheniere Partners sold 3.0 million common units in an underwritten public offering and 1.1 million common units to our subsidiary, Cheniere Common Units Holding, LLC, at a price of $15.25 per common unit. Cheniere Partners is using the net proceeds from the offering for general business purposes, including development costs for the proposed liquefaction facilities at the Sabine Pass LNG terminal.
Use of Restricted Cash and Cash Equivalents
In 2010, the $34.4 million of restricted cash and cash equivalents was used primarily to make distributions of $26.4 million to non-controlling interest holders, pay for construction activities at the Sabine Pass LNG terminal of $4.2 million and incur costs for other individually immaterial items of $3.8 million.
In 2009, the $241.1 million of restricted cash and cash equivalents was used primarily to pay for construction activities at the Sabine Pass LNG terminal of $112.3 million, and to make distributions of $26.4 million to non-controlling interest holders. In addition, in June 2009, through an amendment of the 2008 Loans described below, we moved $65.2 million out of the TUA reserve account into an unrestricted cash and cash equivalents account.
The decreased use of restricted cash and cash equivalents during 2010 primarily resulted from substantially completing construction of the Sabine Pass LNG terminal during the third quarter of 2009, and the decreased use in 2009 primarily resulted from completing construction of the initial sendout capacity of approximately 2.6 Bcf/d and storage capacity of approximately 10.1 Bcf at the Sabine Pass LNG terminal in September 2008.
Distribution from Limited Partner Investment in Freeport LNG
In 2010 and 2009, we received $3.9 million and $15.3 million of distributions from Freeport LNG, respectively. In May 2010, we sold our investment in Freeport LNG and, therefore, have not received distributions since that date.
Proceeds from Sale of Limited Partner Investment in Freeport LNG
We sold our 30% limited partner interest in Freeport LNG to institutional investors for net proceeds of $104.3 million and used $102.0 million of the proceeds to prepay principal of the 2007 Term Loan in June 2010.
Operating Cash Flow
Net cash used in operations was $42.8 million, $16.9 million and $97.9 million in 2011, 2010 and 2009, respectively. Net cash used in operations related primarily to the general administrative overhead costs, pipeline operations costs and LNG and natural gas marketing overhead, offset by earnings from our LNG and natural gas marketing business. The increase in 2011 compared to 2010 primarily resulted from increased costs incurred to develop the proposed liquefaction project at the Sabine Pass LNG terminal. The decrease in 2010 compared to 2009 primarily resulted from Sabine Pass LNG beginning to receive capacity reservation fee payments from Total and Chevron during 2009.
Repurchases and Prepayments of Debt
In 2010 and 2009, we used $104.7 million and $30.0 million, respectively, of cash and cash equivalents to repay/repurchase a portion of our long-term debt.
In the second quarter of 2010, we used $102.0 million of the net proceeds from the sale of our limited partner interest in Freeport LNG to partially prepay the 2007 Term Loan. In addition, as a result of the assignment of the Cheniere Marketing TUA to Cheniere Investments in the second quarter of 2010, we used $2.7 million to partially prepay the 2008 Loans. In the second quarter of 2009, we used a combination of $30.0 million cash and cash equivalents and 4.0 million shares of Cheniere common stock to prepay $120.4 million aggregate principal amount of our Convertible Senior Unsecured Notes.
Distributions to Non-controlling Interest Holders
During 2011, 2010 and 2009, Cheniere Partners distributed $28.2 million, $26.4 million and $26.4 million, respectively, to its non-affiliated common unitholders.
Investment in Cheniere Partners
In September 2011, we invested $17.8 million in Cheniere Partners related to our purchase of 1.1 million common units concurrent with an underwritten public offering of 3.0 million common units at a price of $15.25 per common unit. Cheniere Partners is using the net proceeds from the offering for general business purposes, including the development costs of its project to add liquefaction capacity at the Sabine Pass LNG terminal.
LNG Terminal and Pipeline Construction-in-process, net
Capital expenditures for our LNG terminals and pipeline projects were $8.9 million, $4.2 million and $112.3 million in 2011, 2010 and 2009, respectively. The significant decrease in capital expenditures in 2011 and 2010 compared to 2009 is a result of the substantial completion of construction of the Sabine Pass LNG terminal in September 2009.
Purchase of Treasury Shares
During 2011, 2010 and 2009, we used $14.4 million, $2.8 million and $1.0 million, respectively, of cash and cash equivalents to purchase restricted stock that was returned to us by employees to cover taxes related to their restricted stock that vested during the periods.
Investment in Restricted Cash and Cash Equivalents
In 2011, the $15.9 million investment in restricted cash and cash equivalents primarily resulted from Cheniere Partners' public offering in September 2011 in which Cheniere Partners sold 3.0 million common units in an underwritten public offering and 1.1 million common units to us at a price of $15.25 per common unit. Cheniere Partners is using the net proceeds from the offering for general business purposes, including the development costs of its project to add liquefaction capacity at the Sabine Pass LNG terminal.
Debt Agreements
The following table (in thousands) and the explanatory paragraphs following the table summarize our various debt agreements as of December 31, 2011:
(1)
In January 2012, we repaid the 2007 Term Loan in full.
(2)
Effective as of January 1, 2009, we are required to record a debt discount on our Convertible Senior Unsecured Notes. The unamortized discount will be amortized through the maturity of the Convertible Senior Unsecured Notes.
(3)
In September 2008, Sabine Pass LNG issued an additional $183.5 million, par value, of 2016 Notes described below. The net proceeds from the additional issuance of the 2016 Notes were $145.0 million. The difference between the par value and the net proceeds is the debt discount, which will be amortized through the maturity of the 2016 Notes.
2007 Term Loan
In May 2007, Cheniere Subsidiary Holdings, LLC, a wholly owned subsidiary of Cheniere, entered into a $400.0 million credit agreement ("2007 Term Loan"). Borrowings under the 2007 Term Loan generally bore interest at a fixed rate of 9¾% per annum. Interest was calculated on the unpaid principal amount of the 2007 Term Loan outstanding and was payable quarterly in arrears on March 31, June 30, September 30 and December 31 of each year. The 2007 Term Loan had a maturity date of May 31, 2012. The 2007 Term Loan was secured by a pledge of our 135,383,831 subordinated units in Cheniere Partners.
In May 2010, we sold our 30% limited partner interest in Freeport LNG to institutional investors for net proceeds of $104.3 million. The net proceeds from the sale were used to prepay $102.0 million of the 2007 Term Loan in May 2010. As of December 31, 2010, $298.0 million was outstanding under the 2007 Term Loan and included in long-term debt on our Consolidated Balance Sheets.
During the second quarter of 2011, we reclassified $298.0 million of debt from a long-term liability to a current liability because our 2007 Term Loan was due within 12 months as of May 31, 2011. In January 2012, we repaid the 2007 Term Loan in full.
Convertible Senior Unsecured Notes
In July 2005, we consummated a private offering of $325.0 million aggregate principal amount of convertible senior unsecured notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act (the "Convertible Senior Unsecured Notes"). The notes bear interest at a rate of 2¼% per year. The notes are convertible at any time into our common stock under certain circumstances at an initial conversion rate of 28.2326 shares per $1,000 principal amount of the notes, which is equal to a conversion price of approximately $35.42 per share. As of December 31, 2011, no holders had elected to convert their notes at the conversion rate.
We may redeem some or all of the notes on or before August 1, 2012, for cash equal to 100% of the principal plus any accrued and unpaid interest if in the previous 10 trading days the volume-weighted average price of our common stock exceeds $53.13, subject to adjustment, for at least five consecutive trading days. In the event of such redemption, we will make an additional payment equal to the present value of all remaining scheduled interest payments through August 1, 2012, discounted at the U.S. Treasury securities rate plus 50 basis points. The indenture governing the notes contains customary reporting requirements.
During the second quarter of 2009, we reduced debt by exchanging $120.4 million aggregate principal amount of our Convertible Senior Unsecured Notes for a combination of $30.0 million cash and cash equivalents and 4.0 million shares of Cheniere common stock, reducing our principal amount due in 2012 to $204.6 million. The remaining principal amount of the Convertible Senior Unsecured Notes are convertible into 5.8 million shares of our common stock.
During the third quarter of 2011, we reclassified $190.7 million of debt, net of discount, from a long-term liability to a current liability because our Convertible Senior Unsecured Notes were due within 12 months as of August 1, 2011.
As discussed in Note 15-"Debt and Debt-Related Parties" of our Notes to Consolidated Financial Statements, we adopted on January 1, 2009 an accounting standard that requires issuers of certain convertible debt instruments to separately account for the liability component and the equity component represented by the embedded conversion option in a manner that will reflect that entity's nonconvertible debt borrowing rate when interest costs are recognized in subsequent periods. The fair value of the embedded conversion option at the date of issuance of the Convertible Senior Unsecured Notes was determined to be $134.0 million and has been recorded as a debt discount to the Convertible Senior Unsecured Notes, with a corresponding adjustment to additional paid-in capital. At December 31, 2011, the unamortized debt discount to the Convertible Senior Unsecured Notes was $9.9 million.
Senior Notes
In November 2006, Sabine Pass LNG issued an aggregate principal amount of $2,032.0 million of Senior Notes (the "Senior Notes"), consisting of $550.0 million of 7¼% Senior Secured Notes due 2013 (the "2013 Notes") and $1,482.0 million of 7½% Senior Secured Notes due 2016 (the "2016 Notes"). In September 2008, Sabine Pass LNG issued an additional $183.5 million, before discount, of 2016 Notes whose terms were identical to the previously outstanding 2016 Notes. Interest on the Senior Notes
is payable semi-annually in arrears on May 30 and November 30 of each year. The Senior Notes are secured on a first-priority basis by a security interest in all of Sabine Pass LNG’s equity interests and substantially all of its operating assets.
Sabine Pass LNG may redeem some or all of the Senior Notes at any time, and from time to time, at a redemption price equal to 100% of the principal plus any accrued and unpaid interest plus the greater of:
•1.0% of the principal amount of the Senior Notes; or
•
the excess of: a) the present value at such redemption date of (i) the redemption price of the Senior Notes plus (ii) all required interest payments due on the Senior Notes (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50 basis points; over b) the principal amount of the Senior Notes, if greater.
Under the Sabine Pass Indenture, except for permitted tax distributions, Sabine Pass LNG may not make distributions until certain conditions are satisfied: there must be on deposit in an interest payment account an amount equal to one-sixth of the semi-annual interest payment multiplied by the number of elapsed months since the last semi-annual interest payment, and there must be on deposit in a permanent debt service reserve fund an amount equal to one semi-annual interest payment of approximately $82.4 million. Distributions are permitted only after satisfying the foregoing funding requirements, a fixed charge coverage ratio test of 2:1 and other conditions specified in the Sabine Pass Indenture. During the years ended December 31, 2011, 2010 and 2009, Sabine Pass LNG made distributions to Cheniere Partners of $313.6 million, $374.8 million and $295.7 million, respectively, after satisfying all of the applicable conditions in the Sabine Pass Indenture.
2008 Loans
In August 2008, we entered into a credit agreement pursuant to which we obtained $250.0 million in convertible term loans ("2008 Loans"). The 2008 Loans have a maturity date in 2018. The 2008 Loans bear interest at a fixed rate of 12% per annum, except during the occurrence of an event of default during which time the rate of interest will be 14% per annum. Interest is due semi-annually on the last business day of January and July. The 2008 Loans are secured by Cheniere's rights and fees payable under management services agreements with Sabine Pass LNG and Cheniere Partners, by Cheniere's 12.0 million common units in Cheniere Partners, by the equity and assets of Cheniere's pipeline entities, by the equity of various other subsidiaries and certain other assets and subsidiary guarantees.
