Item 1. and 2. Business and Properties
General
Cheniere Energy Partners
Business Segments
Overview of the LNG Industry
Our Business Strategy
LNG Receiving Terminal Business
Natural Gas Pipeline Business
LNG and Natural Gas Marketing Business
Oil and Gas Exploration, Development and Exploitation Activities
Financial Information about Segments
Subsidiaries
Employees
Item 1A.
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 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 operation, 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 Receiving 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
We have substantial indebtedness, which we will need to refinance in whole or in part at or prior to maturity.
As of December 31, 2008, we had $3.2 billion of indebtedness, consisting primarily of a $400.0 million term loan due 2012 (“2007 Term Loan”), $550.0 million of 7 1/4 % Senior Secured Notes due 2013 (the “2013 Notes”), $1,628.3 of 7 1/2% Senior Secured Notes due 2016 (the “2016 Notes” and collectively with the 2013 Notes, the “Senior Notes”), $325.0 million aggregate principal amount of Convertible Senior Unsecured Notes due 2012 (“Convertible Senior Unsecured Notes”) and $250.0 million in convertible term loans due 2018 (“2008 Convertible Loans”). We will need to refinance all or a portion of our indebtedness. We may not be able to refinance our indebtedness as needed, on commercially reasonable terms or at all.
Our substantial indebtedness could adversely affect our ability to operate our business and prevent us from satisfying or refinancing our debt obligations.
Our substantial indebtedness could have important adverse consequences, including:
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making it more difficult for us to satisfy or refinance our debt obligations;
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limiting our ability to obtain additional financing to fund our capital expenditures, working capital, acquisitions, debt service requirements or liquidity needs for general business or other purposes;
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limiting our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to service debt, including indebtedness that we may incur in the future;
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limiting our ability to compete with other companies that are not as highly leveraged;
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limiting our ability to react to changing market conditions in our industry and to economic downturns;
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limiting our flexibility in planning for, or reacting to, changes in our business and future business opportunities;
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making us more vulnerable than a less leveraged company to a downturn in our business or in the economy;
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limiting our ability to attract customers; and
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resulting in a material adverse effect on our business, results of operations and financial condition if we are unable to service or refinance our indebtedness or obtain additional financing, as needed.
Index to Financial Statements Our substantial indebtedness and the restrictive covenants contained in our debt agreements may not allow us the flexibility that we need to operate our business in an effective and efficient manner and may prevent us from taking advantage of strategic and financial opportunities that would benefit our business.
Our ability to satisfy or refinance our debt obligations will depend upon our future operating performance. Prevailing economic conditions and financial, business and other factors, many of which are beyond our control, will also affect our ability to make payments on our debt obligations. We will need to seek to refinance all or a portion of our existing indebtedness on or before maturity, even if market conditions for such refinancings are adverse at the time. We may not be able to refinance any of our indebtedness on commercially reasonable terms or at all.
We have not been profitable historically, and we are currently experiencing negative 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 $356.5 million and $181.8 million for the years ended December 31, 2008 and 2007, respectively. In the future, we may incur operating losses and experience negative operating cash flow. We do not expect current cash inflows to be sufficient to fund our 2009 expenditures. We are dependent upon our existing cash resources.
Our existing level of cash resources, negative cash flow and limited ability to obtain additional financing could cause us to have inadequate liquidity and could materially and adversely affect our business, financial condition and prospects.
As of December 31, 2008, we had $102.2 million of cash and cash equivalents and $460.9 million of restricted cash and cash equivalents and U.S. Treasury securities, including $71.1 million of restricted cash to be used to complete construction and commissioning of the Sabine Pass LNG receiving terminal. Our ability to generate positive operating cash flow and achieve profitability, so as to enhance our liquidity position in the future, is subject to a number of risks, including those discussed below.
Our future liquidity may also be affected by the timing of construction financing availability in relation to the incurrence of construction costs and other outflows and by the anticipated timing of receipt of cash flow under TUAs and other sales of capacity in relation to the incurrence of projected project operating expenses. Many other factors (including factors beyond our control) could also result in a disparity between liquidity sources and cash needs, including factors such as construction delays and breaches of agreements.
Our substantial existing indebtedness, prevailing economic and market conditions, as well as other factors, have adversely affected the availability and cost of additional financing, which has adversely affected our liquidity, business, financial condition and prospects.
Our ability to generate needed amounts of cash is substantially dependent upon our TUAs with two third-party Sabine Pass LNG customers, and we will be materially and adversely affected if either customer fails to perform its TUA obligations for any reason.
Our future results and liquidity are 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 commencing during 2009. We are dependent on each customer’s continued willingness and ability to perform its obligations under its TUA. We are also exposed to the credit risk of the guarantors of these customers’ obligations under their TUAs in the event that we must seek recourse under a guaranty. If any customer fails to perform its obligations under its TUA, our business, results of operations, financial condition and prospects could be materially adversely affected, even if we were ultimately successful in seeking damages from that customer or its guarantor for a breach of the TUA.
Index to Financial Statements Each customer’s TUA for capacity at the Sabine Pass LNG receiving terminal is subject to termination under certain circumstances.
The long-term TUAs with each of Total and Chevron contain various termination rights. For example, each customer may terminate its TUA if the Sabine Pass LNG receiving 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. We may not be able to replace these TUAs on desirable terms, or at all, if they are terminated.
Our ability to generate needed amounts of cash is also substantially dependent upon our ability to commercially exploit the capacity at the Sabine Pass LNG terminal that we have reserved for our own account.
Our ability to generate positive operating cash flow and achieve profitability in the future is also significantly dependent upon our ability to commercially exploit the TUA capacity that our subsidiary, Cheniere Marketing, LLC (“Cheniere Marketing”) has reserved at the Sabine Pass LNG receiving terminal. As discussed below under “-Risks Relating to Our LNG and Natural Gas Marketing Business-We may not be able to commercially exploit the capacity we have reserved at the Sabine Pass LNG receiving terminal”, there are significant risks attendant to Cheniere Marketing’s future ability to generate operating cash flow. Failure by Cheniere Marketing to succeed in commercially exploiting its reserved TUA capacity at the Sabine Pass LNG receiving terminal could materially and adversely affect our business, results of operations, financial condition and prospects.
Our ability to develop our planned LNG receiving terminals and pipelines and to pursue our other business plans is contingent on our ability to obtain funding. If we are unable to do so, we may be unable to implement or complete our business plan, and our business may ultimately be unsuccessful.
We will need substantially more financing to complete all of our proposed LNG receiving terminals and natural gas pipelines. Prevailing economic and market conditions, as well as other factors, have caused us to defer or limit expenditures we might otherwise have made in developing our business. Such deferrals or limitations in the development of our business could continue and could adversely affect our ability to pursue our business strategy, our results of operations, our financial condition and our prospects. To fund these development projects, we plan to pursue a variety of sources of funding, including some or all of the following:
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debt and/or equity financing at the project level;
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debt and/or equity financing by Cheniere or its subsidiaries; and
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asset sales, to the extent permitted, and joint venture arrangements by Cheniere or its subsidiaries.
Our ability to obtain these or other types of financing will depend, in part, on factors beyond our control, such as the status of various debt and equity markets at the time financing is sought and such markets’ view of our industry and prospects at such time. In particular, currently tight lending conditions may make it more time consuming and expensive for us to obtain financing, if we can obtain financing at all. Accordingly, we may not be able to obtain financing on terms that are acceptable to us, if at all, even if our development projects could otherwise proceed on schedule. In addition, our ability to obtain some types of financing may be dependent upon our ability to obtain other types of financing. For example, project-level debt financing is typically contingent upon a significant equity capital contribution from the project sponsor. As a result, even if we are able to identify potential project-level lenders, we may still have to obtain another form of external financing for us to fund an equity capital contribution to the project subsidiary. Moreover, any future project-level debt financing for additional LNG receiving terminals or pipelines would likely be conditioned upon our prior receipt of commitments from third parties to pay for the projected capacity of the terminals or pipelines, as well as our achievement of additional milestones. A failure to obtain financing at any point in the development process of any of our projects could cause us to delay or fail to complete our business plan, which could cause our business to be unsuccessful.
Index to Financial Statements Even if we are able to obtain financing, the terms required may adversely affect our business.
In order to obtain many types of financing, we may have to accept terms that are disadvantageous to us or that may have an adverse impact on our current or future business, operations or financial condition. For example:
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borrowings or debt issuances may subject us to certain restrictive covenants, including covenants restricting our ability to raise additional capital or cross-defaults to our other indebtedness;
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borrowings or debt issuances at the project level may subject the project entity to restrictive covenants, including covenants restricting its ability to make distributions to us or limiting our ability to sell our interests in such entity;
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additional sales of interests in our projects would reduce our interest in future revenues once the projects commence operations;
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the prepayment of terminal use fees by, or a business development loan from, prospective customers would reduce future revenues once the LNG receiving terminals commence operations;
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offerings of our equity securities would cause dilution for holders of our common stock and Series B Preferred Stock;
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our ability to borrow funds under some project financing arrangements would likely be subject to our satisfying the conditions and covenants in the financing and the construction schedule agreed to at the time we entered into such arrangement. If circumstances changed, we could need to seek waivers of conditions or covenants under our financing arrangements to prevent defaults thereunder and acceleration thereof, which we might not be able to obtain on a timely basis, or at all; and
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we could be required to make equity contributions before we could borrow under certain financing arrangements.
Risks Relating to Our LNG Receiving Terminal Business
We may not complete in a timely and cost-effective manner, or at all, the remaining construction and commissioning of the Sabine Pass LNG receiving terminal or the construction and commissioning of our other planned LNG receiving terminals.
Factors that could adversely affect our planned construction, completion and commissioning of our existing and planned LNG receiving terminals include:
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failure by contractors to fulfill their obligations under their construction contracts, or disagreements with them over their contractual obligations;
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failure to enter into satisfactory additional agreements with contractors;
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shortages of materials or delays in delivery of materials;
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cost overruns and difficulty in obtaining sufficient debt or equity financing to pay for such additional costs;
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difficulties or delays in obtaining LNG for commissioning activities at acceptable costs;
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failure to obtain and retain all necessary governmental and third-party permits, licenses and approvals for construction and operation;
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weather conditions, such as hurricanes and floods, and other catastrophes, such as explosions, fires and accidents;
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difficulties in attracting and maintaining a sufficient skilled and unskilled workforce;
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increases in the level of labor costs and the existence of any labor disputes;
Index to Financial Statements
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resistance in the local community due to safety, environmental or security concerns; and
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local and general economic and infrastructure conditions.
These factors could also adversely affect the timing or cost of completing the remaining 1.4 Bcf/d of sendout capacity and 6.7 Bcf of storage capacity that remained under construction at the Sabine Pass LNG receiving terminal as of December 31, 2008
Cost overruns and delays in the completion of the Sabine Pass LNG receiving terminal or in the construction of our proposed LNG receiving terminals, as well as difficulties in obtaining funding for additional costs, could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.
We have experienced cost overruns of the construction, cool down, commissioning and completion of the Sabine Pass LNG receiving terminal. Our ultimate construction costs for Sabine Pass or other proposed LNG receiving terminals and pipelines may be significantly higher than our current estimates as a result of additional cost overruns, change orders under existing or future construction contracts, increased component and material costs, escalating labor costs, limited availability of labor, delays in construction and increased spending to maintain construction schedules.
Furthermore, in order to cover future increased construction costs, we would likely need to obtain additional funding. If we fail to obtain sufficient funding, our business plan could fail. Our ability to obtain debt or equity financing that may be needed to provide additional funding to cover increased construction costs will depend, in part, on factors beyond our control, such as the status of various capital and industry markets at the time financing is sought. Accordingly, we may not be able to obtain financing on terms that are acceptable to us, if at all. Even if we are able to obtain financing, we may have to accept terms that are disadvantageous to us or that may have a material adverse effect on our current or future business, results of operations, financial condition and prospects.
We are dependent on contractors for the successful completion of our LNG receiving terminals.
We have limited experience constructing LNG receiving terminals. Timely and cost-effective completion of the Sabine Pass LNG receiving terminal and our other proposed LNG receiving terminals in compliance with agreed specifications is central to our business strategy and is highly dependent on our existing or future contractors’ performance under their agreements with us. 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 the Sabine Pass LNG receiving terminal and our other proposed LNG receiving terminals 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 of our existing EPC contracts 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 the completion or impair the operation of the affected facility, and any
Index to Financial Statements
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. In addition, each contractor’s liability for liquidated damages is subject to a cap. Each of our material agreements with contractors is also subject to termination by the contractor prior to completion of construction under certain circumstances, including extended delays (of 100 days or more) caused by force majeure events and our insolvency, breach of material obligations not subject to adjustment by change order, or failure to pay undisputed amounts.
Furthermore, disagreements with our contractors about different elements of the construction process 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.
To commission and test our LNG receiving terminals or in order to maintain their cryogenic readiness, we may need to purchase and process LNG. The cost of such LNG may exceed our estimates, and we may not be able to acquire it at an affordable price or at all. Furthermore, even if we are able to acquire LNG, we may not be able to resell the regasified LNG for a profit or at all.
LNG storage tanks and other equipment at our LNG receiving terminals must undergo a commissioning and testing process before commencement of operations. The commissioning process requires a substantial quantity of LNG as well as access to adequate LNG vessels to deliver the LNG. As of December 31, 2008, we had obtained three cargoes of LNG for commissioning at the Sabine Pass LNG receiving terminal. Our construction cost estimates include amounts to cover our estimated net costs of acquiring the LNG necessary to complete the commissioning and testing process at our LNG receiving terminals. Our actual cost to obtain LNG necessary for the commissioning and testing process could exceed our estimates, and the overrun could be significant.
Risks associated with acquiring LNG include the following:
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we may be unable to enter into contracts for the purchase of the LNG, and may be unable to obtain vessels to deliver such LNG, on terms reasonably acceptable to us or at all;
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we may bear the commodity price risk associated with purchasing the LNG, holding it in inventory for a period of time and selling the regasified LNG; and
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we may be unable to obtain financing for the purchase and shipment of the LNG on terms that are reasonably acceptable to us or at all.
Our failure to obtain LNG, LNG vessels, or both, on economical terms, or our inability to finance the purchase of LNG for commissioning or for maintenance of cryogenic readiness to provide services under our TUAs, could impede completion of commissioning and testing or provide our TUA customers with the opportunity to interrupt or terminate their payment under their TUAs. Any of these occurrences could have a material adverse effect on our business, results of operations, financial condition and prospects.
We may be required to purchase natural gas to provide fuel at the Sabine Pass LNG receiving terminal, which would increase operating costs and could have a material adverse effect on our results of operations.
Sabine Pass LNG’s three TUAs provide for an in-kind deduction of 2% of the LNG delivered to the Sabine Pass LNG receiving terminal, which we will use 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 we will have to purchase additional natural gas from third parties. We will bear the cost and risk of changing prices for any such fuel.
Index to Financial Statements We may not be able to enter into satisfactory TUAs with third-party customers for regasification capacity at our proposed LNG receiving terminals, as we have sought to do in order to implement and complete our business plan. We may change our business strategy as to how and when we market LNG receiving terminal capacity.
Our current business strategy calls for us to enter into long-term TUAs for a portion of the regasification capacity at our proposed LNG receiving terminals, including a commitment to pay capacity reservation fees. The portion of our total regasification capacity that we plan to commit under such long-term TUAs has changed in the past and may change in the future for various reasons, including responding to market factors or perceived opportunities that we believe may be available to us. Our ability to obtain financing for a proposed LNG receiving facility may be contingent on our ability to enter into commercial agreements in advance of the commencement of construction. To date, we have not entered into any third-party agreements for either of our proposed LNG receiving terminals.
We may experience difficulty attracting additional customers because we are a small, developing company with no operating history in the LNG business. In order to succeed, we must convince additional potential customers, among other things, that we will be able to secure adequate financing for the construction of the proposed LNG receiving terminals and related natural gas pipelines that we are developing and that these projects will be approved by appropriate governmental agencies.
We may also change our business strategy due to our inability to enter into agreements with additional customers or based on our views regarding future prices, demand and supply of natural gas and regasification capacity. If our efforts to market LNG receiving terminal and related pipeline capacity are not successful, our business, results of operations, financial condition and prospects could be materially adversely affected.
Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the development and operation of our LNG receiving terminals could impede completion or operation and could have a material adverse effect on us.
The design, construction and operation of our LNG receiving terminals is a highly regulated activity. The FERC’s approval under Section 3 of the Natural Gas Act of 1938, or the NGA, as well as several other material governmental and regulatory approvals and permits, are required in order to construct and operate an LNG receiving terminal. Although we have obtained all of the necessary authorizations to construct and operate the Sabine Pass LNG receiving terminal, such authorizations are subject to ongoing conditions imposed by regulatory agencies. 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 and prospects.
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 receiving terminal site was temporarily suspended in connection with Hurricane Katrina, as a precautionary measure. Approximately three weeks after the occurrence of Hurricane Katrina, the 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 receiving terminal experienced construction delays and increased costs. In September 2008, Hurricane Ike struck the Texas and Louisiana coast and we experienced damage at the Sabine Pass LNG receiving terminal.
Future storms and related storm activity and collateral effects, or other disasters such as explosions, fires, floods or accidents, could result in damage to, delays or cost increases in construction of, or interruption of operations at, our LNG receiving terminals or related infrastructure.
Index to Financial Statements After our LNG receiving terminals are placed in service, their businesses will involve significant operational risks.
Our LNG receiving terminals will face risks associated with operating the facilities. These risks will include, but will not be limited to, the following:
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the facilities’ 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.
Risks Relating to Our Natural Gas Pipeline Business
Expanding our business by constructing additional pipelines subjects us to risks.
The construction of a new pipeline involves numerous regulatory, environmental, political and legal uncertainties beyond our control and requires the expenditure of significant amounts of capital that we will be required to finance through borrowings, through the issuance of additional equity or from operating cash flow. If we undertake these projects, they may not be completed on schedule, at the budgeted cost or at all. Whenever we build a new pipeline, the construction may occur over an extended period of time, and we will not receive any revenues until the pipeline has been completed and customers pay for transportation service on the pipeline. Moreover, we may construct pipelines to capture anticipated future growth in a region in which such growth does not materialize. As a result, our pipelines may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition. Our ability to obtain financing for a pipeline construction project may depend upon the level of LNG import activity in the areas proposed to be served by the project as well as our ability to obtain commitments from LNG suppliers and other customers to utilize the newly constructed pipeline.
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. Failure to obtain any third-party, firm transportation customers could have a material adverse impact on our business.
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 Clean Air Act and the Clean Water Act from the U.S. Army Corps of Engineers and the Louisiana Department of Environmental Quality. 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
Index to Financial Statements
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 and prospects.
Our existing and proposed 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 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 FERC audits our contracts and finds deviations that appear to be unduly discriminatory, 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 Energy Policy Act of 2005, the FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation.
The FERC could change its current ratemaking policies, and those changes could have adverse effects on our proposed pipelines.
Any reduction in the capacity of, or the allocations to, interconnecting, third-party pipelines could cause a reduction of volumes transported in our existing and proposed 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 and financial condition.
Our pipeline business could be materially adversely affected if we lose the right to situate our pipelines on property owned by third parties.
We do not anticipate owning the land on which our proposed pipelines will be constructed, and we are subject to the possibility of increased costs to obtain and retain necessary land use. We anticipate obtaining the right to construct and operate our pipelines on land owned by third parties for a period of time. If we were to lose these rights or be required to relocate our pipelines, our business could be materially adversely affected.
Pipeline safety integrity programs and repairs may impose significant costs and liabilities on us.
The Federal Office of Pipeline Safety has issued a final rule requiring 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 what the rule refers to as “high consequence areas” where a leak or rupture could potentially do the most harm. The final rule requires operators 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;
Index to Financial Statements
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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 preventive and mitigating actions.
We will be required to initiate pipeline integrity testing programs that are intended to assess pipeline integrity. The rule, or an increase in public expectations for pipeline safety, may require additional reporting and more frequent inspection or testing of our pipeline facilities. 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.
Risks Relating to Our LNG and Natural Gas Marketing Business
We may be unable to commercially exploit the capacity at the Sabine Pass LNG terminal that we have reserved for our own account.
The success of our LNG and natural gas marketing business will be significantly dependent upon our ability to commercially exploit the TUA capacity that Cheniere Marketing has reserved at the Sabine Pass LNG receiving terminal. That, in turn, is subject to substantial risks, including the following:
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Cheniere Marketing does not have unconditional agreements or arrangements for any supplies of LNG, or for the utilization of capacity that it has contracted for under its TUA with us and may not be able to obtain such agreements or arrangements on economical terms, or at all;
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Cheniere Marketing does not have unconditional commitments from customers for the purchase of the natural gas it proposes to sell from our LNG receiving terminal, and it may not be able to obtain commitments or other arrangements on economical terms, or at all;
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in order to arrange for supplies of LNG, and for transportation, storage and sales of natural gas, Cheniere Marketing will require significant credit support and funding, which we may not be able to obtain on terms that are acceptable to us, or at all; and
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even if Cheniere Marketing is able to arrange for and finance supplies and transportation of LNG to the Sabine Pass LNG receiving terminal, and for transportation, storage and sales of natural gas to customers, it may experience negative cash flows and adverse liquidity effects due to fluctuations in supply, demand and price for LNG, for transportation of LNG, for natural gas and for storage and transportation of natural gas.
Cheniere Marketing has a limited operating history, limited capital, no credit rating and an unproven business strategy. In addition, we have a non-investment grade corporate rating of CCC+ from Standard and Poor’s, which limits our ability to enhance the creditworthiness of Cheniere Marketing. These factors create financial obstacles and exacerbate the risk that Cheniere Marketing will not be able to enter into commercial arrangements with third parties to commercially exploit its capacity at the Sabine Pass LNG receiving terminal on commercially advantageous terms or at all.
In pursuing each aspect of our plan to commercially exploit Cheniere Marketing’s TUA capacity at the Sabine Pass LNG receiving terminal, we will encounter competition, including competition from major energy companies and other competitors with significantly greater resources.
Any or all of these factors, as well as risk factors described elsewhere and other risk factors that we may not be able to anticipate, control or mitigate, could have a material adverse effect on our ability to commercially exploit Cheniere Marketing’s TUA capacity at the Sabine Pass LNG receiving terminal, which in turn could materially and adversely affect the business, results of operations, financial condition, prospects and liquidity.
Index to Financial Statements We are in the early stages of developing our LNG and natural gas marketing business.
We have recently begun developing our LNG and natural gas marketing business. To date, the business has been unprofitable and has a limited operating history upon which to evaluate our business strategy or the future prospects of the business. Since inception, our LNG and natural gas marketing business has had net operating losses. The ability of our LNG and natural gas marketing business to generate revenues in the future will depend upon whether we can successfully develop and implement our business strategy and make the transition from a development stage business to an operating business. We may encounter many expenses, delays, problems and difficulties that we have not anticipated and for which we have not planned in developing and operating 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, timing, location, quality and credit risk associated with the marketing of LNG and natural gas, we use futures, swaps and option contracts traded or cleared on NYMEX and 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 operating history of, and limited capital resources and credit available to, our LNG and natural gas marketing business limit our ability to develop that business.
We have limited the amount of capital available to our LNG and natural gas marketing business. The business currently has limited access to third-party sources of financing. Other investment-grade marketing companies have greater financial, technical and marketing resources and access to LNG supply than we do. Our LNG and natural gas marketing business is in its early stages of development and may not generate sufficient revenues and cash flows to cover the significant fixed costs of the business. The limited capital and credit available to our LNG and natural gas marketing business, along with a lack of cash flows, may inhibit our ability to develop that 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.
Index to Financial Statements Risks Relating to Our LNG Businesses in General
Failure of imported LNG to be a competitive source of energy for North American markets could materially adversely affect our business, financial condition, results of operations and prospects.
The success of our LNG receiving terminal business, our natural gas pipeline business and our LNG and natural gas marketing business (collectively, our “LNG businesses”), is primarily dependent upon LNG being a competitive source of energy in North America.
In North America, due mainly to a historically abundant supply of natural gas, imported LNG has not historically been a major energy source. Our business plan is based, in part, on the belief that LNG can be produced and delivered at a lower cost than the cost to produce some domestic supplies of natural gas, or other alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas may be discovered in North America, which could further increase the available supply of natural gas and could result in natural gas being available at a lower cost than imported LNG. In addition to natural gas, LNG also competes in North America with other sources of energy, including coal, oil, nuclear, hydroelectric, wind and solar energy.
Other continents have a longer history of importing LNG and, due to their geographic proximity to LNG producers and limited pipeline access to natural gas supplies, may be willing and able to pay more for LNG, thereby reducing or eliminating the supply of LNG available in North American markets. Current and futures prices for natural gas in markets that compete with North America have been higher than prices for natural gas in North America, which has adversely affected the volume of LNG imports into North America. If LNG deliveries to North America continue to be constrained due to stronger demand from these competing markets, our ability and the ability of existing and prospective third-party TUA customers to import LNG into North America on a profitable basis may be adversely affected.