In June 2010, the 2008 Loans were amended to permit all funds on deposit in a TUA reserve payment account to be applied to the prepayment of the accrued interest on the loans outstanding under the 2008 Loans, with any remainder to be applied to the prepayment of the principal balance of such 2008 Loans. As a result, $63.6 million from the TUA reserve account was used to prepay $60.9 million of accrued interest and $2.7 million of principal of the 2008 Loans.
In December 2010, the 2008 Loans were amended to, among other things: eliminate the "put rights" which had allowed the lenders to demand repayment of the 2008 Loans on the third, fifth, and seventh anniversaries thereof; allow for the early prepayment of the 2008 Loans; allow Cheniere for a limited period to sell Cheniere Partners common units held as collateral and prepay the 2008 Loans with the proceeds; and release restrictions on prepayments of other indebtedness at Cheniere as certain conditions are met. In addition, 96.6% of the lenders agreed to terminate their rights to exchange the 2008 Loans for Series B Preferred Stock of Cheniere.
The outstanding principal amount of the 2008 Loans held by Scorpion Capital Partners, LP ("Scorpion"), the holder of 3.4% of the 2008 Loans as of December 31, 2011, is exchangeable for shares of Cheniere common stock at a price of $5.00 per share pursuant to an amendment to the 2008 Loans adopted in September 2011. No portion of any accrued interest is eligible for exchange into Cheniere common stock. On June 16, 2011, our stockholders approved a proposal to permit Scorpion to exchange its 2008 Loans for common stock, to hold such shares of common stock, and to allow Scorpion to vote the common stock as any other stockholder. The portion of outstanding principal amount of the 2008 Loans for Scorpion is classified as related party long-term debt on our consolidated financial statements because Scorpion is an affiliate of one of Cheniere's directors.
As of December 31, 2011 and December 31, 2010, we classified $9.6 million and $8.9 million, respectively, as part of Long-Term Debt-Related Parties on our Consolidated Balance Sheets because a related party then held these portions of this debt.
Issuances of Common Stock
During 2011, no shares of our common stock were issued pursuant to the exercise of stock options. During 2011, we issued 7.8 million shares of restricted stock to new and existing employees.
During 2010, no shares of our common stock were issued pursuant to the exercise of stock options. During 2010, we issued 1.2 million shares of restricted stock to new and existing employees. We also issued 10.1 million shares of our common stock to the lenders of our 2008 Loans in connection with the December 2010 amendment to the 2008 Loans.
During 2011 and 2010, we raised no proceeds from the exercise of stock options or the exchange or exercise of warrants.
Contractual Obligations
We are committed to make cash payments in the future pursuant to certain of our contracts. The following table summarizes certain contractual obligations in place as of December 31, 2011 (in thousands).
(1)
Based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2011, our cash payments for interest would be $212.2 million in 2012, $195.3 million in 2013, $158.8 million in 2014, $158.8 million in 2015 and $195.0 million for the remaining years for a total of $920.1 million. See Note 15-"Debt and Debt-Related Parties" of our Notes to Consolidated Financial Statements.
(2)
A discussion of these obligations can be found at Note 7-"Leases" of our Notes to Consolidated Financial Statements.
(3)
Minimum lease payments have not been reduced by a minimum sublease rental of $3.4 million due in the future under non-cancelable subleases. A discussion of these sublease rental payments can be found at Note 7-"Leases" of our Notes to Consolidated Financial Statements.
(4)
A discussion of these obligations can be found at Note 20-"Commitments and Contingencies" of our Notes to Consolidated Financial Statements.
(5)
Includes obligations for cooperative endeavor agreements, LNG terminal security services, telecommunication services and software licensing.
In addition, in the ordinary course of business, we maintain letters of credit and have certain cash and cash equivalents restricted in support of certain performance obligations of our subsidiaries. Restricted cash and cash equivalents totaled approximately $185.1 million at December 31, 2011. For more information, see Note 6-"Restricted Cash and Cash Equivalents" of our Notes to Consolidated Financial Statements.
Results of Operations
Overall Operations
2011 vs. 2010
Our consolidated net loss was $198.8 million, or $2.60 per share (basic and diluted), in 2011 compared to a net loss of $76.2 million, or $1.37 per share (basic and diluted), in 2010. This increase in net loss was primarily due to the $128.3 million gain in May 2010 from the sale of our 30% interest in Freeport LNG. In addition, the increase in net loss is a result of increased development expense, increased general and administrative expense ("G&A Expense"), and decreased marketing and trading revenues, which was partially offset by decreased LNG terminal and pipeline operating expenses and decreased interest expense, net.
We recognized one-time charges in 2010 of $128.3 million for a gain on sale of equity method investment and $50.3 million for a loss on early extinguishment of debt. In addition, a portion of our loss was attributable to the recognition of non-cash, share-based payments recognized in the consolidated financial statements based on fair value at the date of grant. As a result of our issuance of non-cash, share-based payments to employees, we recorded $26.4 million and $17.9 million of non-cash compensation expense in 2011 and 2010, respectively. Not including the impact of these one-time charges in 2011 and 2010 and the impact of non-cash expense in 2011 and 2010, our net loss would have been $172.4 million, or $2.25 net loss per common share (basic and diluted), and $136.3 million, or $2.44 net loss per common share (basic and diluted), in 2011 and 2010, respectively.
2010 vs. 2009
Our consolidated net loss was $76.2 million, or $1.37 per share (basic and diluted), in 2010 compared to a net loss of $161.5 million, or $3.13 per share (basic and diluted), in 2009. The decrease in the 2010 net loss was primarily due to a gain in 2010 on the sale of our 30% interest in Freeport LNG, increased LNG terminal revenues as a result of the Sabine Pass LNG terminal starting commercial operations during 2009 that was partially offset by a loss on the early extinguishment of our 2008 Loans, increased LNG terminal and pipeline development and operations and maintenance expense, and increased depreciation, depletion and amortization expense ("DD&A").
A significant portion of our loss was attributable to the recognition of non-cash, share-based payments recognized in the consolidated financial statements based on fair value at the date of grant. As a result of our issuance of non-cash, share-based payments to employees, we recorded $17.9 million and $19.2 million of non-cash compensation expense in 2010 and 2009, respectively. In addition, we recognized one-time charges in 2010 of $128.3 million for a gain on sale of equity method investment and $50.3 million for a loss on early extinguishment of debt. In 2009, we recognized one-time charges of $45.4 million for a gain on early extinguishment of debt. Not including the impact of these one-time charges in 2010 and 2009 and the impact of non-cash expense in 2010 and 2009, our net loss would have been $136.3 million, or $2.44 net loss per common share (basic and diluted), and $187.7 million, or $3.64 net loss per common share (basic and diluted), in 2010 and 2009, respectively.
LNG Terminal Revenues
2011 vs. 2010
LNG terminal revenues increased $4.8 million, from $269.5 million in 2010 to $274.3 million in 2011. This increase is primarily a result of increased LNG export loading fee revenue.
2010 vs. 2009
LNG terminal revenues increased $99.4 million, from $170.1 million in 2009 to $269.5 million in 2010. Of this total increase, $96.9 million was a result of Total and Chevron capacity reservation fee TUA payments beginning on April 1, 2009 and July 1, 2009, respectively. The remaining increase in LNG terminal revenues is a result of increased revenues earned from our 2% retainage and LNG export cargo loading fees charged to customers in 2010.
LNG and Natural Gas Marketing and Trading Revenues
Operating results from marketing and trading activities are presented on a net basis on our Consolidated Statements of Operations. Marketing and trading revenues represent the margin earned on the purchase and transportation costs of LNG and subsequent sales of natural gas to third parties. Our marketing and trading revenues also include pretax derivative gains/losses and inventory lower-of-cost-or-market adjustments, if any. See the table below (in thousands) for an itemized comparison of each major type of energy trading and risk management activity:
2011 vs. 2010
LNG and natural gas marketing and trading revenues decreased $5.4 million, from $19.0 million in 2010 to $13.6 million in 2011. The $5.4 million decrease in marketing and trading revenues is primarily a result of lower-of-cost-or-market adjustments on our LNG inventory in 2011. Other energy trading activities primarily consist of our agreements with LNGCo that became effective on April 1, 2010. During 2011 and 2010, we recognized $12.0 million and $10.1 million, respectively, of marketing and trading revenues from LNGCo.
2010 vs. 2009
LNG and natural gas marketing and trading revenues increased $10.9 million, from $8.1 million in 2009 to $19.0 million in 2010. The $8.1 million in 2009 primarily resulted from $8.6 million in derivative gains and $2.3 million of net revenue from physical sales of regasified LNG, which was offset by a $3.3 million inventory write-down. The $19.0 million of LNG and natural gas marketing and trading revenues in 2010 primarily resulted from fixed fee and gross margin revenue from LNGCo and physical sales of LNG.
General and Administrative Expense
Our G&A Expense includes costs that are incurred for general corporate purposes, LNG and natural gas marketing activities, the Sabine Pass LNG terminal and Creole Trail Pipeline activities.
2011 vs. 2010
G&A Expense increased $19.8 million, from $68.6 million in 2010 to $88.4 million in 2011. This increase primarily resulted from increased salary and non-cash compensation expense related to an increased number of corporate employees.
Depreciation, Depletion and Amortization
2010 vs. 2009
DD&A increased $9.1 million, from $54.2 million in 2009 to $63.3 million in 2010. This increase primarily resulted from the substantial completion of construction and achievement of full operability of the Sabine Pass LNG terminal, with approximately 4.0 Bcf/d of total sendout capacity and five LNG storage tanks with approximately 16.9 Bcf of aggregate storage capacity, in the third quarter of 2009.
LNG Terminal and Pipeline Operating Expense
Our LNG terminal and pipeline operating expenses include costs incurred to operate the Sabine Pass LNG terminal and the Creole Trail Pipeline.
2011 vs. 2010
LNG terminal and pipeline operating expense decreased $3.3 million, from $42.4 million in 2010 to $39.1 million in 2011. This decrease primarily resulted from decreased fuel costs in 2011 as a result of efficiencies in our LNG inventory management.
2010 vs. 2009
LNG terminal and pipeline operating expense increased $5.5 million, from $36.9 million in 2009 to $42.4 million in 2010. This $5.5 million increase primarily resulted from the achievement of full operability of the Sabine Pass LNG terminal in the third quarter of 2009 (as described above).
LNG Terminal and Pipeline Development Expense
Our LNG terminal and pipeline development expenses include primarily professional costs associated with front-end engineering and design work, obtaining regulatory approvals authorizing construction of our facilities and other required permitting for our planned LNG terminals and natural gas pipelines.
2011 vs. 2010
LNG terminal and pipeline development expenses increased $28.8 million, from $12.0 million in 2010 to $40.8 million in 2011. This increase resulted from costs incurred to develop the proposed liquefaction project at the Sabine Pass LNG terminal.
2010 vs. 2009
LNG terminal and pipeline development expenses increased $11.8 million from $0.2 million in 2009 compared to $12.0 million in 2010. The increase resulted from liquefaction development activities at the Sabine Pass LNG terminal in 2010. The 2009 costs primarily related to continued site maintenance costs incurred with respect to our potential Corpus Christi and Creole Trail LNG terminal projects.
Gain on Sale of Equity Method Investment
In May 2010, we sold our 30% interest in Freeport LNG and recognized a net gain of $128.3 million. The gain was comprised of net proceeds received of $104.3 million and $24.0 million of distributions in excess of income.