Political instability in foreign countries that have supplies of natural gas, or strained relations between such countries and the U.S., may also impede the willingness or ability of LNG suppliers and merchants in such countries to export LNG to the U.S. Furthermore, some foreign suppliers of LNG may have economic or other reasons to direct their LNG to non-U.S. markets or to competitors’ LNG receiving terminals in the U.S.
As a result of these and other factors, LNG may not be a competitive source of energy in North America. The failure of LNG to be a competitive supply alternative to domestic natural gas, oil and other alternatives could adversely affect our ability to enter into additional TUAs with customers and could also impede the ability to import LNG into North America on a commercial basis of us and our TUA customers, which could inhibit our growth and cause us operating losses. Any significant impediment to the ability to import LNG into the United States generally or to our LNG receiving terminals specifically could have a material adverse effect on us, on our third-party LNG receiving terminal customers, and on our LNG businesses, results of operations, financial condition and prospects.
Cyclical or other changes in the demand for LNG regasification capacity may adversely affect our LNG businesses and the performance of our TUA 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 importation capacity and available natural gas, principally due to the combined impact of several factors, including:
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additions to competitive regasification capacity in North America, Europe, Asia and other markets, which could divert LNG from our existing and proposed LNG receiving terminals;
•
insufficient LNG liquefaction capacity worldwide;
•
insufficient LNG tanker capacity;
Index to Financial Statements
•
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 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 LNG, natural gas or alternative energy sources, which may reduce the demand for imported LNG and/or natural gas;
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adverse relative demand for LNG in North America compared to other markets, which may decrease LNG imports into North America; and
•
cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.
These factors could materially adversely affect our ability, and the ability of current and prospective TUA customers, to procure supplies of LNG to be imported into North America and to procure customers for regasified LNG at economical prices, or at all.
Insufficient development of additional LNG liquefaction capacity worldwide could adversely affect 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.
Commercial development of an LNG liquefaction facility takes a number of years and requires substantial capital investment. Many factors could negatively affect continued development of LNG liquefaction facilities, including:
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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;
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decreases in the price of LNG and natural gas, which might decrease the expected returns relating to investments in LNG projects;
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the inability of project owners or operators to obtain governmental approvals to construct or operate LNG facilities;
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political unrest in exporting countries or local community resistance in such countries to the siting of LNG facilities due to safety, environmental or security concerns; and
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any significant explosion, spill or similar incident involving an LNG liquefaction facility or LNG carrier.
There may be shortages of LNG vessels worldwide, which could adversely affect 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 construction and delivery of LNG vessels requires 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 TUA customers because of:
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an inadequate number of shipyards constructing LNG vessels and a backlog of orders at these shipyards;
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political or economic disturbances in the countries where the vessels are being constructed;
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changes in governmental regulations or maritime self-regulatory organizations;
Index to Financial Statements
•
work stoppages or other labor disturbances at the shipyards;
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bankruptcy or other financial crisis of shipbuilders;
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quality or engineering problems;
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weather interference or a catastrophic event, such as a major earthquake, tsunami or fire; and
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shortages of or delays in the receipt of necessary construction materials.
Decreases in the demand for and price of natural gas could lead to reduced development of LNG projects worldwide, which could adversely affect 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 receiving terminals and LNG projects generally is based on assumptions about the future price of natural gas and the availability of imported LNG. 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 international 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 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.
Our LNG businesses face competition, including competing LNG receiving terminals and related pipelines from competitors with far greater resources.
Many competing companies have secured access to, or are pursuing development or acquisition of, LNG import infrastructure to serve the U.S. natural gas market. Some industry analysts have predicted substantial excess LNG receiving capacity in North America for at least several years based on terminals currently in operation or under construction. Competitors faced by our LNG businesses in the U.S. include major energy corporations (e.g., BG, BP, Chevron, ConocoPhillips and Dow Chemical). In addition, other competitors have developed or reopened additional LNG receiving terminals in Europe, Asia and other markets, which also compete with our existing and proposed LNG facilities. Almost all of these competitors have longer operating histories, more development experience, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources and access to LNG supply than we do. The superior resources that these competitors have available for deployment could allow them to compete successfully against our LNG businesses, which could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.
Terrorist attacks or military campaigns may adversely impact our LNG businesses.
A terrorist incident involving an LNG facility or LNG carrier may result in delays in, or cancellation of, construction of new LNG facilities, including our proposed LNG receiving terminals and related natural gas
Index to Financial Statements
pipelines, 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, which could increase our costs and decrease our cash flows, depending on the duration of the closure. Operations at our LNG receiving terminals 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.
Risks Relating to Our Business in General
Our initiatives to pursue downstream and upstream opportunities as part of our overall energy business strategy may not be successful and, even if successful, could expose us to greater and unanticipated risks.
We may not be successful in our efforts to pursue any or all of our downstream opportunities such as natural gas pipeline development or natural gas marketing, or in our efforts to pursue any or all of our upstream opportunities such as securing foreign LNG supply arrangements. If we are successful in pursuing one or more of these downstream or upstream opportunities, we will likely incur greater risks than we expect to incur in our LNG receiving terminal business, and some of those risks we will not be able to anticipate.
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 proposed LNG receiving terminals and pipelines, as well as the conduct of our oil and gas exploration and production business, are subject to 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 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 receiving terminals 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. CERCLA and similar 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 receiving terminal and pipeline, we could be liable for the costs of cleaning up hazardous substances released into the environment and for damage to natural resources.
Index to Financial Statements Existing environmental laws and regulations may be revised or reinterpreted or new laws and regulations may be adopted or become applicable to us. 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 our LNG receiving 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 our LNG receiving terminal through the Sabine Pass Channel, could cause additional expenditures, restrictions and delays in our business and to our planned 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 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 our proposed LNG receiving terminals 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 receiving 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 receiving terminal. Any increase in our operating costs could materially adversely affect our business, results of operations, financial condition 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 2009 will be dependent upon one asset, the Sabine Pass LNG receiving terminal. Due to our lack of asset and geographic diversification, an adverse development at the Sabine Pass LNG receiving terminal 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.
Some of our economic value is derived from our ownership of a minority interest in an entity over which we exercise no day-to-day control.
We own a 30% limited partner interest in Freeport LNG. Some of our value is attributable to this investment. In this report, we may use the words “our,” “we” or “us” in describing this investment or its assets and operations; however, we do not exercise control over Freeport LNG. The management team of Freeport LNG could make business decisions without our consent that could impair the economic value of our investment in Freeport LNG. Any such diminution in the value of our investment could have an adverse impact on our business, results of operations, financial condition and prospects.
Index to Financial Statements We may have to take actions that are disruptive to our business strategy to avoid registration under the Investment Company Act of 1940.
The Investment Company Act of 1940, or Investment Company Act, requires registration for companies that are engaged primarily in the business of investing, reinvesting, owning, holding or trading in securities. Registration as an investment company would subject us to restrictions that are inconsistent with our fundamental business strategy.
A company may be deemed to be an investment company if it owns investment securities with a value exceeding 40% of the value of its total assets (excluding government securities and cash items) on an unconsolidated basis, unless an exemption or safe harbor applies. Securities issued by companies other than majority-owned subsidiaries are generally counted as investment securities for purposes of the Investment Company Act. We own a minority equity interest in Freeport LNG, which could be counted as an investment security. We generally plan to invest our liquid assets in commercial paper or other assets that may be considered investment securities in order to achieve higher yields from our available funds than investments in government securities and money market or similar cash investments would provide. Based on our board of directors’ determination of the value of our subsidiaries, we estimate that less than 40% of our assets consist of investment securities. However, in the event we acquire additional investment securities in the future, or if the value of our interests in companies that we do not control were to increase relative to the value of our controlled subsidiaries, we might be required to invest some portion of our liquid assets in government securities or cash items that yield lower returns than our proposed investments, or, in the alternative, we might be required to divest some of our non-controlled business interests, or take other action, in order to avoid being classified as an investment company.
We may engage in operations or make substantial commitments and investments 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 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 risks of:
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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;
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changing laws and policies affecting trade, taxation and investment;
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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 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 financial statements.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
Index to Financial Statements 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, 2008, 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. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
Index to Financial Statements PART II
ITEM 5.
ITEM 5. MARKET PRICE FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock has traded on the NYSE Alternext US (formerly the American Stock Exchange) 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 Alternext US, for each quarter during 2007 and 2008.
As of February 17, 2009, we had 52 million shares of common stock outstanding held by approximately 1,021 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 three months ended December 31, 2008, we purchased 143,220 shares of restricted stock at an average cash price of $2.86 per share related to restricted stock vested in December 2008 that was returned to the Company by employees to cover taxes.
Index to Financial Statements 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 ending December 31, 2008. The graph was constructed on the assumption that $100 was invested in our common stock, the S&P Oil and Gas Exploration and Production Index and the Russell 2000 Index on December 31, 2003 and that any dividends were fully reinvested.
The “Total Stockholder Return” information contained in this Item 5 of this Annual Report on Form 10-K is not deemed to be “soliciting material” or to be “filed” with the SEC or subject to Regulation 14A or 14C under the Exchange Act or to the liabilities of Section 18 of the Exchange Act, and will not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent we specifically incorporate it by reference into such a filing.
Index to Financial Statements 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 Notes thereto included elsewhere in this report.
Index to Financial Statements
(1) 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 receiving terminal and Creole Trail Pipeline and the seeking of alternative arrangements for our time charter interest in two LNG vessels (See Note 4-“Restructuring Charges” of our Notes to Consolidated Financial Statements).
(2) In 2005, our investment in Gryphon Exploration Company was sold to Woodside Energy (USA), generating net cash proceeds and a gain to Cheniere of $20.2 million.
(3) Amount in 2008 relates to losses on the termination of the Bridge Loan in August 2008. Amounts in 2006 primarily relate to losses on the termination of a Sabine Pass LNG credit facility and term loan in November 2006. See Note 18-“Long-Term Debt and Long-Term Debt-Related Parties” of our Notes to Consolidated Financial Statements.
(4) Amounts in 2006 primarily relate to losses on the termination of hedge transactions related to the termination of a Sabine Pass LNG credit facility and term loan in November 2006.
(5) Net loss per share and weighted average shares outstanding have been restated to reflect a two-for-one stock split that occurred on April 22, 2005.
(6) Amounts reported for the years ended December 31, 2005 and 2004 have been adjusted to reflect the change in our method of accounting for investments in oil and gas properties from the full cost method to the successful efforts method.
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 Item 8, “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:
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Overview of Business
•
Overview of 2008 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
•
Recently Issued Accounting Standards Not Yet Adopted
Overview of Business
We operate three segments: LNG receiving terminal business, natural gas pipeline business, and LNG and natural gas marketing business. To a limited extent, we continue to be engaged in oil and natural gas exploration, development and exploitation activities in the Gulf of Mexico.
LNG Receiving Terminal Business
We have focused our LNG receiving terminal development efforts on the following three projects: the Sabine Pass LNG receiving terminal in western Cameron Parish, Louisiana on the Sabine Pass Channel; the
Index to Financial Statements
Corpus Christi LNG receiving terminal near Corpus Christi, Texas; and the Creole Trail LNG receiving terminal at the mouth of the Calcasieu Channel in central Cameron Parish, Louisiana. In addition, we own a 30% interest in Freeport LNG Development, L.P. (“Freeport LNG”) which has constructed an LNG receiving terminal located on Quintana Island near Freeport, Texas.
Our ownership interest in the Sabine Pass LNG receiving terminal is held through Cheniere Energy Partners, L.P. (“Cheniere Partners”), a Delaware limited partnership, in which we hold an approximate 90.6% interest as a result of the completion of a public offering of common units in Cheniere Partners. Cheniere Partners owns a 100% interest in Sabine Pass LNG, L.P. (“Sabine Pass LNG”), which is constructing the Sabine Pass LNG receiving terminal. We currently own 100% interests in the proposed Corpus Christi and Creole Trail LNG receiving terminals. The three LNG receiving terminals under development by us have an aggregate designed regasification capacity of approximately 10.1 Bcf/d, subject to expansion.
Construction of the Sabine Pass LNG receiving terminal commenced in March 2005, and we achieved commercial operability in September 2008 with initial sendout capacity of approximately 2.6 Bcf/d and storage capacity of approximately 10.1 Bcf. We anticipate achieving full operability of the Sabine Pass LNG receiving terminal with a total sendout capacity of approximately 4.0 Bcf/d and total storage capacity of approximately 16.8 Bcf during the third quarter of 2009. Sabine Pass LNG has entered into long-term terminal use agreements (“TUAs”) with Total LNG USA, Inc. (“Total”), Chevron U.S.A., Inc. (“Chevron”) and Cheniere Marketing, LLC (“Cheniere Marketing”), our wholly-owned subsidiary formerly known as Cheniere Marketing, Inc., for the entire 4.0 Bcf/d of regasification capacity that will be available at the Sabine Pass LNG receiving terminal upon completion of construction.