Interest Expense, net
2011 vs. 2010
Interest expense, net of amounts capitalized, decreased $2.6 million, from $262.0 million in 2010 to $259.4 million in 2011. This decrease in interest expense resulted from the reduction of our indebtedness during the second quarter of 2010.
2010 vs. 2009
Interest expense, net of amounts capitalized, increased $18.7 million, from $243.3 million in 2009 to $262.0 million in 2009. The increase in interest expense resulted from the achievement of full operability of the Sabine Pass LNG terminal in the third quarter of 2009, which reduced the amount of interest expense that was capitalized.
Gain/(Loss) on Early Extinguishment of Debt
2011 vs. 2010
Gain/(Loss) on early extinguishment of debt decreased $50.3 million, from a $50.3 million loss in 2010 to zero in 2011. During the fourth quarter of 2010, the 2008 Loans were amended to, among other things: eliminate the "put right," which had allowed the lenders to demand repayment of the 2008 Loans on the third, fifth and seventh anniversaries thereof; allow for the early prepayment of the 2008 Loans; allow us to sell Cheniere Partners common units held as collateral and prepay the 2008 Loans with the proceeds; and release restrictions on prepayments of other indebtedness of Cheniere as certain conditions are met. In addition, 96.6% of the lenders agreed to terminate their rights to exchange the 2008 Loans for Series B Preferred Stock. As part of the amendments to the 2008 Loans, we issued 10.1 million shares of Cheniere common stock to such lenders. The value of the 10.1 million Cheniere common shares were expensed as a loss on early extinguishment of debt in the fourth quarter of 2010.
2010 vs. 2009
Gain/(Loss) on early extinguishment of debt decreased $95.7 million, from a $45.4 million gain in 2009 to a $50.3 million loss in 2010. The $50.3 million loss in 2010 is discussed above. During the second quarter of 2009, we reduced debt by exchanging $120.4 million aggregate principal amount of our Convertible Senior Unsecured Notes for a combination of $30.0 million cash and cash equivalents and 4.0 million common shares, reducing our principal amount due in 2012 to $204.6 million. As a result of the exchange, we recognized a gain of $45.4 million that was reported as a gain on early extinguishment of debt in 2009.
Off-Balance Sheet Arrangements
As of December 31, 2011, we had no "off-balance sheet arrangements" that may have a current or future material affect on our consolidated financial position or results of operations.
Inflation and Changing Prices
During the years ended December 31, 2011, 2010 and 2009, inflation and changing commodity prices have had an impact on our oil and gas revenues but have not significantly impacted our results of operations.
Summary of Critical Accounting Policies and Estimates
The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives but involve an implementation and interpretation of existing rules, and the use of judgment, to apply the accounting rules to the specific set of circumstances existing in our business. In preparing our consolidated financial statements in conformity with generally accepted accounting principles in the United States ("GAAP"), we endeavor to comply with all applicable rules on or before their adoption, and we believe that the proper implementation and consistent application of the accounting rules are critical. However, not all situations are specifically addressed in the accounting literature. In these cases, we must use our best judgment to adopt a policy for accounting for these situations. We accomplish this by analogizing to similar situations and the accounting guidance governing them.
Cash and Cash Equivalents
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
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 and lease option costs that are capitalized as property, plant and equipment and certain permits that are capitalized as intangible LNG 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.
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 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 performs the services set forth in each customer’s TUA.
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.
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:
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
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
We use derivative instruments from time to time to hedge cash flows attributable to the future sale of LNG inventory and to hedge the price risk attributable to future purchases of natural gas to be utilized as fuel to operate the Sabine Pass LNG terminal. We have disclosed certain information regarding these derivative positions, including the fair value of our derivative positions, in Note 16-"Financial Instruments" of our Notes to Consolidated Financial Statements
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), net on our Consolidated Statements of Operations. We record changes in the fair value of our derivative positions on our Consolidated Statements of Operations 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 change.
Regulated Natural Gas Pipelines
Our natural gas pipeline business is 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 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.
Goodwill
Goodwill represents the excess of cost over fair value of the assets of businesses acquired. It is evaluated annually for impairment by first comparing 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. We had goodwill of $76.8 million at December 31, 2011 and 2010, attributable to our LNG terminal segment.
We perform an annual goodwill impairment review in the fourth quarter of each year, although we may perform a goodwill impairment review more frequently whenever events or circumstances indicate that the carrying value may not be recoverable. 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.
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 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, 2011 and 2010 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 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 18-"Share-Based Compensation" of our Notes to Consolidated Financial Statements).
Recent Accounting Standards
In June 2011, the Financial Accounting Standards Board ("FASB") amended current comprehensive income guidance. The amended guidance eliminates the option to present the components of other comprehensive income as part of the statement of shareholders’ equity. Instead, we must report comprehensive income in either a single continuous statement of comprehensive income which contains two sections, net income and other comprehensive income, or in two separate but consecutive statements. This guidance will be effective for public companies during the interim and annual periods beginning after December 15, 2011 with early adoption permitted. Also, in December 2011, FASB issued an accounting standard update to abrogate the requirement for presentation in the income statement of the effect on net income of reclassification adjustments out of AOCI as required in FASB's June 2011 amendment. We expect to adopt this guidance in our first fiscal quarter ending March 31, 2012. The adoption of this guidance will not have an impact on our consolidated financial position, results of operations or cash flows as it only requires a change in the format of the current presentation.
In September 2011, the FASB amended the guidance on the annual testing of goodwill for impairment. The amended guidance will allow companies to assess qualitative factors to determine if it is more-likely-than-not that goodwill might be impaired and whether it is necessary to perform the two-step goodwill impairment test required under current accounting standards. This guidance will be effective for our fiscal year ending December 31, 2012, with early adoption permitted. We adopted this guidance in our fourth fiscal quarter ended December 31, 2011. The adoption of this guidance did not have a material impact on our consolidated financial position, results of operations or cash flows.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Cash Investments
We have cash investments that we manage based on internal investment guidelines that emphasize liquidity and preservation of capital. Such cash investments are stated at historical cost, which approximates fair market value on our Consolidated Balance Sheets.
Marketing and Trading Commodity Price Risk
We have entered into certain derivative instruments to economically hedge the price risk attributable to future purchases of natural gas to be utilized as fuel to operate the Sabine Pass LNG terminal ("Fuel Derivatives") and to hedge the exposure to variability in expected future cash flows attributable to the future sale of our LNG inventory ("LNG Inventory Derivatives"). We use one-day value at risk ("VaR") with a 95% confidence interval and other methodologies for market risk measurement and control purposes. The VaR is calculated using the Monte Carlo simulation method. The table below provides information about our derivative financial instruments that are sensitive to changes in natural gas prices as of December 31, 2011 (in thousands, except for volume and price range data).
We had not entered into any natural gas or foreign currency derivative positions as of December 31, 2010.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
CHENIERE ENERGY, INC. AND SUBSIDIARIES
Management’s Reports to the Stockholders of Cheniere Energy, Inc.
Reports of Independent Registered Public Accounting Firm-Ernst & Young LLP
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Stockholders’ (Deficit) Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Supplemental Information to Consolidated Financial Statements-Summarized Quarterly Financial Data
MANAGEMENT’S REPORTS TO THE STOCKHOLDERS OF CHENIERE ENERGY, INC.
Management’s Report on Internal Control Over Financial Reporting
As management, we are responsible for establishing and maintaining adequate internal control over financial reporting for Cheniere Energy, Inc. and its subsidiaries ("Cheniere"). In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, we have conducted an assessment, including testing using the criteria in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). Cheniere’s system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and, even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation.
Based on our assessment, we have concluded that Cheniere maintained effective internal control over financial reporting as of December 31, 2011, based on criteria in Internal Control-Integrated Framework issued by the COSO.
Cheniere’s independent auditors, Ernst & Young LLP, have issued an audit report on Cheniere’s internal control over financial reporting as of December 31, 2011, which is contained in this Form 10-K.
Management’s Certifications
The certifications of Cheniere’s Chief Executive Officer and Chief Financial Officer required by the Sarbanes-Oxley Act of 2002 have been included as Exhibits 31 and 32 in Cheniere’s Form 10-K.
CHENIERE ENERGY, INC.
By:
/s/ CHARIF SOUKI
By:
/s/ MEG A. GENTLE
Charif Souki
Chief Executive Officer and President
(Principal Executive Officer)
Meg A. Gentle
Senior Vice President
and Chief Financial Officer
(Principal Financial Officer)
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of
Cheniere Energy, Inc.
We have audited the accompanying consolidated balance sheets of Cheniere Energy, Inc. and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of operations, stockholders' (deficit) equity, and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Cheniere Energy, Inc. and subsidiaries at December 31, 2011 and 2010, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Cheniere Energy, Inc.'s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2012 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Ernst & Young LLP
Houston, Texas
February 24, 2012
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of
Cheniere Energy, Inc.
We have audited Cheniere Energy, Inc. and subsidiaries' internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Cheniere Energy, Inc. and subsidiaries' management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Cheniere Energy, Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Cheniere Energy, Inc. and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of operations, stockholders' (deficit) equity, and cash flows for each of the three years in the period ended December 31, 2011 and our report dated February 24, 2012 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Ernst & Young LLP
Houston, Texas
February 24, 2012
CHENIERE ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
The accompanying notes are an integral part of these consolidated financial statements.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
The accompanying notes are an integral part of these consolidated financial statements.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ (DEFICIT) EQUITY
(in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
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 Energy, Inc., a Delaware corporation, is a Houston-based energy company primarily engaged in liquefied natural gas ("LNG") related businesses. We own and operate the Sabine Pass LNG terminal in Louisiana through our 88.8% ownership interest in and management agreements with Cheniere Energy Partners, L.P. ("Cheniere Partners"), which is a publicly traded partnership that we created in 2007. We also own and operate the Creole Trail Pipeline, which interconnects the Sabine Pass LNG terminal with natural gas markets in North America. One of our subsidiaries, Cheniere Marketing, LLC ("Cheniere Marketing"), is marketing LNG and natural gas on its own behalf and on behalf of Cheniere Partners, is working to monetize LNG storage and regasification capacity reserved by Cheniere Partners at the Sabine Pass LNG terminal. Cheniere Partners is developing a project to add liquefaction capabilities at the Sabine Pass LNG terminal. We are in various stages of developing projects, including LNG terminal and pipeline related projects, each of which, among other things, will require acceptable commercial and financing arrangements before we make a final investment decision. Unless the context requires otherwise, references to the "Company", "Cheniere", "we", "us" and "our" refer to Cheniere Energy, Inc. and its subsidiaries, including our publicly traded subsidiary partnership, Cheniere Partners.
NOTE 2-SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
Our Consolidated Financial Statements were prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). The consolidated financial statements include the accounts of Cheniere Energy, Inc. and its majority-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.
Certain reclassifications have been made to conform prior period information to the current presentation. The reclassifications had no effect on our overall consolidated financial position, results of operations or cash flows.
Cash and Cash Equivalents
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
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 and lease option costs that are capitalized as property, plant and equipment and certain permits that are capitalized as intangible LNG 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.
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 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.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
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:
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
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
We use derivative instruments from time to time to hedge cash flows attributable to the future sale of LNG inventory and to hedge the price risk attributable to future purchases of natural gas to be utilized as fuel to operate the Sabine Pass LNG terminal. We have disclosed certain information regarding these derivative positions, including the fair value of our derivative positions, in Note 16-"Financial Instruments" of our Notes to Consolidated Financial Statements
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 record changes in the fair value of our derivative positions on our Consolidated Statements of Operations 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 change.
Regulated Natural Gas Pipelines
Our natural gas pipeline business is subject to the jurisdiction of the Federal Energy Regulatory Commission ("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 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
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
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 fixed assets for 2011, 2010 or 2009.
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 realizable.
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.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
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.
Cash Equivalents
We classify all investments with original maturities of three months or less as 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.
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.
Goodwill
Goodwill represents the excess of cost over fair value of the assets of businesses acquired. It is evaluated annually for impairment by first comparing 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. We had goodwill of $76.8 million at December 31, 2011 and 2010, attributable to our LNG terminal segment.
We perform an annual goodwill impairment review in the fourth quarter of each year, although we may perform a goodwill impairment review more frequently whenever events or circumstances indicate that the carrying value may not be recoverable. 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.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
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
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 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, 2011 and 2010 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 18-"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, warrants 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 2011, 2010 and 2009, were 2.4 million shares, 5.8 million shares and 9.0 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 15-"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. In addition, common shares of 59.2 million on a weighted average basis, issuable upon conversion of the 2008 Loans and the Convertible Senior Unsecured Notes, were not included in the computation of diluted net loss per share for 2009 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:
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
Natural Gas Pipeline
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.
LNG Terminal
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. Due to the language in the real property lease agreements, we have determined that the cost to surrender the LNG terminal in the required condition will be minimal, and therefore have not recorded an ARO associated with the Sabine Pass LNG terminal.
Recent Accounting Standards Not Yet Adopted
In June 2011, the Financial Accounting Standards Board ("FASB") amended current comprehensive income guidance. The amended guidance eliminates the option to present the components of other comprehensive income as part of the statement of shareholders’ equity. Instead, we must report comprehensive income in either a single continuous statement of comprehensive income which contains two sections, net income and other comprehensive income, or in two separate but consecutive statements. This guidance will be effective for public companies during the interim and annual periods beginning after December 15, 2011 with early adoption permitted. Also, in December 2011, FASB issued an accounting standard update to abrogate the requirement for presentation in the income statement of the effect on net income of reclassification adjustments out of AOCI as required in FASB's June 2011 amendment. We expect to adopt this guidance in our first fiscal quarter ending March 31, 2012. The adoption of this guidance will not have an impact on our consolidated financial position, results of operations or cash flows as it only requires a change in the format of the current presentation.
NOTE 3-Liquidity
As of December 31, 2011, we had unrestricted cash and cash equivalents of $459.2 million available to Cheniere. In addition, we had consolidated restricted cash and cash equivalents of $185.1 million (which included cash and cash equivalents and other working capital available to Cheniere Partners, in which we own an 88.8% interest, and Sabine Pass LNG) designated for the following purposes: $96.1 million for interest payments related to the Senior Notes described below; $4.3 million for Sabine Pass LNG's working capital; $77.1 million for Cheniere Partners' working capital; and $7.5 million for other restricted purposes.
During the second quarter of 2011, we reclassified $298.0 million of debt from a long-term liability to a current liability because our 2007 Term Loan described below was due within 12 months as of May 31, 2011. During the third quarter of 2011, we reclassified $190.7 million, net of discount, of debt from a long-term liability to a current liability because our Convertible Senior Unsecured Notes were due within 12 months as of August 15, 2011. In December 2011, we closed an underwritten public offering of 41,745,000 shares of our common stock, which were sold to the public at a price per share of $8.35, resulting in net proceeds of approximately $330.9 million. In January 2012, we used a portion of the net proceeds to repay in full the outstanding principal balance of the $298.0 million 2007 Term Loan due May 31, 2012. The aggregate repayment amount was $298.2 million, including the outstanding principal amount and accrued interest through January 5, 2012.
In September 2011, we initiated an at-the-market program to sell up to 10 million shares of our common stock. As of December 31, 2011, we had sold 1.5 million shares with net proceeds of $14.4 million. During the year ended December 31, 2011, we paid $0.4 million in commissions to Miller Tabak + Co., Inc., as sales agent, in connection with the at-the-market program.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
We believe that we will have sufficient unrestricted cash, liquid assets, cash generated from our operations and proceeds from capital market transactions to satisfy our debt obligations and fund our operations for at least the next 12 months. In order to satisfy our principal payment due on our Convertible Senior Unsecured Notes in August 2012, we will need to extend, refinance or repay such indebtedness, which may be accomplished by refinancing our existing indebtedness, raising capital by issuing equity, debt or other securities or using cash generated from selling assets or through a combination of the foregoing and will be dependent on factors such as worldwide natural gas and capital market conditions.
NOTE 4-CHENIERE ENERGY PARTNERS, L.P.
As of December 31, 2011, our combined general partner and limited partner ownership interest in Cheniere Partners was approximately 88.8%. As of such date, we held 135,383,831 subordinated units, 11,963,488 common units and a 2% general partner interest in Cheniere Partners.
The portion of the common units held by the public is presented as a non-controlling interest on our Consolidated Balance Sheets. Losses attributable to the non-controlling interest are presented separately on our Consolidated Statements of Operations based upon the non-controlling interest’s share of Cheniere Partners’ losses calculated in accordance with Cheniere Partners’ partnership agreement.
Cheniere Partners' cash distribution policy is consistent with the terms of its partnership agreement, which requires that it distribute all of its available cash quarterly. During the subordination period, the common units have the right to receive distributions of available cash from operating surplus in an amount equal to the initial quarterly distribution of $0.425 per quarter, plus any arrearages in the payment of the initial quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. At December 31, 2011, we owned all of the outstanding subordinated units, representing 81% of the limited partner interest in Cheniere Partners. These units are deemed "subordinated" because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until after the common units have received the initial quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordination period is to increase the likelihood that during this period there will be sufficient available cash to pay the initial quarterly distributions on the common units.
NOTE 5-NON-CONTROLLING INTEREST
We have consolidated certain partnerships because we have a controlling interest in these ventures. Therefore, the entities’ financial statements are consolidated in our Consolidated Financial Statements and the entities’ other equity is recorded as a non-controlling interest. The following table sets forth the components of our non-controlling interest balance since inception attributable to third-party investors’ interests at December 31, 2011 (in thousands):
(1)
In March and April 2007, we and Cheniere Partners completed a public offering of 15,525,000 Cheniere Partners common units (the "Cheniere Partners Offering"). Cheniere Partners received $98.4 million in net proceeds from the issuance of its common units to the public. Prior to January 1, 2009, a company was able to elect an accounting policy of recording a gain or loss on the sale of common equity of a subsidiary equal to the amount of proceeds received in excess of the carrying value of the parent’s investment. Effective January 1, 2009, the sale of common equity of a subsidiary is accounted for as an equity transaction.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
In January 2011, Cheniere Partners initiated an at-the-market program to sell up to 1.0 million common units, the proceeds from which would be used primarily to fund development costs associated with its proposed liquefaction project. As of December 31, 2011, Cheniere Partners had sold 0.5 million common units with net proceeds of $9.0 million.
In September 2011, Cheniere Partners sold 3.0 million common units in an underwritten public offering and 1.1 million common units to Cheniere Common Units Holding, LLC at a price of $15.25 per common unit. Cheniere Partners received net proceeds of $43.3 million and $16.4 million from the public offering and Cheniere Common Units Holding, LLC sale, respectively.
(2)
In conjunction with the Cheniere Partners Offering, Cheniere LNG Holdings, LLC ("Holdings") sold a portion of the Cheniere Partners common units held by it to the public, realizing net proceeds of $203.9 million, which included $39.4 million of net proceeds realized once the underwriters exercised their option to purchase an additional 2,025,000 common units from Holdings. Due to the subordinated distribution rights on our subordinated units, we have recorded those proceeds as a non-controlling interest.
(3)
Cash distributions to the non-controlling interest are recorded directly against the non-controlling interest on our Consolidated Balance Sheet. There is no obligation beyond what is reflected in our financial statements to fund or absorb such distributions to the non-controlling interest. If in the future the non-controlling interest on our Consolidated Balance Sheet is reduced to zero, these distributions may increase the loss allocated to us.
NOTE 6-RESTRICTED CASH AND CASH EQUIVALENTS
Restricted cash and cash equivalents consist of cash and cash equivalents that are contractually restricted as to usage or withdrawal, as follows:
Senior Notes Debt Service Reserve
Sabine Pass LNG has consummated private offerings of an aggregate principal amount of $2,215.5 million of Senior Notes (See Note 15-"Debt and Debt-Related Parties" ). Under the indenture governing the Senior Notes (the "Sabine Pass Indenture"), except for permitted tax distributions, Sabine Pass LNG may not make distributions until certain conditions are satisfied, including that there must be on deposit in an interest payment account an amount equal to one-sixth of the semi-annual interest payment multiplied by the number of elapsed months since the last semi-annual interest payment and there must be on deposit in a permanent debt service reserve fund an amount equal to one semi-annual interest payment of $82.4 million. Distributions are permitted only after satisfying the foregoing funding requirements, a fixed charge coverage ratio test of 2:1 and other conditions specified in the Sabine Pass Indenture.
As of December 31, 2011 and 2010, we classified $13.7 million as current restricted cash and cash equivalents for the payment of interest due within twelve months. As of December 31, 2011 and 2010, we classified the permanent debt service reserve fund of $82.4 million as non-current restricted cash and cash equivalents. These cash accounts are controlled by a collateral trustee, and, therefore, are shown as restricted cash and cash equivalents on our Consolidated Balance Sheets.
Other Restricted Cash and Cash Equivalents
As of December 31, 2011 and 2010, $81.4 million and $53.3 million, respectively, of current restricted cash and cash equivalents was primarily related to cash and cash equivalents held by Sabine Pass LNG and Cheniere Partners that were considered restricted to Cheniere. As of December 31, 2011 and 2010, due to various other contractual restrictions, $6.4 million and $6.1 million had been classified as current restricted cash and cash equivalents, respectively, and $0.5 million had been classified as non-current restricted cash and cash equivalents on our Consolidated Balance Sheets.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
NOTE 7-LEASES
During the years ended December 31, 2011, 2010 and 2009, we recognized rental expense for all operating leases of $11.5 million, $10.2 million and $11.3 million, respectively.
Future Annual Minimum Lease Payments
Future annual minimum lease payments, excluding inflationary adjustments, are as follows (in thousands):
(1)
Includes certain lease option renewals as they were reasonably assured.
(2)
Future annual minimum lease payments do not include $3.4 million expected to be recovered through sublease agreements for our office leases in Houston, Texas.
(3)
Lease payments for our tug boat lease represent third-party tug boat lease payment obligations and do not take into account the payments we receive from our third-party TUA customers that effectively offset $80.2 million, or two-thirds of our lease payment obligations, as discussed below.
Tug Boat Agreements
Sabine Pass Tug Services, LLC ("Tug Services"), Cheniere Partners' wholly owned subsidiary, entered into a Marine Services Agreement (the "Tug Agreement") for the use of tug boats and marine services for the Sabine Pass LNG terminal. The term of the Tug Agreement commenced in January 2008 for a period of 10 years, with an option to renew two additional, consecutive terms of five years each. In accordance with accounting literature on how to determine whether an arrangement contains a lease, we determined that the Tug Agreement contains a lease for the tugs specified in the Tug Agreement. In addition, we concluded that the tug boat lease contained in the Tug Agreement is an operating lease, and as such, the equipment component of the Tug Agreement is charged to expense over the term of the Tug Agreement as it becomes payable.
In the second quarter of 2009, Tug Services entered into a Tug Sharing Agreement with Sabine Pass LNG's three TUA customers to provide their LNG cargo vessels with tug boat and marine services at the Sabine Pass LNG terminal and effectively offset the cost of the tug boat lease. The Tug Sharing Agreement provides for each of our customers to pay Tug Services an annual service fee.