We will contemplate making final investment decisions to complete construction of the Corpus Christi LNG receiving terminal and to commence construction of the Creole Trail LNG receiving terminal upon, among other things, entering into acceptable commercial and financing arrangements.
Natural Gas Pipeline Business
We are developing natural gas pipelines to provide access to North American natural gas markets from our LNG receiving terminals, and to serve growing natural gas markets with diverse new sources of natural gas supplies. We have focused our natural gas pipeline development efforts on the following three projects: the Creole Trail Pipeline originating at the Sabine Pass LNG receiving terminal to points of interconnection with multiple interstate and intrastate natural gas pipelines throughout southern Louisiana; the Corpus Christi Pipeline originating at the Corpus Christi LNG receiving terminal to points of interconnection with interstate and intrastate natural gas pipelines in South Texas; and the Cheniere Southern Trail Pipeline originating in southern Louisiana to a point of interconnection with the Florida Gas Transmission Pipeline in western Florida. We have also purchased 100% interest in the Frontera Pipeline project, a combined transportation and storage project designed to serve industrial and power generation customers in northeastern Mexico (the “Burgos Hub Project”).
As of December 31, 2008, Phase 1 of the Creole Trail Pipeline, consisting of 94 miles of natural gas pipeline, had been constructed and placed into commercial operation. In conjunction with Phase 1 of the Creole Trail Pipeline, six delivery meter stations were commissioned providing access to eight major interstate and intrastate natural gas pipeline systems.
If we decide to complete construction of the Corpus Christi LNG receiving terminal, we intend to develop the Corpus Christi Pipeline when, among other things, we have entered into acceptable commercial and acceptable financing arrangements.
The Cheniere Southern Trail Pipeline project would interconnect with multiple takeaway pipelines from LNG receiving terminals in southwestern Louisiana and a LNG receiving terminal being developed in Mississippi. The Cheniere Southern Trail Pipeline may also interconnect with multiple onshore pipelines serving conventional basins in the Gulf of Mexico and with new developments transporting natural gas from the
Index to Financial Statements
unconventional shale plays in Texas and Arkansas. The Cheniere Southern Trail Pipeline could supply Florida with natural gas needed to supply the growth we anticipate in natural gas-fired generation capacity in the state over the next ten to fifteen years. This pipeline would provide LNG suppliers with access to new natural gas markets, while providing alternative access to conventional gas supplies, to improve gas supply security for Florida and the remainder of the Southeastern U.S. The Cheniere Southern Trail Pipeline will be developed once we have entered into acceptable commercial and acceptable financing arrangements.
The Burgos Hub Project involves the construction of an integrated pipeline project that would traverse the United States and Mexico border and includes a related subterranean storage facility in Mexico. We will contemplate making a final investment decision in the Burgos Hub Project upon, among other things, receiving all required authorizations to construct and operate the pipeline and storage facility, and entering into acceptable commercial and acceptable financing arrangements.
LNG and Natural Gas Marketing Business
Our LNG and natural gas marketing business segment is focused on producing long-term, recurring cash flow utilizing its reserved 2.0 Bcf/d of regasification capacity at the Sabine Pass LNG receiving terminal. 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 Marketing.
To help achieve these goals, we have entered into domestic marketing agreements with various counterparties for the sale of LNG. These agreements provide a framework under which Cheniere Marketing may offer to sell to a counterparty all or a portion of the LNG from each LNG cargo it acquires on delivery to the Sabine Pass LNG receiving terminal, and under which the counterparty will utilize a portion of Cheniere Marketing’s TUA capacity for storage and regasification services related to the portion of the LNG cargo that the counterparty purchases.
Oil and Natural Gas Exploration, Development and Exploitation Activities
Although our focus is primarily on the development of LNG-related businesses, we continue to be involved to a limited extent in oil and gas exploration, development and exploitation activities in the shallow waters of the Gulf of Mexico. This business has historically required, and will continue to require, an insignificant amount of cash to fund its operations.
Overview of 2008 Events
Our significant accomplishments during 2008, some of which may also impact future years, include the following:
•
in February 2008, we announced that we were exploring strategic options for Cheniere to enhance stockholder value, including options to optimize the value of the Sabine Pass LNG receiving terminal and the regasification capacity at the terminal held by Cheniere Marketing under a long-term TUA;
•
in April 2008, we commenced 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 receiving terminal and Creole Trail Pipeline and the seeking of alternative arrangements for our time charter interests in two LNG vessels. The cost savings program involved reducing our personnel company-wide by approximately 43%. We recognized losses of $78.7 million from this cost savings program, including the impact of cancelling our LNG vessel charter agreements, with substantially all of these losses having no material effect on our working capital in 2008. As of December 31, 2008, we estimate that we will recognize an additional $0.9 million of such losses in the future;
Index to Financial Statements
•
in April 2008, construction of Phase 1 of the Creole Trail Pipeline (consisting of 94 miles of natural gas pipeline) was completed and the pipeline was placed into commercial operation;
•
in May 2008, we entered into a $95.0 million, 18-month bridge loan (the “Bridge Loan”) and received approximately $82.3 million of net proceeds to be held as unrestricted cash and cash equivalents and to be used for general corporate purposes and pipeline capital expenditures. The purpose of the Bridge Loan was to provide incremental funding and liquidity until we entered into a strategic transaction, obtained sufficient revenues from a significant number of imported LNG cargos or consummated an alternative financing transaction;
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in June 2008, Freeport LNG achieved commercial operability, and it began receiving TUA payments from its customers in the second half of 2008;
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in August 2008, Cheniere Common Units Holding, LLC, our wholly-owned subsidiary, closed a $250.0 million senior secured convertible term loan agreement (“2008 Convertible Loans”). Proceeds were used to: repay the Bridge Loan obtained in May 2008; fund a reserve account for payments under Cheniere Marketing’s TUA with Sabine Pass LNG; pay expenses incurred in connection with the 2008 Convertible Loans and the consideration of other potential strategic alternatives; and fund working capital and general corporate needs of Cheniere and its subsidiaries;
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in September 2008, Sabine Pass LNG received $145.0 million, net of discount, from the issuance of an additional $183.5 million of Sabine Pass LNG’s 7 1/2% Senior Secured Notes due 2016 (“2016 Notes”) pursuant to the existing indenture, dated as of November 9, 2006 (the “Sabine Pass Indenture”), under which Sabine Pass LNG had previously issued $1,482.0 million in aggregate principal amount of 2016 Senior Notes and $550.0 million in aggregate principal amount of 7 1/4% Senior Secured Notes due 2013 (“2013 Notes” and collectively with the 2016 Notes, the “Senior Notes”);
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in September 2008, Cheniere Marketing began making its TUA payments to Sabine Pass LNG; and
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in September 2008, the initial 2.6 Bcf/d of sendout capacity and 10.1 Bcf of storage capacity at the Sabine Pass LNG receiving terminal was completed and achieved commercial operability.
We believe that these 2008 activities will provide us with sufficient liquidity to operate our business and pursue our business strategies over the next several years.
Liquidity and Capital Resources
Overview
As of December 31, 2008, we had unrestricted cash and cash equivalents of $102.2 million. In addition, we had restricted cash and cash equivalents of $440.0 million and U.S. Treasury securities of $20.8 million, which were designated for the following purposes: $71.1 million for construction costs of the Sabine Pass LNG receiving terminal; $194.8 million for Sabine Pass LNG’s working capital; $96.1 million for interest payments related to the Senior Notes described below; $62.8 million for Cheniere Marketing TUA payments; $32.8 million for cash distributions by Cheniere Partners; and $3.3 million in other restricted cash and cash equivalents.
As described below in further detail by business segment and corporate and other activities, we believe that we have sufficient cash and cash equivalents to operate our business and pursue our business strategies over the next several years.
Index to Financial Statements LNG Receiving Terminal Business
Cheniere Partners
Our ownership interest in the Sabine Pass LNG receiving terminal is held through Cheniere Partners. In 2007, Cheniere Partners completed a public offering of 15,525,000 Cheniere Partners common units. As a result of this public offering, our combined general partner and limited partner ownership interests in Cheniere Partners was reduced to approximately 90.6%. Cheniere Partners owns a 100% interest in Sabine Pass LNG, which is constructing and operating the Sabine Pass LNG receiving terminal.
For each calendar year, Cheniere Partners is expected to make distributions of $1.70 per unit on all outstanding common units, subordinated units and related distributions to its general partner. We anticipate receiving $18.5 million per year out of the total $44.9 million of annual common unit distributions. We anticipate receiving $235.8 million per year from distributions to the subordinated unitholders and general partner, of which we own 100%.
Cheniere Partners relies on the receipt of operating revenues from Sabine Pass LNG’s TUAs to fund quarterly cash distributions to us and other unitholders. Sabine Pass LNG is not permitted under the Sabine Pass Indenture to make cash distributions to Cheniere Partners if it does not satisfy a fixed charge coverage ratio test of 2:1, calculated as required in the Sabine Pass Indenture. If the coverage test is not met, we may not receive distributions. As of December 31, 2008, the fixed charge coverage ratio was met and the first distribution was made from Sabine Pass LNG to Cheniere Partners; Cheniere Partners utilized the cash received from Sabine Pass LNG to pay expenses and make distributions to us and its other unitholders.
A distribution reserve account was established from proceeds of Cheniere Partners’ initial public offering to pay distributions to the common unitholders and general partner until Cheniere Partners is able to sustain distributions from unrestricted cash, at which time the funds remaining in the account are expected to be returned to us. As of February 15, 2009, there was $32.8 million in the distribution reserve account, which is adequate to fund distributions to the common unitholders and general partner made with respect to each calendar quarter through September 30, 2009. Sabine Pass LNG began making distributions from unrestricted cash in February 2009 and expects to continue making its distributions from its cash balances. We expect that approximately $35 million will be remaining in the distribution reserve account after accounting for interest earned in the account after February 15, 2009, and that approximately $35 million of remaining funds will be distributed to us in August 2009 pursuant to the terms of Cheniere Partners’ partnership agreement.
We also expect to receive approximately $19 million of annual management and service fees from Sabine Pass LNG and Cheniere Partners pursuant to existing agreements.
Sabine Pass LNG Receiving Terminal
Our estimated aggregate construction, commissioning and operating cost budget through the achievement of full operability of the Sabine Pass LNG receiving terminal (with approximately 4.0 Bcf/d of total sendout capacity and five LNG storage tanks with approximately 16.8 Bcf of aggregate storage capacity) is approximately $1,559 million, excluding financing costs. Of this amount, approximately $1,416 million of construction and commissioning costs had been incurred as of December 31, 2008. Our remaining construction, commissioning and operating costs are anticipated to be funded from working capital and the $71.1 million of restricted cash and cash equivalents designated for construction. In September 2008, Hurricane Ike and related storm activity, such as windstorms, storm surges and floods, struck the Texas and Louisiana coasts. We experienced minor damage at the Sabine Pass LNG receiving terminal with most of the damage impacting equipment and facilities associated with the 1.4 Bcf/d of sendout capacity and 6.7 Bcf of storage capacity still under construction. Impact to operations and the equipment and facilities associated with the initial 2.6 Bcf/d of sendout capacity and 10.1 Bcf of storage capacity was minimal. We continue to expect to complete construction of the remaining 1.4 Bcf/d of sendout capacity and 6.7 Bcf of storage capacity in the third quarter of 2009.
Index to Financial Statements
Estimated costs to repair damage caused by Hurricane Ike are approximately $32 million, of which we believe approximately $22 million will be recoverable from insurance proceeds and other sources. The estimated costs to repair this damage have been factored into the budget estimate above.
The entire 4.0 Bcf/d of regasification capacity that will be available at the Sabine Pass LNG receiving terminal upon completion of construction has been fully reserved under three long-term TUAs, under which Sabine Pass LNG’s customers are required to pay fixed monthly fees, whether or not they use the terminal. Because we achieved commercial operability of the Sabine Pass LNG receiving terminal in September 2008, capacity reservation fee TUA payments will begin to be made by our third-party customers as follows:
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Total has reserved approximately 1.0 Bcf/d of regasification capacity and has agreed to make monthly capacity payments to Sabine Pass LNG aggregating approximately $125 million per year for 20 years commencing April 1, 2009. Total, S.A. has guaranteed Total’s obligations under its TUA up to $2.5 billion, subject to certain exceptions; and
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Chevron has reserved approximately 1.0 Bcf/d of regasification capacity and has agreed to make monthly capacity payments to Sabine Pass LNG aggregating approximately $125 million per year for 20 years commencing not later than July 1, 2009. Chevron Corporation has guaranteed Chevron’s obligations under its TUA up to 80% of the fees payable by Chevron.