LNG Site Leases
Our obligations under LNG site options are renewable on an annual or semiannual basis. We may terminate our obligations at any time by electing not to renew or by exercising the options.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
In January 2005, we exercised our options and entered into three land leases for the site of the Sabine Pass LNG terminal. The leases have an initial term of 30 years, with options to renew for six 10-year extensions with similar terms as the initial term. In February 2005, two of the three leases were amended, thereby increasing the total acreage under lease to 853 acres and increasing the annual lease payments to $1.5 million. In November and December 2011, we entered into two additional land leases, thereby increasing the total acreage under lease to 1,015 acres and increasing the annual lease payments by $0.4 million. The annual lease payments will be adjusted for inflation based on a consumer price index, as defined in the lease agreements, every five years. We recognized $1.8 million, $1.7 million and $1.5 million of site lease expense on our Consolidated Statements of Operations in 2011, 2010 and 2009, respectively.
NOTE 8-VARIABLE INTEREST ENTITY
In 2010, Cheniere Marketing entered into various agreements ("LNGCo Agreements") with JPMorgan LNG Co. ("LNGCo") under which Cheniere Marketing has agreed to develop and maintain commercial and trading opportunities in the LNG industry and present any such opportunities exclusively to LNGCo. Cheniere Marketing also agreed to provide, or arrange for the provision of, all of the operations and administrative services required by LNGCo in connection with any LNG cargoes purchased by LNGCo, including negotiating agreements and arranging for transporting, receiving, storing, hedging and regasifying LNG cargoes. Cheniere Marketing does not have the authority to contractually bind LNGCo under the LNGCo Agreements. In the event LNGCo declines to purchase an LNG cargo presented to it by Cheniere Marketing under the LNGCo Agreements, Cheniere Marketing may pursue the opportunity on its own behalf or present it to third parties. The term of the LNGCo Agreements expires in April 2012; however, either party may terminate the agreements without penalty prior to such date. In return for the services to be provided by Cheniere Marketing, LNGCo will pay a fixed fee to Cheniere Marketing and may pay additional fees depending upon the gross margins of each transaction and the aggregate gross margin earned during the term of the LNGCo Agreements.
During the years ended December 31, 2011 and 2010, we recognized $12.0 million and $10.1 million, respectively, of marketing and trading revenues from LNGCo. As of December 31, 2011, the carrying amount of Cheniere Marketing’s assets relating to LNGCo, which is equivalent to Cheniere Marketing's maximum exposure to loss, was $3.0 million. A portion of this $3.0 million represents our fixed fee receivable and is reported as accounts and interest receivable on our consolidated financial statements, and the remaining portion represents our margin deposit receivable and is reported as prepaid expense and other current assets on our consolidated financial statements and is to be paid to Cheniere Marketing upon the completion or termination of the LNGCo Agreements.
NOTE 9-LNG INVENTORY
LNG inventory is recorded at cost and is subject to lower of cost or market ("LCM") adjustments at the end of each period. LNG inventory cost is determined using the average cost method. Recoveries of losses resulting from interim period LCM adjustments are recorded when market price recoveries occur on the same inventory in the same fiscal year. These recoveries are recognized as gains in later interim periods with such gains not exceeding previously recognized losses. As of December 31, 2011, we had 1,995,000 MMBtu of LNG inventory recorded at $6.6 million, and as of December 31, 2010, we had 326,000 MMBtu of LNG inventory recorded at $1.2 million on our Consolidated Balance Sheets. During the years ended December 31, 2011, 2010 and 2009, we recognized $11.0 million, $0.3 million and $3.5 million, respectively, as a result of LCM adjustments to our LNG inventory.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
NOTE 10-PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consists of LNG terminal and natural gas pipeline costs, LNG site and related costs, investments in oil and gas properties, and fixed assets, as follows (in thousands):
LNG Terminal Costs
We began depreciating equipment and facilities associated with the initial 2.6 Bcf/d of sendout capacity and 10.1 Bcf of storage capacity of the Sabine Pass LNG terminal when they were ready for use in the third quarter of 2008. We began depreciating equipment and facilities associated with the remaining 1.4 Bcf/d of sendout capacity and 6.8 Bcf of storage capacity of the Sabine Pass LNG terminal when they were ready for use in the third quarter of 2009. Depreciation expense related to the Sabine Pass LNG terminal totaled $42.6 million, $41.8 million and $32.2 million for the years ended December 31, 2011, 2010 and 2009, respectively.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
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 15 and 50 years, as follows:
In March 2006, our Corpus Christi LNG terminal project satisfied the criteria for capitalization. Accordingly, costs associated with the initial site work for the Corpus Christi LNG terminal have been capitalized. As of December 31, 2011, $35.5 million of costs associated with the initial site work for the Corpus Christi LNG terminal were capitalized as LNG terminal construction-in-process. As noted in Note 2-"Summary of Significant Accounting Policies," 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. Management’s assessment is based on certain estimates and assumptions used to determine if impairment is warranted. If the estimates and assumptions used are determined to be different in the future, the amount capitalized may be subject to impairment.
Natural Gas Pipeline Costs
Our natural gas pipeline business is 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.
Fixed Assets
Our fixed assets are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets.
NOTE 11-DEBT ISSUANCE COSTS
We have incurred debt issuance costs in connection with our debt. These costs are capitalized and are being amortized over the term of the related debt. The amortization of the debt issuance cost was recorded as interest expense. As of December 31, 2011, we had capitalized $33.4 million of costs directly associated with the arrangement of debt financing, net of accumulated amortization, as follows (in thousands):
Scheduled amortization of these debt issuance costs for the next five years is estimated to be $29.6 million.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
NOTE 12-GOODWILL
Our goodwill on our Consolidated Balance Sheets as of December 31, 2011 and 2010 is associated with our LNG terminal reporting unit. We performed our annual goodwill impairment review in the fourth quarters of 2011, 2010 and 2009. In 2011, this impairment review consisted of assessing qualitative factors to determine if it is more-likely-than-not that goodwill might be impaired. In 2010 and 2009, this impairment review consisted of comparing the carrying value, including goodwill, of the reporting unit under review to the estimated fair value of the reporting unit. Had the carrying value exceeded the estimated fair value of the reporting unit, an impairment of the reporting unit would have been recognized, resulting in an impairment charge to earnings. A reporting unit is defined as a business segment or component of a business segment that has similar economic characteristics. For our impairment reviews, we have designated our LNG terminal business as the reporting unit under review due to similar economic characteristics. Our reviews indicated that no impairment of goodwill was necessary.
NOTE 13-ACCRUED LIABILITIES
As of December 31, 2011 and 2010, accrued liabilities consisted of the following (in thousands):
NOTE 14-DEFERRED REVENUE
As of December 31, 2011 and 2010, we had recorded $26.6 million and $26.6 million, respectively, as current deferred revenue and $25.5 million and $30.0 million, respectively, as non-current deferred revenue related to advance capacity reservation fee payments on our Consolidated Balance Sheets.
Advance Capacity Reservation Fee
In November 2004, Total Gas and Power North America, Inc. ("Total") paid Sabine Pass LNG a nonrefundable advance capacity reservation fee of $10.0 million in connection with the reservation of approximately 1.0 Bcf/d of LNG regasification capacity at the Sabine Pass LNG terminal. An additional advance capacity reservation fee payment of $10.0 million was paid by Total to Sabine Pass LNG in April 2005. The advance capacity reservation fee payments are being amortized as a reduction of Total’s regasification capacity reservation fee under its TUA over a 10-year period beginning with the commencement of its TUA on April 1, 2009. As a result, we recorded the advance capacity reservation fee payments that Sabine Pass LNG received, although non-refundable, as deferred revenue to be amortized to income over the corresponding 10-year period.
In November 2004, Sabine Pass LNG also entered into a TUA to provide Chevron U.S.A. Inc. ("Chevron") with approximately 0.7 Bcf/d of LNG regasification capacity at the Sabine Pass LNG terminal. In December 2005, Chevron exercised its option to increase its reserved capacity by approximately 0.3 Bcf/d to approximately 1.0 Bcf/d, making advance capacity reservation fee payments to Sabine Pass LNG totaling $20.0 million. The advance capacity reservation fee payments are being amortized as a reduction of Chevron’s regasification capacity reservation fee under its TUA over a 10-year period beginning with the commencement of its TUA on July 1, 2009. As a result, we recorded the advance capacity reservation fee payments that Sabine Pass LNG received, although non-refundable, as deferred revenue to be amortized to income over the corresponding 10-year period.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
As of December 31, 2011, we had recorded $4.0 million and $25.5 million as current and non-current deferred revenue on our Consolidated Balance Sheets, respectively, related to the Total and Chevron advance capacity reservation fees. As of December 31, 2010, we had recorded $4.0 million and $29.5 million as current and non-current deferred revenue on our Consolidated Balance Sheets, respectively, related to the Total and Chevron advance capacity reservation fees.
TUA Payments
Total and Chevron are obligated to make monthly TUA payments to Sabine Pass LNG in advance of the month of service. These monthly payments are recorded to current deferred revenue in the period cash is received and are then recorded as revenue in the next month when the TUA service is performed. As of December 31, 2011 and 2010, we had recorded $21.1 million and $21.0 million, respectively, as current deferred revenue on our Consolidated Balance Sheets related to Total's and Chevron's monthly TUA payments.
NOTE 15-DEBT AND DEBT-RELATED PARTIES
As of December 31, 2011 and 2010, our debt consisted of the following (in thousands):
Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31, 2011 (in thousands):
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
2007 Term Loan
In May 2007, Cheniere Subsidiary Holdings, LLC, a wholly owned subsidiary of Cheniere, entered into a $400.0 million credit agreement ("2007 Term Loan"). Borrowings under the 2007 Term Loan generally bear interest at a fixed rate of 9¾% per annum. Interest is calculated on the unpaid principal amount of the 2007 Term Loan outstanding and is payable quarterly in arrears on March 31, June 30, September 30 and December 31 of each year. The 2007 Term Loan will mature on May 31, 2012. The 2007 Term Loan is secured by a pledge of our 135,383,831 subordinated units in Cheniere Partners.
In May 2010, we sold our 30% interest in Freeport LNG Development, L.P. ("Freeport LNG") to institutional investors for net proceeds of $104.3 million. The net proceeds from the sale were used to prepay $102.0 million of the 2007 Term Loan in May 2010. As of December 31, 2010, $298.0 million was outstanding under the 2007 Term Loan and included in long-term debt on our Consolidated Balance Sheets. During the second quarter of 2011, we reclassified $298.0 million of debt from a long-term liability to a current liability because our 2007 Term Loan was due within 12 months as of May 31, 2011.
Convertible Senior Unsecured Notes
In July 2005, we consummated a private offering of $325.0 million aggregate principal amount of Convertible Senior Unsecured Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act. The notes bear interest at a rate of 2¼% per year. The notes are convertible at any time into our common stock under certain circumstances at an initial conversion rate of 28.2326 shares per $1,000 principal amount of the notes, which is equal to a conversion price of approximately $35.42 per share. As of December 31, 2011, no holders had elected to convert their notes at the conversion rate.
We may redeem some or all of the notes on or before August 1, 2012, for cash equal to 100% of the principal plus any accrued and unpaid interest if in the previous 10 trading days the volume-weighted average price of our common stock exceeds $53.13, subject to adjustment, for at least five consecutive trading days. In the event of such redemption, we will make an additional payment equal to the present value of all remaining scheduled interest payments through August 1, 2012, discounted at the U.S. Treasury securities rate plus 50 basis points. The indenture governing the notes contains customary reporting requirements.
During the second quarter of 2009, we reduced debt by exchanging $120.4 million aggregate principal amount of our Convertible Senior Unsecured Notes for a combination of $30.0 million cash and cash equivalents and 4.0 million shares of common stock, reducing our principal amount due in 2012 to $204.6 million. The remaining principal amount of the Convertible Senior Unsecured Notes are convertible into 5.8 million shares of our common stock.
During the third quarter of 2011, we reclassified $190.7 million of debt, net of discount, from a long-term liability to a current liability because our Convertible Senior Unsecured Notes were due within 12 months as of August 1, 2011.
We adopted on January 1, 2009 an accounting standard that requires issuers of certain convertible debt instruments to separately account for the liability component and the equity component represented by the embedded conversion option in a manner that will reflect that entity's nonconvertible debt borrowing rate when interest costs are recognized in subsequent periods. The fair value of the embedded conversion option at the date of issuance of the Convertible Senior Unsecured Notes was determined to be $134.0 million and has been recorded as a debt discount to the Convertible Senior Unsecured Notes, with a corresponding adjustment to additional paid-in capital. At December 31, 2011, the unamortized debt discount to the Convertible Senior Unsecured Notes was $9.9 million.
Senior Notes
In November 2006, Sabine Pass LNG issued an aggregate principal amount of $2,032.0 million of Senior Notes (the "Senior Notes"), consisting of $550.0 million of 7¼% Senior Secured Notes due 2013 (the "2013 Notes") and $1,482.0 million of 7½% Senior Secured Notes due 2016 (the "2016 Notes"). In September 2008, Sabine Pass LNG issued an additional $183.5 million, before discount, of 2016 Notes whose terms were identical to the previously outstanding 2016 Notes. Interest on the Senior Notes is payable semi-annually in arrears on May 30 and November 30 of each year. The Senior Notes are secured on a first-priority basis by a security interest in all of Sabine Pass LNG’s equity interests and substantially all of its operating assets.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
Sabine Pass LNG may redeem some or all of the Senior Notes at any time, and from time to time, at a redemption price equal to 100% of the principal plus any accrued and unpaid interest plus the greater of:
•1.0% of the principal amount of the Senior Notes; or
•
the excess of: a) the present value at such redemption date of (i) the redemption price of the Senior Notes plus (ii) all required interest payments due on the Senior Notes (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50 basis points; over b) the principal amount of the Senior Notes, if greater.
Under the Sabine Pass Indenture, except for permitted tax distributions, Sabine Pass LNG may not make distributions until certain conditions are satisfied: there must be on deposit in an interest payment account an amount equal to one-sixth of the semi-annual interest payment multiplied by the number of elapsed months since the last semi-annual interest payment, and there must be on deposit in a permanent debt service reserve fund an amount equal to one semi-annual interest payment of approximately $82.4 million. Distributions are permitted only after satisfying the foregoing funding requirements, a fixed charge coverage ratio test of 2:1 and other conditions specified in the Sabine Pass Indenture. During the years ended December 31, 2011 and 2010, Sabine Pass LNG made distributions of $313.6 million and $374.8 million, respectively, after satisfying all the applicable conditions in the Sabine Pass Indenture.
2008 Loans
In August 2008, we entered into a credit agreement pursuant to which we obtained $250.0 million in convertible term loans ("2008 Loans"). The 2008 Loans have a maturity date in 2018. The 2008 Loans bear interest at a fixed rate of 12% per annum, except during the occurrence of an event of default during which time the rate of interest will be 14% per annum. Interest is due semi-annually on the last business day of January and July. The 2008 Loans are secured by Cheniere's rights and fees payable under management services agreements with Sabine Pass LNG and Cheniere Partners, by Cheniere's 12.0 million common units in Cheniere Partners, by the equity and assets of Cheniere's pipeline entities, by the equity of various other subsidiaries and certain other assets and subsidiary guarantees.
In June 2010, the 2008 Loans were amended to permit all funds on deposit in a TUA reserve payment account to be applied to the prepayment of the accrued interest on the loans outstanding under the 2008 Loans, with any remainder to be applied to the prepayment of the principal balance of such 2008 Loans. As a result, $63.6 million from the TUA reserve account was used to prepay $60.9 million of accrued interest and $2.7 million of principal of the 2008 Loans.
In December 2010, the 2008 Loans were amended to, among other things: eliminate the "put rights" which had allowed the lenders to demand repayment of the 2008 Loans on the third, fifth, and seventh anniversaries thereof; allow for the early prepayment of the 2008 Loans; allow Cheniere for a limited period to sell Cheniere Partners common units held as collateral and prepay the 2008 Loans with the proceeds; and release restrictions on prepayments of other indebtedness at Cheniere as certain conditions are met. In addition, 96.6% of the lenders agreed to terminate their rights to exchange the 2008 Loans for Series B Preferred Stock of Cheniere.
The outstanding principal amount of the 2008 Loans held by Scorpion Capital Partners, LP ("Scorpion"), the holder of 3.4% of the 2008 Loans as of December 31, 2011, is exchangeable for shares of Cheniere common stock at a price of $5.00 per share pursuant to an amendment to the 2008 Loans adopted in September 2011. No portion of any accrued interest is eligible for exchange into Cheniere common stock. On June 16, 2011, our stockholders approved a proposal to permit Scorpion to exchange its 2008 Loans for common stock, to hold such shares of common stock, and to allow Scorpion to vote the common stock as any other stockholder. The portion of outstanding principal amount of the 2008 Loans for Scorpion is classified as related party long-term debt on our consolidated financial statements because Scorpion is an affiliate of one of Cheniere's directors.
As of December 31, 2011 and December 31, 2010, we classified $9.6 million and $8.9 million, respectively, as part of Long-Term Debt-Related Parties on our Consolidated Balance Sheets because a related party then held these portions of this debt.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
NOTE 16-FINANCIAL INSTRUMENTS
We have entered into certain derivative instruments to hedge the exposure to variability in expected future cash flows attributable to the future sale of our LNG inventory ("LNG Inventory Derivatives"), and to hedge the price risk attributable to future purchases of natural gas to be utilized as fuel to operate the Sabine Pass LNG terminal ("Fuel Derivatives"). Changes in the fair value of our derivatives instruments are reported in earnings because we have not elected to designate these derivative instruments as a hedging instrument that is required to qualify for cash flow hedge accounting. The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties.
The fair value of our derivative instruments are based on inputs that are quoted prices in active markets for similar assets or liabilities, resulting in Level 2 categorization of such measurements. The following table sets forth, by level within the fair value hierarchy, the fair value of our derivative instruments assets and liabilities at December 31, 2011 (in thousands):
(1)
LNG Inventory Derivatives asset is classified as other current assets on our Consolidated Balance Sheets. Changes in the fair value of LNG Inventory Derivatives are recorded in marketing and trading revenues on our Consolidated Statements of Operations. We recorded marketing and trading revenues of $2.5 million, $2.3 million and $8.6 million related to LNG Inventory Derivatives in the years ended December 31, 2011, 2010 and 2009, respectively.
(2)
Fuel Derivatives liability is classified as other current liabilities on our Consolidated Balance Sheets. Changes in the fair value of Fuel Derivatives are classified as derivative gain (loss) on our Consolidated Statements of Operations. We recorded derivative loss of $2.3 million and derivative gain of $0.5 million and $5.3 million in the years ended December 31, 2011, 2010 and 2009, respectively.
The estimated fair value of financial instruments, including those financial instruments for which the fair value option was not elected are set forth in the table below. The carrying amounts reported on our Consolidated Balance Sheets for cash and cash equivalents, restricted cash and cash equivalents, accounts receivable, interest receivable, and accounts payable approximate fair value due to their short-term nature.
Financial Instruments (in thousands):
(1)
The estimated fair value of the Senior Notes, net of discount, was based on quotations obtained from broker-dealers who make markets in these and similar instruments.
(2)
The estimated fair value of our Convertible Senior Unsecured Notes was based on the closing trading prices on December 31, 2011 and 2010, as applicable.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
(3)
The 2007 Term Loan is closely held by few holders, and purchases and sales are infrequent and are conducted on a bilateral basis without price discovery by us. This loan is not rated and has unique covenants and collateral packages such that comparisons to other instruments would be imprecise. Nonetheless, we have provided an estimate of the fair value of this loan as of December 31, 2011 and 2010 based on an index of the yield to maturity of CCC rated debt of other companies in the energy sector, resulting in Level 3 categorization.
(4)
In December 2010, the 2008 Loans were amended to, among other things: eliminate the "put rights" which had allowed the lenders to demand repayment of the 2008 Loans on the third, fifth, and seventh anniversaries thereof; allow for the early prepayment of the 2008 Loans; allow Cheniere for a limited period to sell Cheniere Partners common units held as collateral and prepay the 2008 Loans with the proceeds; and release restrictions on prepayments of other indebtedness at Cheniere as certain conditions are met. In addition, 96.6% of the lenders agreed to terminate their rights to exchange the 2008 Loans for Series B Preferred Stock of Cheniere. Pursuant to an amendment to the 2008 Loans adopted in September 2011, the outstanding principal amount of the 2008 Loans held by Scorpion is exchangeable for shares of Cheniere common stock at a price of $5.00 per share. The estimated fair value of the 2008 Loans as of December 31, 2011 and 2010 was determined to be the same as the carrying amount due to our ability to call the debt (other than the debt held by Scorpion) at anytime without penalty or a make-whole payment for an early redemption.
NOTE 17-INCOME TAXES
Income tax provision (benefit) included in our reported net loss consisted of the following (in thousands):
The reconciliation of the federal statutory income tax rate to our effective income tax rate is as follows:
(1) We have made certain changes in the classification and presentation of certain items. These changes do not affect the
disclosed effective tax rate.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
Significant components of our deferred tax assets and liabilities at December 31, 2011 and 2010 are as follows (in thousands):
(1)
We have made changes to the disclosed 2010 share-based compensation gross deferred tax asset and the disclosed 2010 investment in limited partnership gross deferred tax liability, which had a corresponding change in the 2010 valuation allowance. These changes do not affect the 2010 disclosed net deferred tax asset.
(2)
The federal net operating loss ("NOL") carryforward expires between 2017 and 2031. The state NOL carryforward expires between 2020 and 2026.
(3) A valuation allowance equal to our U.S. and state net deferred tax asset balance has been established due to the uncertainty of realizing the tax benefits related to our U.S. and state net deferred tax assets. The change in the U.S. and state deferred tax asset valuation allowance is $83.5 million and $33.4 million for the years ended December 31, 2011 and 2010, respectively.
Changes in the balance of unrecognized tax benefits are as follows (in thousands):
At December 31, 2011, the amount of unrecognized tax benefits related to our federal NOL carryforward associated with uncertain tax positions was $135.3 million. Our effective tax rate would not be affected if the unrecognized federal 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 record interest and penalties related to unrecognized tax benefits to our income tax provision.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
During the third quarter of 2010, largely due to the increased level of trading activity in our shares, we experienced an ownership change within the provisions of Internal Revenue Code Section 382 (“Section 382”) that will subject approximately $855 million of our existing federal NOL carryforwards to an annual NOL utilization limitation. The applicable Section 382 limitation may affect our ability to fully utilize approximately $855 million of our existing federal NOL carryforward. Our ability to fully utilize our existing federal NOL carryforward is dependent on the amount of any net unrealized built in gains on the ownership change date and increasing the recognition of built-in gains in the five-year period following the above-referenced ownership change. We will continue to monitor trading activity in our shares which may cause an additional ownership change which may ultimately affect our ability to fully utilize our existing federal NOL carryforward.