In addition, Cheniere Marketing has reserved the remaining 2.0 Bcf/d of regasification capacity, and is entitled to use any capacity not utilized by Total and Chevron. In September 2008, Cheniere Marketing made a capacity reservation fee payment of $15.0 million for October, November and December 2008. In December 2008, Cheniere Marketing made a capacity reservation fee payment of $62.7 million for the first three months of 2009. Cheniere Marketing is required to make monthly capacity payments aggregating approximately $250 million per year for the period from January 1, 2009, through at least the third quarter of 2028. Cheniere has guaranteed Cheniere Marketing’s obligations under its TUA.
Under each of these TUAs, Sabine Pass LNG is also entitled to retain 2% of the LNG delivered for the customer’s account, which Sabine Pass LNG will use primarily as fuel for revaporation and self-generated power at the Sabine Pass LNG receiving terminal.
Each of Total and Chevron has paid us $20.0 million in nonrefundable advance capacity reservation fees, which will be amortized over a 10-year period as a reduction of each customer’s regasification capacity fees payable under its TUA.
Other LNG Receiving Terminals
We have a 30% limited partner interest in Freeport LNG. In March 2008 and May 2008, we received cash call notices from Freeport LNG requesting that we provide further financial support due to higher than expected commissioning and performance testing costs. During 2008, we funded the cash calls and have recorded $4.8 million of additional losses in Freeport LNG. In October 2008, Freeport LNG made its first distribution of $4.8 million to us. We expect to continue to receive distributions from Freeport LNG as they are approved by Freeport LNG’s board of directors.
We will contemplate making final investment decisions to complete construction of our Corpus Christi LNG receiving terminal project and to commence construction of our Creole Trail LNG receiving terminal project upon, among other things, entering into acceptable commercial arrangements and entering into acceptable financing arrangements for the applicable project. We do not expect to spend significant funds on these projects until we have entered into acceptable commercial arrangements and acceptable financing arrangements.
Index to Financial Statements Natural Gas Pipeline Business
As of December 31, 2008, Phase 1 of the Creole Trail Pipeline, consisting of 94 miles of natural gas pipeline, had been constructed and placed into commercial operations. Expenditures incurred for the construction of the Creole Trail Pipeline through December 31, 2008 were approximately $553 million, including accrued liabilities. We believe we have sufficient cash and cash equivalents to operate our Creole Trail Pipeline for the next several years.
We will contemplate making a final investment decision to construct Phase 2 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 Burgos Hub), to the extent not already obtained, and entering into acceptable commercial arrangements and acceptable financing arrangements for the applicable project.
LNG and Natural Gas Marketing Business
In April 2008, we commenced 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 receiving terminal and Creole Trail Pipeline and the seeking of alternative arrangements for our time charter interests in two LNG vessels. We have unwound, terminated or assigned our commitments under our domestic natural gas agreements on terms we believe to be acceptable and have cancelled both of our LNG vessel charters.
We deposited $135.0 million in a TUA reserve account utilizing a portion of the 2008 Convertible Loans that were closed in August 2008. Pursuant to the 2008 Convertible Loans, all funds in the TUA reserve account in excess of three months of Cheniere Marketing’s TUA payments can be released to us as unrestricted cash and cash equivalents after we have received three consecutive monthly payments from both Total and Chevron under their respective TUAs, which we believe will occur in August 2009. We believe that we will obtain approximately $66 million from the TUA reserve account as unrestricted cash and cash equivalents in August 2009.
Cheniere Marketing will utilize funds in the TUA reserve account, distributions from Cheniere Partners and operating cash flows to pay its TUA obligation.
Corporate and Other Activities
We are required to maintain a certain level of corporate general and administrative functions to serve our business activities described above. We believe that we have sufficient cash and cash equivalents to fund these business activities over the next several years.
Although our focus is primarily on the development of LNG-related businesses, we continue to be involved to a limited extent in oil and gas exploration, development and exploitation activities in the shallow waters of the Gulf of Mexico. We do not anticipate significant cash expenditures related to this activity and expect cash inflows from oil and natural gas production to gradually decrease as our reserves are produced.
Index to Financial Statements Sources and Uses of Cash
The following table summarizes (in thousands) the sources and uses of our cash and cash equivalents for 2008, 2007 and 2006. 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.
Use of restricted cash and cash equivalents
Under the Sabine Pass Indenture, a portion of the proceeds from the Senior Notes was initially required to be used for scheduled interest payments through May 2009 and to fund the cost to complete construction of the Sabine Pass LNG receiving terminal. Due to these restrictions imposed by the Sabine Pass Indenture, the proceeds from the Senior Notes are not presented as cash and cash equivalents. When proceeds from the Senior Notes that have been designated as restricted cash and cash equivalents are used, they are presented as a source of cash and cash equivalents. In 2008 and 2007, the $465.3 million and $527.0 million, respectively, of restricted cash and cash equivalents were used primarily to pay for construction activities at the Sabine Pass LNG receiving terminal.
Index to Financial Statements Proceeds from debt issuance and proceeds from debt issuance-related parties
Our proceeds from the issuance of debt and from the issuance of debt-related parties were $490.0 million, $400.0 million and $2,415.4 million in 2008, 2007 and 2006, respectively. During 2008, we received $95.0 million from borrowings under the Bridge Loan, $250.0 million from borrowings under the 2008 Convertible Loans (considered related party), and $145.0 million, net of discount, from the additional issuance of the 2016 Notes (a portion of which is considered related party borrowings). During 2007, we received $400.0 million from borrowings under the 2007 Term Loan, which was used primarily to repurchase shares of our common stock under the call option acquired in the issuer call spread purchased by us in connection with the issuance of the Convertible Senior Unsecured Notes. During 2006, we received $2,032.0 million in proceeds from the issuance of the Senior Notes and $383.4 million in borrowings under the amended Sabine Pass credit facility.
Use of Restricted U.S. Treasury securities
As mentioned above, through the Cheniere Partners Offering, Cheniere Partners received $98.4 million in net proceeds from the issuance of common units to the public. Cheniere Partners used all of the net proceeds to purchase U.S. Treasury securities to fund a distribution reserve for payment of initial quarterly distributions until Cheniere Partners is able to sustain funding of distributions to its unitholders from unrestricted cash, at which time any remaining cash in the distribution reserve is expected to be returned to us.
Proceeds from sale of common units to minority owners in partnership
In connection with the Cheniere Partners Offering in 2007, we sold to the public a portion of the Cheniere Partners common units held by us through a subsidiary, 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 us. These net proceeds are being used for corporate and general purposes.
Proceeds from issuance of common units in partnership
In connection with the Cheniere Partners Offering in 2007, Cheniere Partners received $98.4 million in net proceeds for the issuance of common units to the public. Cheniere Partners used all of the net proceeds to purchase U.S. Treasury securities to fund a distribution reserve for payment of initial quarterly distributions of $0.425 per common unit, as well as related quarterly distributions to its general partner through the quarterly distributions until Cheniere Partners is able to sustain funding of distributions to its unitholders from unrestricted cash, at which time any remaining cash in the distribution reserve is expected to be returned to us.
LNG receiving terminal and pipeline construction-in-process, net
Capital expenditures for our LNG receiving terminals and pipeline projects were $583.9 million, $788.5 million and $440.4 million in 2008, 2007 and 2006, respectively. The 26% decrease in 2008 resulted primarily from the winding down and completion of the construction of the initial phases of the Sabine Pass LNG receiving terminal and the Creole Trail Pipeline. The 79% increase in 2007 resulted primarily from our continued construction expenditures on the Sabine Pass LNG receiving terminal, which commenced construction in the first quarter of 2005, and the Creole Trail Pipeline, which commenced initial construction in the second quarter of 2007.
Investment in restricted cash and cash equivalents
Investment in restricted cash and cash equivalents was $248.8 million, zero and $1,070.7 million in 2008, 2007, and 2006, respectively. Investments in restricted cash and cash equivalents are cash and cash equivalents that have been legally restricted to be used for a specific purpose. During 2008, we received $250.0 million from borrowings under the 2008 Convertible Loans and $145.0 million, net of discount, from the additional issuance of the 2016 Notes. Proceeds received from these borrowings were used to fund reserve accounts of $248.8
Index to Financial Statements
million, which we classified as restricted cash and cash equivalents. During 2006, the proceeds from the issuance of the Senior Notes were contractually restricted to be used for the construction of our Sabine Pass LNG receiving terminal and for interest payments on the Senior Notes. Due to the contractual constrictions we classified $1,070.7 million as restricted cash and cash equivalents.
Operating cash flow
Net cash used in operations was $142.1 million, $84.3 million and $80.4 million in 2008, 2007 and 2006, respectively. Net cash used in operations in 2006 through 2008 related primarily to the continued development and construction of the Sabine Pass LNG receiving terminal and related activities, including increased employee support costs.
Repayment of debt
In 2008, we repaid borrowings under the Bridge Loan with a portion of the proceeds obtained from the 2008 Convertible Loans. In 2006, we repaid borrowings under the amended Sabine Pass credit facility and Term Loan with a portion of the proceeds obtained from the issuance of the Senior Notes.
Debt issuance costs
Our debt issuance costs were $34.5 million, $9.8 million and $43.8 million in 2008, 2007 and 2006, respectively. The debt issuance costs in 2008 related to the additional issuance of 2016 Notes, the 2008 Convertible Loans and the Bridge Loan. The debt issuance costs in 2007 were primarily related to the 2007 Term Loan. Debt issuance costs in 2006 were primarily related to the amended Sabine Pass credit facility and the Senior Notes.
Distributions to minority interest
During 2008 and 2007, Cheniere Partners distributed $26.4 million and $13.6 million, respectively, to its non-affiliated common unitholders.
Advances under long-term contracts, net of transfer to construction-in-process
We have entered into certain contracts and purchase agreements related to the construction of our Sabine Pass LNG receiving terminal that require us to make payments to fund costs that will be incurred or equipment that will be received in the future. Advances made under long-term contracts on purchase commitments are carried at face value and transferred to property, plant, and equipment as the costs are incurred or equipment is received.
Purchase of treasury shares
Concurrent with the issuance of the Convertible Senior Unsecured Notes, we also entered into hedge transactions in the form of an issuer call spread. During 2007, we exercised the call spread and purchased 9.2 million shares of our common stock for an aggregate purchase price of $325.0 million.
Purchases of intangible and fixed assets, net of sales
Purchases of fixed assets were $2.9 million, $41.7 million and $10.5 million in 2008, 2007 and 2006, respectively. The decrease in 2008 is primarily a result of a decrease in the purchase of intangible and fixed assets due to the winding down of construction activities at the Sabine Pass LNG receiving terminal and Creole Trail Pipeline. The increase in fixed assets from 2006 to 2007 resulted primarily from the expansion of our business to support the Sabine Pass LNG receiving terminal, Creole Trail Pipeline and our natural gas and LNG marketing business.
Index to Financial Statements Debt Agreements
Convertible Senior Unsecured Notes
In July 2005, we consummated a private offering of $325.0 million aggregate principal amount of Convertible Senior Unsecured Notes due 2012 to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended (the “Securities Act”). The notes bear interest at a rate of 2.25% per year. Interest on the Convertible Senior Unsecured Notes is payable semi-annually in arrears February 1 and August 1 of each year. The notes are convertible at any time into our common stock under certain circumstances at an initial conversion rate of 28.2326 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, 2008, no holders had elected to convert their notes. 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 Sabine Pass Indenture governing the notes contains customary reporting requirements.
Sabine Pass LNG Senior Notes
Sabine Pass LNG has issued an aggregate principal amount of $2,215.5 million of Senior Notes consisting of $550.0 million of 7 1/4% Senior Secured Notes due 2013 and $1,665.5 million of 7 1 /2% Senior Secured Notes due 2016. 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. Under the Sabine Pass Indenture governing the Senior Notes, 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. In addition, 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 will be permitted only after satisfaction of the foregoing funding requirements, after satisfying a fixed charge coverage ratio test of 2:1 and after satisfying other conditions specified in the Sabine Pass Indenture.
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 9.75% 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, September 30, September 30 and December 31 of each year. The 2007 Term Loan will mature on May 31, 2012. The net proceeds from the 2007 Term Loan were $391.7 million and are being used for general corporate purposes, including the repurchase, completed in July 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. The 2007 Term Loan is secured by a pledge of our 135,383,831 subordinated units in Cheniere Partners and our equity interests in the entities that own our 30% interest in Freeport LNG.