We currently file tax returns in the U.S. federal jurisdiction, the United Kingdom and various state and local jurisdictions. We are no longer subject to U.S. federal, state or local income tax examinations by tax authorities for tax years prior to 2008. The Louisiana Department of Revenue is currently examining our 2007 through 2009 income tax returns.
In 2011, we generated a federal NOL of $595.4 million which is expected to be carried forward and applied against regular taxable income in future periods. Accounting for share-based compensation provides that when settlement of a share-based award contributes to an NOL carryforward, neither of the associated excess tax benefits nor the credit to additional paid-in-capital ("APIC") should be recorded until the share-based award deduction reduces income tax payable. Upon utilization of the loss in future periods, a benefit of $21.2 million will be reflected in APIC.
NOTE 18-SHARE-BASED COMPENSATION
We have granted options to purchase common stock to employees, consultants and outside directors under the Cheniere Energy, Inc. Amended and Restated 1997 Stock Option Plan ("1997 Plan") and the Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive Plan ("2003 Plan"). We recognize our share-based payments to employees in the consolidated financial statements based on their fair values at the date of grant. The calculated fair value is recognized as expense (net of any capitalization) over the requisite service period, net of estimated forfeitures, using the straight-line method.
For the years ended December 31, 2011, 2010 and 2009, the total share-based compensation expense recognized in our net loss (net of capitalization) was $26.4 million, $17.9 million and $19.2 million, respectively. The effect of a change in estimated forfeitures is recognized through a cumulative adjustment included in share-based compensation cost in the period of change in estimate. We consider many factors when estimating expected forfeitures, including types of awards, employee class and historical experience. For the years ended December 31, 2011, 2010 and 2009, the cumulative adjustment recognized in our compensation expense was $0.6 million, $1.1 million and $1.0 million, respectively. For the years ended December 31, 2011, 2010 and 2009, the total share-based compensation cost capitalized as part of the cost of capital assets was zero, zero and $1.1 million respectively.
The total unrecognized compensation cost at December 31, 2011 relating to non-vested share-based compensation arrangements granted under the 1997 Plan and 2003 Plan was $7.7 million. That cost is expected to be recognized over 4.0 years, with a weighted average period of 1.1 years.
We have disclosed the deferred tax benefit realized from share-based compensation exercised during the annual period in Note 17-"Income Taxes". A valuation allowance equal to the deferred tax asset has been established due to the uncertainty of realizing the tax benefits related to this deferred tax asset.
We received no proceeds from the exercise of stock options in the years ended December 31, 2011, 2010 and 2009.
Phantom Stock
On February 25, 2009, the Compensation Committee of our Board of Directors (the "Compensation Committee") made phantom stock grants of 5,545,000 shares pursuant to our 2003 Plan to all Cheniere executives, designated employees and one consultant. On June 12, 2009, the Compensation Committee made additional phantom stock grants of 800,000 shares to our Chief Executive Officer pursuant to the approval from our stockholders to increase the maximum number of shares granted to any one individual under our 2003 Plan during a calendar year from 1.0 million shares to 3.0 million shares. The shares were awarded under a time based plan and a performance based plan. The time based plan included an aggregate of 1,565,000 shares of phantom stock and provided for a three-year graded vesting schedule. The shares awarded under the time based plan vested equally on each
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
of December 15, 2009, 2010 and 2011. The performance based plan included an aggregate of 4,780,000 shares of phantom stock with each grant divided into three equal parts providing incentive compensation based on separate vesting terms. Vested shares of phantom stock were settled in cash or in shares of common stock, as determined by the Compensation Committee. In June 2009, we obtained approval from our stockholders to increase the number of shares of common stock available for issuance under our 2003 Plan from 11.0 million common shares to 21.0 million shares of common stock, which provided the requisite shares of common stock needed to satisfy vested phantom stock. We transferred the fair valued compensation liability associated with these phantom stock grants into additional paid-in capital. Using a Monte Carlo simulation, fair values were calculated as of June 12, 2009 for the time and performance based plans. For the year ended December 31, 2011, a total of $12.2 million was recognized as compensation expense relating to the vesting of time and performance based phantom stock grants. There was no unrecognized compensation cost at December 31, 2011 relating to non-vested phantom stock.
In May 2007, the Compensation Committee established the 2007 Incentive Compensation Plan ("2007 Bonus Plan") and the 2008-2010 Incentive Compensation Plan ("2008-2010 Bonus Plan"), each pursuant to the 2003 Plan, covering executive officers and other key employees for the performance periods of 2007 through 2010. A total of 537,000 and 1,794,000 shares of phantom stock were granted under the 2007 Bonus Plan and 2008-2010 Bonus Plan, respectively, payable in shares of common stock upon achievement of stock price hurdles established by the plans. In January 2008, 537,000 of shares of common stock were issued as the stock price hurdle for the 2007 Bonus Plan was achieved. During the fourth quarter of 2008, certain executives and key employees forfeited 1,041,000 shares of their phantom shares granted under the 2008-2010 Bonus Plan with no concurrent consideration. In connection with the forfeitures of the phantom shares, a total of $5.1 million of unrecognized compensation cost was recognized. Subsequently, on February 19, 2009, the Compensation Committee canceled the 2008-2010 Plan.
Stock Options
We estimate the fair value of stock options at the date of grant using a Black-Scholes valuation model. The risk-free rate is based on the U.S. Treasury securities yield curve in effect at the time of grant. The expected term (estimated period of time outstanding) of stock options granted is based on the “simplified” method of estimating the expected term for “plain vanilla” stock options, and varies based on the vesting period and contractual term of the stock option. Expected volatility for stock options granted is based on an equally weighted average of the implied volatility of exchange traded stock options on our common stock expiring more than one year from the measurement date, and historical volatility of our common stock for a period equal to the stock option’s expected life. We have not declared dividends on our common stock. We did not issue any options to purchase shares of our common stock during the year ended December 31, 2011.
The table below provides a summary of option activity under the 1997 Plan and 2003 Plan as of December 31, 2011:
The weighted average grant-date fair value of options granted during the years ended December 31, 2011, 2010 and 2009 was zero. The total intrinsic value of options exercised during the years ended December 31, 2011, 2010 and 2009 was zero.
Stock and Non-Vested Stock
We have granted stock, phantom stock and restricted stock and non-vested restricted stock to employees, executive officers, outside directors and consultants under the 2003 Plan. Grants of non-vested stock are accounted for on an intrinsic value basis. The amortization of the calculated value of non-vested stock grants is accounted for as a charge to compensation and an increase in additional paid-in-capital over the requisite service period.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
For the years ended December 31, 2011, 2010 and 2009, we issued 5,262,000 shares, 502,000 shares and 522,000 shares, respectively, of phantom stock awards to our executives and certain officers.
For the years ended December 31, 2011, 2010 and 2009, we issued 2,565,000 shares, 1,234,000 shares and 325,000 shares, respectively, of restricted stock awards to our employees, executives, directors and a consultant as performance, retention, service and new hire awards. A majority of the awards were issued with a one, three or four-year graded vesting period. A certain group of 2007 retention grants received a vesting schedule of 50% on December 1, 2008, 30% on December 1, 2009 and 20% on June 1, 2010. A certain group of 2011 restricted stock awards received a vesting schedule of 33% on June 30, 2011, 33% on June 30, 2012, and 33% on June 30, 2013.
On May 25, 2007, the Compensation Committee approved a bonus plan covering substantially all employees not otherwise included in the 2007 Plan. This plan provided covered employees the ability to earn bonuses based on the achievement of established annual performance goals as well as a stock price appreciation goal. The fair value of the grants was recalculated at each balance sheet date until the total number of restricted shares was granted in January 2008. Because of the existence of the stock price appreciation goal, which was a market condition, the restricted stock was not eligible for amortization under the straight-line method, and each vesting tranche is being amortized separately.
The table below provides a summary of the status of our non-vested shares under the 2003 Plan as of December 31, 2011 (in thousands except for per share information):
The weighted average grant date fair values per share of restricted stock granted during the years ended December 31, 2011, 2010 and 2009 were $7.72, $3.31, and zero, respectively. The total grant date fair value per share of shares vested during the years ended December 31, 2011, 2010 and 2009 were $7.26, $5.54 and $3.07, respectively.
Share-based Plan Descriptions and Information
Our 1997 Plan provides for the issuance of stock options to purchase up to 5.0 million shares of our common stock, all of which have been granted. Non-qualified stock options were granted to employees, contract service providers and outside directors.
In June 2009, we obtained approval from our stockholders to increase the number of shares of common stock available for issuance under our 2003 Plan from 11.0 million shares to 21.0 million shares. These awards may be in the form of non-qualified stock options, incentive stock options, purchased stock, restricted (non-vested) stock, bonus (unrestricted) stock, stock appreciation rights, phantom stock and other share-based performance awards deemed by the Compensation Committee to be consistent with the purposes of the 2003 Plan. To date, the only awards made by the Compensation Committee have been in the form of non-qualified stock options, restricted stock, restricted stock units and phantom shares.
401(k) Plan
In 2005, we established a defined contribution pension plan ("401(k) Plan"). The 401(k) Plan allows eligible employees to contribute up to 100% of their compensation up to the IRS maximum. We match each employee’s salary deferrals (contributions) up to six percent of compensation and may make additional contributions at our discretion. Effective January 1, 2007, employees are immediately vested in the contributions made by us. Our contributions to the 401(k) Plan were $1.1 million, $1.0 million and $1.4 million for the years ended December 31, 2011, 2010 and 2009, respectively. We have made no discretionary contributions to the 401(k) Plan to date.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
NOTE 19-COMPREHENSIVE LOSS
The following table is a reconciliation of our net loss to our comprehensive loss for the periods shown (in thousands):
NOTE 20-COMMITMENTS AND CONTINGENCIES
LNG Terminal Commitments and Contingencies
Obligations under LNG TUAs
Sabine Pass LNG has entered into third-party TUAs with Total and Chevron to provide berthing for LNG vessels and for the unloading, storage and regasification of LNG at the Sabine Pass LNG terminal.
Obligations under Bechtel EPC Contract
In November 2011, Sabine Pass Liquefaction entered into a lump sum turnkey agreement with Bechtel for the engineering, procurement and construction of the first two LNG trains and related facilities at the Sabine Pass LNG terminal (the "EPC Contract"), with each LNG train having a nominal capacity of approximately 4.5 mtpa. The contract provides that Sabine Pass Liquefaction will pay Bechtel a contract price of $3.9 billion, which is subject to adjustment by change order. Sabine Pass Liquefaction has the right to terminate the EPC Contract for its convenience, in which case Bechtel will be paid (i) the portion of the contract price for the work performed, (ii) costs reasonably incurred by Bechtel on account of such termination and demobilization, and (iii) a lump sum of between $1.0 million and $2.5 million depending on the termination date if the EPC Contract is terminated prior to issuance of the notice to proceed and up to $30.0 million depending on the termination date if the EPC Contract is terminated after issuance of the notice to proceed.
Crest Royalty
Under a settlement agreement dated as of June 14, 2001, we agreed to pay or cause certain affiliates, successors and assigns to pay a royalty, which we refer to as the Crest Royalty. This Crest Royalty is calculated based on the volume of natural gas processed through covered LNG facilities. In 2003, Freeport LNG contractually assumed the obligation to pay the Crest Royalty for natural gas processed at Freeport LNG’s receiving terminal. The Crest Royalty is subject to a maximum of approximately $11.0 million and a minimum of $2.0 million per production year. The calculation of the Crest Royalty, and the scope of Freeport LNG's assumed obligation to pay the Crest Royalty, are being litigated in a breach of contract and declaratory judgment action pending in Texas state court.
Restricted Net Assets
At December 31, 2011, our restricted net assets of consolidated subsidiaries were approximately ($240.2) million.