2008 Convertible Loans
In August 2008, we entered into a credit agreement pursuant to which we obtained $250.0 million in convertible term loans (“2008 Convertible Loans”). The 2008 Convertible Loans will mature in 2018, but the lenders can require prepayment of the loans for thirty days following August 15, 2011, 2013 and 2015, and upon a change of control. The 2008 Convertible 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
Index to Financial Statements
semi-annually on the last business day of January and July. At our option, until August 15, 2011, accrued interest may be added to the principal on each semi-annual interest date. The aggregate amount of all accrued interest to August 15, 2011 will be payable upon the maturity date. The 2008 Convertible Loans are secured by Cheniere’s rights and fees payable under management services agreements with Sabine Pass LNG and Cheniere Partners, by Cheniere’s common units in Cheniere Partners, by the equity and non-real property assets of Cheniere’s pipeline entities, by the equity of various other subsidiaries and certain other assets and subsidiary guarantees. The principal amount of $250.0 million may be exchanged for newly-created Series B Convertible Preferred Stock, par value $0.0001 per share (“Series B Preferred Stock”), with voting rights limited to the equivalent of 10,125,000 shares of common stock. The exchange ratio is one share of Series B Preferred Stock for each $5,000 of outstanding borrowings, subject to adjustment. The exchange ratio will be adjusted in the event we make certain distributions of cash, shares or property on our shares of common stock. The aggregate preferred stock is exchangeable into 50 million shares of common stock at a price of $5.00 per share pursuant to a broadly syndicated offering. We are required to file a registration statement to register the Series B Preferred Stock upon demand by the majority of the holders of the Series B Preferred Stock. Such holders also have the right to demand registration of the shares of common stock into which the Series B Preferred Stock is convertible. No portion of any accrued interest is eligible for conversion into Series B Preferred Stock. We placed $135.0 million of the borrowings under the 2008 Convertible Loans into a TUA reserve account to pay the reservation fee and operating fee as defined under Cheniere Marketing’s TUA. We utilized $95.0 million of the borrowings under the 2008 Convertible Loans to repay the Bridge Loan. The remaining borrowings were utilized to pay for interest on the Bridge Loan, to pay expenses incurred in connection with the issuance of the 2008 Convertible Loans and consideration of other strategic alternatives and to fund working capital and general corporate needs of Cheniere and its subsidiaries.
One of the lenders is Scorpion Capital Partners LP (“Scorpion”), an affiliate of one of the Company’s directors. Scorpion’s portion of the 2008 Convertible Loans was $8.5 million and Scorpion did not receive any fees in connection with making the 2008 Convertible Loans.
As long as the 2008 Convertible Loans are exchangeable for shares of Series B Preferred Stock or shares of Series B Preferred Stock remain outstanding, the holders of a majority of the 2008 Convertible Loans and Series B Preferred Stock, acting together, shall have the right to nominate two individuals to the Company’s Board of Directors, and together with the Board of Directors, a third nominee, who shall be an independent director.
Issuances of Common Stock
During 2008, 2007 and 2006, we raised $0.5 million, $3.2 million, and $2.0 million, respectively, net of offering costs, from the exercise of stock options and the exchange or exercise of warrants.
During 2008, a total of 145,000 shares of our common stock were issued pursuant to the exercise of stock options, resulting in net cash proceeds of $0.5 million. In addition, in January 2008, 480,000 shares having three-year graded vesting were issued to our employees in the form of non-vested stock awards and 537,000 shares were issued to our executive officers in the form of vested stock awards related to our performance in 2007. In May 2008 and June 2008, as a part of the short-term and long-term retention plans approved by the Compensation Committee, 374,000 shares vesting on December 1, 2008 and 1,525,000 shares having a three-year graded vesting beginning December 31, 2008 were issued to our employees and a consultant in the form of non-vested stock awards. In December 2008, 1,703,000 shares of non-vested stock having a three year graded vesting were issued to employees as an incentive award. During 2008, an additional 272,000 shares having a one-year graded vesting were issued to our directors and 26,000 shares of non-vested stock having three- or four-year graded vestings were issued to employees.
During 2007, we issued a total of 1,717,000 shares of our common stock. A total of 416,000 shares of our common stock were issued pursuant to the exercise of stock options, resulting in net cash proceeds of
Index to Financial Statements
$3.2 million. In addition, 273,000 shares were issued in satisfaction of cashless exercises of options to purchase 316,000 shares of common stock. In January 2007, we issued 630,000 shares having three-year graded vesting to our employees and executive officers in the form of non-vested stock awards related to our performance in 2006. In May 2007, we issued 31,000 shares having a one-year graded vesting to our directors. In June 2007 and November 2007, we issued 150,000 shares as retention grants to certain employees vesting 50% on December 1, 2008, 30% on December 1, 2009, and 20% on June 1, 2010. In 2007, we issued an additional 250,000 shares of non-vested stock having three or four-year graded vestings primarily to new employees.
During 2007, we purchased 9,176,000 shares of our common stock for a cash price of $35.42 per share under the call options acquired in the issuer call spread purchased by us in connection with the issuance of the Convertible Senior Unsecured Notes. As of December 31, 2007, these shares had not been cancelled and remained as treasury stock on our Consolidated Balance Sheet. The treasury shares were cancelled during 2008.
During 2006, we issued a total of 711,000 shares of our common stock. A total of 310,000 shares of our common stock were issued pursuant to the exercise of stock options, resulting in net cash proceeds of $2.0 million. In addition, 77,000 shares were issued in satisfaction of cashless exercises of options to purchase 98,000 shares of our common stock. A total of 79,000 shares were issued in 2006 to executive officers in the form of non-vested restricted stock awards related to our performance in 2005, and we issued 241,000 shares of non-vested restricted stock to new employees. We paid federal payroll withholding taxes of $1.0 million in exchange for 26,000 shares of our common stock, which related to common stock previously awarded to officers that vested during 2006. These shares were initially recorded as treasury shares, at cost, but were subsequently retired. In December 2006, 30,000 shares were issued to outside directors in the form of non-vested (restricted) stock awards related to their services provided in 2006.
Contractual Obligations
We are committed to making cash payments in the future on certain of our contracts. Below is a schedule of the future payments that we are obligated to make based on agreements in place as of December 31, 2008 (in thousands).
(1) A discussion of these obligations can be found at Note 18 of our Notes to Consolidated Financial Statements.
(2) A discussion of these obligations can be found at Note 8 of our Notes to Consolidated Financial Statements.
(3) Minimum lease payments have not been reduced by a minimum sublease rental of $13.7 million due in the future under noncancelable subleases.
(4) A discussion of these obligations can be found at Note 23 of our Notes to Consolidated Financial Statements.
(5) Includes obligations for cooperative endeavor agreements, telecommunication services and software licensing.
Index to Financial Statements 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 and U.S. Treasury securities totaled approximately $460.9 million at December 31, 2008. For more information, see Note 7-“Restricted Cash and Cash Equivalents and U.S. Treasury Securities” of our Notes to Consolidated Financial Statements.
Results of Operations
Overall Operations
2008 vs. 2007
Our consolidated net loss was $356.5 million, or $7.53 per share (basic and diluted), in 2008 compared to a net loss of $181.8 million, or $3.60 per share (basic and diluted), in 2007. The increase in the loss was primarily due to restructuring charges, decreased interest income, increased interest expense, net, increased depreciation, depletion and amortization expense (“DD&A”), increased LNG receiving terminal and pipeline operating expense and increased loss on early extinguishment of debt, which were partially offset by decreased LNG receiving terminal and pipeline development expense.
A significant portion of our loss was attributable to the recognition of non-cash, share-based payments accounted for under SFAS No. 123R, which requires all non-cash, share-based compensation, be recognized in the 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 $55.0 million of non-cash compensation expense in 2008 compared to $56.6 million of non-cash compensation expense in 2007. In addition, we recognized one-time charges of $78.7 million for restructuring charges and $10.7 million for loss on early extinguishment of debt. Not including the impact of these one-time charges in 2008 and the impact of non-cash expense in 2008, our net loss would have been $212.0 million, or $4.48 net loss per common share (basic and diluted).
2007 vs. 2006
Our consolidated net loss was $181.8 million in 2007, a 25% increase over our 2006 net loss, as described below. The increase in the loss was primarily due to our increase in employee headcount in anticipation of commencing operations in early 2008, additional LNG receiving terminal development expenses and an increase in the amount of DD&A recognized in part due to our increase in asset infrastructure being placed in service. In addition, a significant portion of our loss is attributable to the recognition of non-cash, share-based payments accounted for under SFAS No. 123R, Share-Based Payments, which requires all non-cash, share-based compensation be recognized in the 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 $56.6 million of non-cash compensation expense in 2007. Not including the impact of this non-cash expense in 2007, our net loss would have been $125.2 million, or $2.48 net loss per common share-basic and diluted.
Restructuring Charges
During 2008, we incurred $78.7 million of restructuring charges resulting from our cost savings program in connection with the downsizing of our natural gas marketing business activities, nearing completion of significant construction activities for both the Sabine Pass LNG receiving terminal and Creole Trail Pipeline and seeking alternative arrangements for our time charter interests in two LNG vessels (See Note 4-“Restructuring Charges” of our Notes to Consolidated Financial Statements).
Interest Income
2008 vs. 2007
Interest income decreased $62.3 million in 2008 compared to 2007, because of the lower average invested cash balances resulting from the use of cash to pay construction costs and interest payments and lower interest rates.
Index to Financial Statements 2007 vs. 2006
Interest income increased $33.5 million in 2007 compared to 2006 because of the higher average invested cash balances resulting from the November 2006 issuance of Senior Notes.
Interest Expense, net
2008 vs. 2007
Interest expense, net of amounts capitalized, increased $26.1 million in 2008 compared to 2007. The increase was caused by the additional borrowing under the Bridge Loan, the 2008 Convertible Loans and the issuance of $183.5 million of additional 2016 Notes during the third quarter of 2008.
2007 vs. 2006
Interest expense, net of amounts capitalized, increased $50.6 million in 2007 compared to 2006. The increase was caused primarily by interest expense recognized on the Senior Notes issued for the construction of the Sabine Pass LNG receiving terminal. In addition, in May 2007, we entered into the 2007 Term Loan which increased our debt and correspondingly increased our interest expense, net of amounts capitalized.
DD&A
2008 vs. 2007
DD&A increased $18.0 million in 2008 compared to 2007. This increase resulted from our having begun depreciating the Sabine Pass LNG receiving terminal’s initial 2.6 Bcf/d of regassification capacity and 10.1 Bcf of storage capacity and the Creole Trail Pipeline when they achieved commercial operability in the third and second quarter of 2008, respectively.
LNG Receiving Terminal and Pipeline Operating Expense
2008 vs. 2007
LNG receiving terminal and pipeline operating expenses increased $14.5 million in 2008 compared to 2007 as a result of the Creole Trail Pipeline becoming operational in the second quarter of 2008 and the Sabine Pass LNG receiving terminal achieving commercial operability in September 2008.
Loss on Early Extinguishment of Debt
2008 vs. 2007
Loss on early extinguishment of debt increased $10.7 million in 2008 compared to 2007. The increase was a result of recognizing all unamortized debt issuance costs associated with the $95 million Bridge Loan that was repaid in full using a portion of the borrowings under the 2008 Convertible Loans during the third quarter of 2008.
2007 vs. 2006
In connection with the issuance of the Senior Notes in November 2006, we terminated a Sabine Pass credit facility and term loan. As a result, we recorded a $43.2 million loss on the early extinguishment of debt related to the expensing of debt issuance costs.
LNG Receiving Terminal and Pipeline Development Expense
Our LNG receiving terminal and pipeline development expenses include primarily professional costs associated with front-end engineering and design work, obtaining orders from the FERC authorizing construction of our facilities and other required permitting for our planned LNG receiving terminals and natural gas pipelines.
Index to Financial Statements 2008 vs. 2007
LNG receiving terminal and pipeline development expenses decreased $24.1 million in 2008 compared to 2007. The major components of the decrease were an $11.0 million decrease in salaries and benefits, a $4.4 million decrease in public relations and other business development expenditures and a $2.6 million decrease in non-cash compensation expenses. These development expenses along with other $6.1 million individually insignificant development activities decreased in 2008 as a result of the achievement of commercial operability of the initial phase of the Sabine Pass LNG receiving terminal and Phase 1 of the Creole Trail Pipeline and the resulting shift from development activities in 2007 to operating activities in 2008.