Other Commitments
In the ordinary course of business, we have issued surety bonds related to our offshore oil and gas operations and entered into certain multi-year licensing and service agreements, none of which are considered material to our financial position.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
Legal Proceedings
We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. In the opinion of management, as of December 31, 2011, there were no threatened or pending legal matters that would have a material impact on our consolidated results of operations, financial position or cash flows.
NOTE 21-BUSINESS SEGMENT INFORMATION
We have three operating business segments: LNG terminal business, natural gas pipeline business and LNG and natural gas marketing business. These operating segments reflect lines of business for which separate financial information is produced internally and are subject to evaluation by our chief operating decision makers in deciding how to allocate resources.
Our LNG terminal business segment consists of the operational Sabine Pass LNG terminal, approximately 88.8% owned (at December 31, 2011) in western Cameron Parish, Louisiana on the Sabine Pass Channel and two other LNG terminals that are in various stages of development at the following locations: Corpus Christi LNG, 100% owned, near Corpus Christi, Texas; and Creole Trail LNG, 100% owned, at the mouth of the Calcasieu Channel in central Cameron Parish, Louisiana.
Our natural gas pipeline business segment consists of the Creole Trail Pipeline, consisting of 94 miles of natural gas pipeline connecting the Sabine Pass LNG terminal to numerous interconnections points with existing interstate natural gas pipelines in southwest Louisiana, and other natural gas pipelines in various stages of development to provide access to North American natural gas markets.
Our LNG and natural gas marketing business segment is seeking to enter into long-term commercial agreements for regasification capacity; develop a portfolio of long-term, short-term, and spot LNG purchase and sale agreements; assist Cheniere Partners in negotiations with potential customers for importing and exporting natural gas through the Sabine Pass LNG terminal; and enter into business relationships for the domestic marketing of natural gas imported by Cheniere Marketing as LNG to the Sabine Pass LNG terminal.
The following table summarizes revenues, net income (loss) from operations and total assets for each of our operating segments (in thousands):
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
(1)
Includes corporate activities, oil and gas exploration, development and exploitation activities and certain intercompany eliminations. Our oil and gas exploration, development and exploitation operating activities have been included in the corporate and other column due to the lack of a material impact that these activities have on our consolidated financial statements.
(2)
Intersegment revenues related to our LNG terminal segment are primarily from tug revenues from Cheniere Marketing and the receipt of 80% of gross margins earned by Cheniere Marketing in monetizing the TUA capacity of Cheniere Energy Investments, LLC ("Cheniere Investments") at the Sabine Pass LNG terminal in the year ended December 31, 2011. These LNG terminal segment intersegment revenues are eliminated with intersegment expenses in our Consolidated Statements of Operations.
(3)
Intersegment losses related to our LNG and natural gas marketing segment are primarily from Cheniere Marketing's tug costs and the payment of 80% of gross margins earned by Cheniere Marketing in monetizing the TUA capacity of Cheniere Investments at the Sabine Pass LNG terminal in the year ended December 31, 2011. These LNG terminal segment intersegment costs are eliminated with intersegment revenues in our Consolidated Statements of Operations.
(4)
Intersegment revenues related to our LNG terminal segment are primarily from TUA capacity reservation fee revenues and tug revenues of $125.5 million and $250.2 million that were received from our LNG and natural gas marketing segment for the years ended December 31, 2010 and 2009, respectively. These LNG terminal segment intersegment revenues are eliminated with intersegment expenses in our Consolidated Statements of Operations.
(5)
Intersegment revenues related to our natural gas pipeline segment are primarily from transportation fees charged by our natural gas pipeline segment to our LNG terminal and LNG and natural gas marketing segments to transport natural gas that was regasified at the Sabine Pass LNG terminal. These natural gas pipeline segment intersegment revenues are eliminated with intersegment expenses in our Consolidated Statements of Operations.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
(6)
Intersegment losses related to our LNG and natural gas marketing segment are primarily from TUA capacity reservation fee expenses and tug costs of $125.5 million and $250.2 million that were incurred from our LNG terminal segment for the years ended December 31, 2010 and 2009, respectively. These costs and expenses are classified as marketing trading gains (losses) as they are considered capacity contracts related to our energy trading and risk management activities. These LNG and natural gas marketing segment intersegment costs and expenses are eliminated with intersegment revenues in our Consolidated Statements of Operations.
(7)
Intersegment losses related to corporate and other are from various transactions between our LNG terminal, natural gas pipeline and LNG and natural gas marketing segments in which revenue recorded by one operating segment is eliminated with a non-revenue line item (i.e., operating expense or is capitalized) by the other operating segment.
NOTE 22-SUPPLEMENTAL CASH FLOW INFORMATION AND DISCLOSURES OF NON-CASH TRANSACTIONS
The following table provides supplemental disclosure of cash flow information (in thousands):
NOTE 23-SUBSEQUENT EVENTS (UNAUDITED)
In January 2012, we repaid in full the outstanding principal balance of the $298.0 million 2007 Term Loan due May 31, 2012. We used a portion of the net proceeds from the public offering of 41,745,000 shares of common stock in December 2011 to repay the 2007 Term Loan. The aggregate repayment amount was $298.2 million, including the outstanding principal amount and accrued interest through January 5, 2012.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
SUMMARIZED QUARTERLY FINANCIAL DATA
(unaudited)
Quarterly Financial Data-(in thousands, except per share amounts)
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
Based on their evaluation as of the end of the fiscal year ended December 31, 2011, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act are (i) accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and (ii) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
Our Management's Report on Internal Control Over Financial Reporting is included in our Consolidated Financial Statements on page 54 and is incorporated herein by reference.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
Pursuant to paragraph 3 of General Instruction G to Form 10-K, the information required by Items 10 through 14 of Part III of this Report is incorporated by reference from Cheniere’s definitive proxy statement, which is to be filed pursuant to Regulation 14A within 120 days after the end of Cheniere’s fiscal year ended December 31, 2011.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)
Financial Statements, Schedules and Exhibits
(1)
Financial Statements-Cheniere Energy, Inc. and Subsidiaries:
Management’s Reports to the Stockholders of Cheniere Energy, Inc.
Reports of Independent Registered Public Accounting Firm-Ernst & Young LLP
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Stockholders’ (Deficit) Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Supplemental Information to Consolidated Financial Statements-Summarized Quarterly Financial Data
(2)
Financial Statement Schedules:
(3) Exhibits:
* Incorporated by reference
† Management contract or compensatory plan or arrangement
SCHEDULE I-CONDENSED FINANCIAL INFORMATION OF REGISTRANT-
CHENIERE ENERGY, INC.
CONDENSED BALANCE SHEET
(in thousands)
See accompanying notes to condensed financial statements.
SCHEDULE I-CONDENSED FINANCIAL INFORMATION OF REGISTRANT-
CHENIERE ENERGY, INC.
CONDENSED STATEMENT OF OPERATIONS
(in thousands)
See accompanying notes to condensed financial statements.
SCHEDULE I-CONDENSED FINANCIAL INFORMATION OF REGISTRANT-
CHENIERE ENERGY, INC.
CONDENSED STATEMENT OF CASH FLOWS
(in thousands)
See accompanying notes to condensed financial statements
SCHEDULE I-CONDENSED FINANCIAL INFORMATION OF REGISTRANT-
CHENIERE ENERGY, INC.
NOTES TO CONDENSED FINANCIAL STATEMENTS
NOTE 1-SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The condensed financial statements represent the financial information required by Securities and Exchange Commission Regulation S-X 5-04 for Cheniere Energy, Inc ("Cheniere").
In the condensed financial statements, Cheniere’s investments in affiliates are presented under the equity method of accounting. Under this method, the assets and liabilities of affiliates are not consolidated. The investments in net assets of the affiliates are recorded in the balance sheet. The loss from operations of the affiliates is reported on a net basis as equity in net losses of affiliates.
A substantial amount of Cheniere’s operating, investing, and financing activities are conducted by its affiliates. The condensed financial statements should be read in conjunction with Cheniere’s consolidated financial statements.
NOTE 2-DEBT
As of December 31, 2011 and 2010, our debt consisted of the following (in thousands):
Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31, 2011 (in thousands):
(1)
Based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2011, our cash payments for interest would be $18.6 million in 2012.
SCHEDULE I-CONDENSED FINANCIAL INFORMATION OF REGISTRANT-
CHENIERE ENERGY, INC.
NOTES TO CONDENSED FINANCIAL STATEMENTS
Note-Affiliate
In May 2007, we entered into a $391.7 million long-term note ("Note-Affiliate") with Cheniere Subsidiary Holdings, LLC ("Cheniere Subsidiary"), a wholly owned subsidiary of Cheniere. Cheniere Subsidiary received the $391.7 million net proceeds from a $400 million credit agreement entered into in May 2007. Borrowings under the Note-Affiliate bear interest equal to the terms of Cheniere Subsidiary's credit agreement at a fixed rate of 9¾% per annum. Interest is calculated on the unpaid principal amount of the Note-Affiliate outstanding and is payable quarterly in arrears on March 31, June 30, September 30 and December 31 of each year. The Note-Affiliate will mature on May 31, 2012. In August 2008, the Note-Affiliate was replaced with a global intercompany note entered into by all Cheniere subsidiaries that were parties to the 2008 Loans. Each subsidiary is both a maker and a payee under the global intercompany note, and balances between subsidiaries are as recorded on Cheniere's books and records. The $391.7 million of proceeds from the Note-Affiliate were used for general corporate purposes, including our repurchase, completed during 2007, of approximately 9.2 million shares of our outstanding common stock pursuant to the exercise of the call options acquired in the issuer call spread purchased by us in connection with the issuance of the Convertible Senior Unsecured Notes.
NOTE 3-GUARANTEES
Guarantees on Behalf of Cheniere Marketing, LLC
Marketing and Trading Guarantees
Our LNG and natural gas marketing business segment is pursuing a two-front commercial strategy focused on producing long-term recurring cash flow by capitalizing on 2.0 Bcf/d of regasification capacity at the Sabine Pass LNG terminal reserved by Cheniere Energy Investments, LLC ("Cheniere Investments"). Our strategy is to remain engaged in the LNG spot market as opportunities arise, and to maintain relationships with key suppliers and market participants that we believe are candidates for entering into long-term LNG cargo sales and/or the purchase of TUA capacity currently reserved by Cheniere Investments. Many of Cheniere Marketing, LLC’s natural gas purchase, sale, transportation and shipping agreements have been guaranteed by Cheniere. As of December 31, 2011, these contracts have been guaranteed by Cheniere and have zero amount of exposure to the potential of future payments. There was zero carrying amount of liability related to these guaranteed contracts as of December 31, 2011.
Guarantee on behalf of Sabine Pass Tug Services, LLC
Sabine Pass Tug Services, LLC ("Tug Services"), a wholly owned subsidiary of Cheniere Energy Partners, L.P., entered into a Marine Services Agreement ("Tug Agreement") for three tugs with Alpha Marine Services, LLC. The initial term of the Tug Agreement ends on the tenth anniversary of the service date, with Tug Services having the option for two additional extension terms of five years each. This contract has been guaranteed by Cheniere for up to $5.0 million.
NOTE 4 -SUPPLEMENTAL CASH FLOW INFORMATION AND DISCLOSURES OF NON-CASH TRANSACTIONS
(1)
Amounts represent equity losses of affiliates not funded by Cheniere.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
CHENIERE ENERGY, INC.
(Registrant)
By:
/s/ CHARIF SOUKI
Charif Souki
Chief Executive Officer, President and
Chairman of the Board
Date:
February 24, 2012
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.