2007 vs. 2006
LNG receiving terminal and pipeline development expenses increased $22.6 million in 2007 compared to 2006. Regulatory pipeline asset development expense increased $12.3 million in 2007 as a result of the 2006 recognition as regulatory assets, as prescribed by SFAS No. 71, Accounting for Effects of Certain Types of Regulations, amounts that had previously been expensed as pipeline development expenses. The impact of recording these regulatory assets reduced pipeline development expense in 2006 by $12.3 million. Employee salaries and benefits increased $9.7 million in 2007, due to an increase in the average number of employees engaged in LNG receiving terminal and pipeline activities from 68 in 2006 to 138 in 2007. Public relations increased $4.0 million in 2007 due to our participation in Hurricane Rita relief in Johnson Bayou, Louisiana. These increases in development expense were partially offset by a decrease in professional and technical expenses in 2007 as a result of decreased engineering, legal and other technical and professional services directly related to the Corpus Christi and Creole Trail LNG receiving terminals in 2007 as compared to 2006.
Off-Balance Sheet Arrangements
As of December 31, 2008, 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 2008, 2007 and 2006, 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 the specific set of circumstances existing in our business. In preparing our financial statements in conformity with U.S. generally accepted accounting principles (“GAAP”), we make every effort to comply properly 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. Additional information about our critical accounting policies is included in Note 2-“Summary of Significant Accounting Policies” of our Notes to Consolidated Financial Statements.
Accounting for LNG Activities
Generally, we begin capitalizing the costs of our LNG receiving terminals and related pipelines once the individual project meets the following criteria: (i) regulatory approval has been received, (ii) financing for the
Index to Financial Statements
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 receiving terminals and related pipelines.
Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land costs, costs of lease options and the costs of certain permits, which 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. Site rental costs and related amortization of capitalized options were capitalized during the construction period through the end of 2005. Beginning in 2006, such costs have been expensed as required by the Financial Accounting Standards Board (“FASB”) Staff Position (“FSP”) 13-1, Accounting for Rental Cost Incurred During a Construction Period.
During the construction periods of our LNG receiving terminals, we capitalize interest and other related debt costs in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 34, Capitalization of Interest Cost, as amended by SFAS No. 58, Capitalization of Interest Cost in Financial Statements That Include Investments Accounted for by the Equity Method-an Amendment of FASB Statement No. 34. 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 fees are recognized as revenue over the term of the respective TUAs. Advance capacity reservation fees are initially deferred.
Regulated Natural Gas Pipelines
Our developing 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, and we have determined that certain of our pipeline systems to be constructed have met the criteria set forth in SFAS No. 71, Accounting for the Effects of Certain Types of Regulations. Accordingly, we have applied the provisions of SFAS No. 71 to the affected pipeline subsidiaries beginning in the second quarter of 2006.
Our application of SFAS No. 71 is based on the current regulatory environment, our current projected tariff rates, and our ability to collect those rates. Future regulatory developments and rate cases could impact this accounting. Although discounting of our maximum tariff rates may occur, we believe that the standards required by SFAS No. 71 for its application are met and the use of regulatory accounting under SFAS No. 71 best reflects the results of future operations in the economic environment in which we will operate. Regulatory accounting requires us to record assets and liabilities that result from the rate-making process that would not be recorded under generally accepted accounting principles for non-regulated entities. We will continue to evaluate the application of regulatory accounting principles based on on-going changes in the regulatory and economic environment. 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.
Index to Financial Statements 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.
Cash Flow Hedges
We have used, and may in the future use, derivative instruments to limit our exposure to variability in expected future cash flows. As defined in SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, cash flow hedge transactions hedge the exposure to variability in expected future cash flows (i.e., in our case, the variability of floating interest rate exposure). In the case of cash flow hedges, the hedged item (the underlying risk) is generally unrecognized (i.e., not recorded on the balance sheet prior to settlement), and any changes in the fair value, therefore, will not be recorded within earnings. Conceptually, if a cash flow hedge is effective, this means that a variable, such as a movement in interest rates, has been effectively fixed so that any fluctuations will have no net result on either cash flows or earnings. Therefore, if the changes in fair value of the hedged item are not recorded in earnings, then the changes in fair value of the hedging instrument (the derivative) must also be excluded from the income statement or else a one-sided net impact on earnings will be reported, despite the fact that the establishment of the effective hedge results in no net economic impact. To prevent such a scenario from occurring, SFAS No. 133 requires that the fair value of a derivative instrument designated as a cash flow hedge be recorded as an asset or liability on the balance sheet, but with the offset reported as part of other comprehensive income, to the extent that the hedge is effective. We assess both at the inception of each hedge and on an on-going basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows of the hedged items. On an on-going basis, we monitor the actual dollar offset of the hedges’ market values compared to hypothetical cash flow hedges. Any ineffective portion of the cash flow hedges will be reflected in earnings. Ineffectiveness is the amount of gains or losses from derivative instruments that are not offset by corresponding and opposite gains or losses on the expected future transaction.
Goodwill
Goodwill is accounted for in accordance with SFAS No. 142, Goodwill and Other Intangible Assets. 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. See Note 14-“Goodwill” of our Notes to Consolidated Financial Statements.
Share-Based Compensation Expense
Effective January 1, 2006, we adopted the fair value recognition provisions of SFAS No. 123R, Share-Based Payments, using the modified prospective transition method, and therefore have not restated the results of prior periods. Under this method, we recognize compensation expense for all share-based payments granted after January 1, 2006 and prior to, but not yet vested as of, January 1, 2006, in accordance with SFAS No. 123R using the Black-Scholes-Merton option valuation model. Under the fair value recognition provisions of SFAS No. 123R, 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. Prior to the adoption of SFAS No. 123R, we accounted for share-based payments under Accounting Principles Board (“APB”) Opinion 25, Accounting for Stock Issued to Employees, and accordingly, did not recognize compensation expense for options granted that had an exercise price greater than or equal to the market value of the underlying common stock on the date of grant.
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
Index to Financial Statements
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 year ended December 31, 2008 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 21-“Share-Based Compensation” of our Notes to Consolidated Financial Statements).
Change in Method of Accounting for Investments in Oil and Gas Properties
Effective January 1, 2006, we converted from the full cost method to the successful efforts method of accounting for our investments in oil and gas properties. While our primary focus is the development of our LNG-related businesses, we have continued to be involved, to a limited extent, in oil and gas exploration, development and exploitation activities in the U.S. Gulf of Mexico. We determined that, in light of our level of exploration, development and exploitation activities in 2005, the successful efforts method of accounting provided a better matching of expenses to the period in which oil and gas production was realized. As a result, we determined that the change in accounting method at that time was appropriate. The change in accounting method constituted a “Change in Accounting Principle,” requiring that all prior period financial statements be adjusted to reflect the results and balances that would have been reported had we been following the successful efforts method of accounting from our inception. The cumulative effect of the change in accounting method as of December 31, 2006 and 2005 was to reduce the balance of our net investment in oil and gas properties and retained earnings at those dates by $18.0 million and $18.2 million, respectively. The change in accounting method resulted in a decrease in the net loss of $0.3 million and an increase in the net loss of $0.3 million for 2006 and 2005, respectively, and had no impact on earnings per share (basic and diluted) for these respective periods. The change in method of accounting had no impact on cash or working capital.
Recently Issued Accounting Standards Not Yet Adopted
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements-an amendment of ARB No. 51, which establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS No. 160 is effective for fiscal years beginning October 1, 2009. In conjunction with our public offering of 15,525,000 of our common units in Cheniere Partners, we sold a portion of our Cheniere Partners common units to the public, realizing net proceeds of $203.9 million. Due to the subordinated distribution rights on our subordinated units, we have recorded those proceeds as a minority interest. As a result of the adoption of SFAS No. 160 on January 1, 2009, when our subordinated units in Cheniere Partners are converted to common units we are no longer able to elect an accounting policy of recording this gain through earnings, but will recognize the $203.9 million suspended gain directly in equity. In addition, our minority interest will be presented within the Stockholders equity section of our consolidated balance sheet, separate from the parent’s equity.
On January 1, 2008, we adopted SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities-including an amendment of FASB Statement No. 115. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other assets and liabilities at fair value on an instrument-by-instrument basis (the fair value option) with changes in fair value reported in earnings. Cheniere already records derivative contracts at fair value in accordance with SFAS No. 133, Accounting for Derivative
Index to Financial Statements
Instruments and Hedging Activities, as amended. The adoption of SFAS No. 159 had no impact on our financial position, results of operations and cash flow as management did not elect the fair value option for any financial instruments or other assets and liabilities.
On January 1, 2008, we adopted SFAS No. 157, Fair Value Measurements as it relates to financial assets and financial liabilities. In February 2008, the FASB issued FASB Staff Position (“FSP”) No. FAS 157-2, Effective Date of FASB Statement No. 157, which delayed the effective date of SFAS No. 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on at least an annual basis, until January 1, 2009 for calendar year-end entities. The adoption of SFAS No. 157 did not have a material impact on our financial position, results of operations and cash flow.
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No. 13. SFAS No. 161 requires enhanced disclosures about an entity’s derivative and hedging activities, including (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedged items are accounted for under SFAS No. 133, and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. This standard becomes effective for us on January 1, 2009. Earlier adoption of SFAS No. 161 and, separately, comparative disclosures for earlier periods at initial adoption are encouraged. As SFAS No. 161 only requires enhanced disclosures, this standard will have no impact on our financial position, results of operations and cash flow.
In April 2008, the FASB issued FSP SFAS No. 142-3, Determination of the Useful Life of Intangible Assets. This FSP amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FASB Statement No. 142, Goodwill and Other Intangible Assets. The intent of this FSP is to improve the consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141R, and other GAAP. This FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption is prohibited. We do not expect the adoption of SFAS FSP No. 142-3 to have a material impact on our financial position, results of operations and cash flow.
In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles. SFAS No. 162 identifies the sources of accounting principles and the framework for selecting principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP in the United States. This statement will be effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board’s amendments to AU section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles. We do not expect the adoption of SFAS No. 162 to have a material impact on our financial position, results of operations and cash flow.
In May 2008, the FASB issued FSP APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement). This FSP clarifies that convertible debt instruments that may be settled in cash upon conversion (including partial cash settlement) are not addressed by paragraph 12 of APB Opinion No. 14, Accounting for Convertible Debt and Debt issued with Stock Purchase Warrants. Additionally, this FSP specifies that issuers of such instruments should separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. This FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. We do not anticipate that this new FSP will have any material impact upon our financial position, results of operations and cash flow.
Index to Financial Statements 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 sheet.
Marketing and Trading Commodity Price Risk
Our derivative positions as of December 31, 2008 primarily consisted of exchange cleared NYMEX natural gas swaps entered into to hedge the exposure to variability in expected future cash flows related to commissioning and cool down cargoes purchased in the second quarter of 2008 that are being sold as part of the testing phase of the commissioning process. As of December 31, 2008, we had entered into a total of 782,500 MMBtu of NYMEX natural gas swaps through June 2009 for which we will receive fixed prices of $5.35 to $8.62 per MMBtu. At December 31, 2008, the value of the derivatives was an asset of $1.2 million.
Index to Financial Statements ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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
Report of Independent Registered Public Accounting Firm-UHY LLP
Consolidated Balance Sheet
Consolidated Statement of Operations
Consolidated Statement of Stockholders’ (Deficit) Equity
Consolidated Statement of Cash Flows
Notes to Consolidated Financial Statements
Supplemental Information to Consolidated Financial Statements-Summarized Quarterly Financial Data
Index to Financial Statements 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.
Based on our assessment, we have concluded that Cheniere maintained effective internal control over financial reporting as of December 31, 2008, based on criteria in Internal Control-Integrated Framework issued by the COSO.
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/ DON A. TURKLESON
Charif Souki
Chief Executive Officer and President
Don A. Turkleson
Senior Vice President
and Chief Financial Officer
Index to Financial Statements 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, 2008 and 2007, and the related consolidated statements of operations, stockholders’ (deficit) equity, and cash flows for each of the two years in the period ended December 31, 2008. Our audit 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 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 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 provides 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, 2008 and 2007, and the consolidated results of their operations and their cash flows for each of the two years in the period ended December 31, 2008, 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, 2008, 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 26, 2009 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
ERNST & YOUNG LLP
Houston, Texas
February 26, 2009
Index to Financial Statements REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of
Cheniere Energy, Inc.
We have audited Cheniere Energy, Inc.’s internal control over financial reporting as of December 31, 2008, 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.’s 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. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, 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, 2008 and 2007, and the related consolidated statements of operations, stockholders’ (deficit) equity, and cash flows for each of the two years in the period ended December 31, 2008 and our report dated February 26, 2009 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
ERNST & YOUNG LLP
Houston, Texas
February 26, 2009
Index to Financial Statements REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and
Stockholders of Cheniere Energy, Inc.:
We have audited the accompanying consolidated statements of operations, stockholders’ equity and cash flows of Cheniere Energy, Inc. and subsidiaries (the “Company”) for the year ended December 31, 2006. In connection with our audit of the consolidated financial statements, we also have audited financial statement schedule I. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule 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 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 audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated results of their operations and their cash flows for the year ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
As discussed in Note 2 to the consolidated financial statements, effective January 1, 2006, the Company changed its method of accounting for investments in oil and gas properties. As also discussed in Note 2 to the consolidated financial statements, effective January 1, 2006, the Company changed its method of accounting for stock-based compensation.
/s/ UHY LLP
UHY LLP
Houston, Texas
February 27, 2007 except for
financial statement schedule I as to which the
date is February 26, 2008
Index to Financial Statements CHENIERE ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(in thousands, except share data)
The accompanying notes are an integral part of these financial statements.
Index to Financial Statements CHENIERE ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
(in thousands, except per share data)
The accompanying notes are an integral part of these financial statements.
Index to Financial Statements CHENIERE ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ (DEFICIT) EQUITY
(in thousands)
The accompanying notes are an integral part of these financial statements.
Index to Financial Statements CHENIERE ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
(in thousands)
The accompanying notes are an integral part of these financial statements.
Index to 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 company engaged, through its subsidiaries, in the energy business generally, including our publicly traded subsidiary partnership, Cheniere Energy Partners, L.P. (“Cheniere Partners”). As used in these Notes to Consolidated Financial Statements, the terms “Cheniere”, “we”, “us” and “our” refer to Cheniere Energy, Inc. and its subsidiaries. We are currently engaged primarily in the business of developing and constructing, and then owning and operating, a network of three onshore liquefied natural gas (“LNG”) receiving terminals and natural gas pipelines, and we are developing a business to market LNG and natural gas primarily through our wholly-owned subsidiary, Cheniere Marketing, LLC. (“Cheniere Marketing”), formerly Cheniere Marketing, Inc. To a limited extent, we continue to be engaged in oil and natural gas exploration, development and exploitation activities in the Gulf of Mexico.
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. The consolidated financial statements include the accounts of Cheniere Energy, Inc. and its majority-owned subsidiaries. We also hold ownership interests in entities that are accounted for under the equity method of accounting. All significant intercompany accounts and transactions have been eliminated in consolidation.
Accounting for LNG Activities
Generally, we begin capitalizing the costs of our LNG receiving 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 receiving terminals and related pipelines.
Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land costs, costs of lease options and the costs of certain permits, which 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. Site rental costs and related amortization of capitalized options were capitalized during the construction period through the end of 2005. Beginning in 2006, such costs have been expensed as required by the Financial Accounting Standards Board (“FASB”) Staff Position (“FSP”) 13-1, Accounting for Rental Cost Incurred During a Construction Period.
During the construction periods of our LNG receiving terminals, we capitalize interest and other related debt costs in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 34, Capitalization of Interest Cost, as amended by SFAS No. 58, Capitalization of Interest Cost in Financial Statements That Include Investments Accounted for by the Equity Method-an Amendment of FASB Statement No. 34. Upon commencement of operations, capitalized interest, as a component of the total cost, will be amortized over the estimated useful life of the asset.
Regulated Operations
Our developing natural gas pipeline business is subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”) in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978,
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and we have determined that certain of our pipeline systems to be constructed have met the criteria set forth in SFAS No. 71, Accounting for the Effects of Certain Types of Regulations. Accordingly, we began applying the provisions of SFAS No. 71 to the affected pipeline subsidiaries in the second quarter of 2006.
Our application of SFAS No. 71 is based on the current regulatory environment, our current projected tariff rates and our ability to collect those rates. Future regulatory developments and rate cases could impact this accounting. Although discounting of our maximum tariff rates may occur, we believe the standards required by SFAS No. 71 for its application are met and the use of regulatory accounting under SFAS No. 71 best reflects the results of future operations in the economic environment in which we will operate. Regulatory accounting requires us to record assets and liabilities that result from the rate-making process that would not be recorded under the accounting principles generally accepted in the United States of America (“GAAP”) for non-regulated entities. We will continue to evaluate the application of regulatory accounting principles based on on-going changes in the regulatory and economic environment. Items that may influence our assessment are:
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inability to recover cost increases due to rate caps and rate case moratoriums;
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inability to recover capitalized costs, including an adequate return on those costs through the rate-making process and the FERC proceedings;
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excess capacity;
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increased competition and discounting in the markets we serve; and
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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.
Revenue Recognition
LNG regasification capacity fees are recognized as revenue over the term of the respective terminal use agreement (“TUA”). Advance payments of capacity reservation fees are initially deferred.
Revenues from the sale of oil and gas production are recognized upon passage of title, net of royalty interests. When sales volumes differ from our entitled share, an underproduced or overproduced imbalance occurs. To the extent an overproduced imbalance exceeds our share of the remaining estimated proved natural gas reserves for a given property, we record a liability. At December 31, 2008 and 2007, we had no gas imbalances.
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. Once placed into service, the LNG terminal construction-in-process costs are depreciated using the straight-line depreciation method. Depreciation of computer and office equipment,
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computer software, leasehold improvements and vehicles is computed using the straight-line method over the estimated useful lives of the assets, which range from two to ten years. 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.
In accordance with SFAS No. 144, 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 impairments related to fixed assets of zero, $18,000 and $1.6 million for 2008, 2007 and 2006.
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 prescribed in SFAS No. 109, Accounting for Income Taxes. 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.
Cash Flow Hedges
We have used, and may in the future use, derivative instruments to limit our exposure to variability in expected future cash flows. As defined in SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, cash flow hedge transactions hedge the exposure to variability in expected future cash flows (i.e., in our case, the variability of floating interest rate exposure). In the case of cash flow hedges, the hedged item (the underlying risk) is generally unrecognized (i.e., not recorded on the balance sheet prior to settlement), and any changes in the fair value, therefore, will not be recorded within earnings. Conceptually, if a cash flow hedge is effective, this means that a variable, such as a movement in interest rates, has been effectively fixed so that any fluctuations will have no net result on either cash flows or earnings. Therefore, if the changes in fair value of the hedged item are not recorded in earnings, then the changes in fair value of the hedging instrument (the derivative) must also be excluded from the income statement or else a one-sided net impact on earnings will be reported, despite the fact that the establishment of the effective hedge results in no net economic impact. To prevent such a scenario from occurring, SFAS No. 133 requires that the fair value of a derivative instrument designated as a cash flow hedge be recorded as an asset or liability on the balance sheet, but with the offset reported as part of other comprehensive income, to the extent that the hedge is effective. We assess both at the inception of each hedge and on an on-going basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows of the hedged items. On an on-going basis we monitor the actual dollar offset of the hedges’ market values compared to hypothetical cash flow hedges. Any ineffective portion of the cash flow hedges will be reflected in earnings. Ineffectiveness is the amount of gains or losses from derivative instruments that are not offset by corresponding and opposite gains or losses on the expected future transaction.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions that affect the
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amounts reported in the consolidated financial statements and the accompanying notes. Actual results could differ from the estimates and assumptions used.
Items subject to estimates and assumptions include, but are not limited to, the carrying amount of property, plant and equipment, and goodwill; valuation allowances for income tax assets; and the fair value of share-based payments. Actual results could differ significantly from those 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.
We have entered into certain long-term TUAs with unaffiliated third parties for regasification capacity at our Sabine Pass LNG receiving terminal. We are dependent on the respective counterparties’ creditworthiness and their willingness to perform under their respective TUAs. We have mitigated this credit risk by securing TUAs for a significant portion of our regasification capacity with creditworthy third-party customers with a minimum Standard & Poor’s rating of AA.
Goodwill
As further described in Note 14-“Goodwill”, we account for goodwill in accordance with the provisions of SFAS No. 142, Goodwill and Other Intangible Assets. Under the provisions of that statement, we are required to perform an annual review of goodwill for impairment. This review is required to be done at the reporting unit level, which we have determined to be our LNG receiving terminals business, which is a component of our LNG receiving terminal development business segment. We perform the annual review for possible impairment in the fourth calendar quarter of each year. If an event or change in circumstances indicates the fair value of a reporting unit may be below its carrying value, an impairment test would be performed sooner than the annual review date.
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
Effective January 1, 2006, we adopted the fair value recognition provisions of SFAS No. 123R, Share-Based Payments, using the modified prospective transition method, and therefore have not restated the results of
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prior periods. Under this method, we recognize compensation expense for all share-based payments granted after January 1, 2006 and prior to, but not yet vested as of, January 1, 2006, in accordance with SFAS No. 123R using the Black-Scholes-Merton option valuation model. Under the fair value recognition provisions of SFAS No. 123R, 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. Prior to the adoption of SFAS No. 123R, we accounted for share-based payments under Accounting Principles Board (“APB”) Opinion 25, Accounting for Stock Issued to Employees, and accordingly, did not recognize compensation expense for options granted that had an exercise price greater than or equal to the market value of the underlying common stock on the date of grant.
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 2008 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 21-“Share-Based Compensation” for further discussion on share-based compensation).
Net Loss Per Share
Net loss per share (“EPS”) is computed in accordance with the requirements of SFAS No. 128, Earnings Per Share. 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 under SFAS No. 128. 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 2008, 2007 and 2006, were 4.9 million, 5.8 million and 5.7 million, respectively. In addition, common shares of 59.2 million on a weighted average basis, issuable upon conversion of the 2008 Convertible Loans and the Convertible Senior Unsecured Notes (described in Note 18-“Long-Term Debt and Long-Term Debt-Related Parties”), were not included in the computation of diluted net loss per share for 2008, 2007 and 2006, 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.
Change in Method of Accounting for Investments in Oil and Gas Properties
Effective January 1, 2006, we converted from the full cost method to the successful efforts method of accounting for our investments in oil and gas properties. While our primary focus is the development of our LNG-related businesses, we have continued to be involved, to a limited extent, in oil and gas exploration and development activities in the U.S. Gulf of Mexico. We determined that, in light of our current level of exploration and development activities, the successful efforts method of accounting provides was better matching
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of expenses to the period in which oil and gas production was realized. As a result, we determined that the change in accounting method was appropriate. The change in accounting method constituted a “Change in Accounting Principle,” requiring that all prior period financial statements be adjusted to reflect the results and balances that would have been reported had we been following the successful efforts method of accounting from our inception. The cumulative effect of the change in accounting method as of December 31, 2006 was to reduce the balance of our net investment in oil and gas properties and retained earnings at that date by $18.0 million. The change in accounting method for the year ended December 31, 2006 resulted in a decrease in the net loss of $15.0 million. The cumulative effect of the change in accounting method increased earnings per share (basic and diluted) $0.3 million for the year ended December 31, 2006, but had no impact on earnings per share (basic and diluted) for the year ended December 31, 2006. The change in method of accounting had no impact on cash or working capital.
Asset Retirement Obligations
We account for the retirement of our tangible long-lived assets in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires us to record the fair value of a liability for legal obligations associated with the retirement of tangible long-lived assets and a corresponding increase in the carrying amount of the related long-lived assets. Subsequently, the asset retirement costs included in the carrying amount of the related asset are allocated to expense based on the useful life of the applicable asset.
New Accounting Pronouncements
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements-an amendment of ARB No. 51, which establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS No. 160 is effective for fiscal years beginning October 1, 2009. In conjunction with our public offering of 15,525,000 of our common units in Cheniere Partners, we sold a portion of our Cheniere Partners common units to the public, realizing net proceeds of $203.9 million. Due to the subordinated distribution rights on our subordinated units, we have recorded those proceeds as a minority interest. As a result of the adoption of SFAS No. 160 on January 1, 2009, when our subordinated units in Cheniere Partners are converted to common units we are no longer able to elect an accounting policy of recording this gain through earnings, but will recognize the $203.9 million suspended gain directly in equity. In addition, our minority interest will be presented within the Stockholders equity section of our consolidated balance sheet, separate from the parent’s equity.
On January 1, 2008, we adopted SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities-including an amendment of FASB Statement No. 115 (“SFAS No. 159”). SFAS No. 159 permits entities to choose to measure many financial instruments and certain other assets and liabilities at fair value on an instrument-by-instrument basis (the fair value option) with changes in fair value reported in earnings. Cheniere already records derivative contracts at fair value in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended (“SFAS No. 133”). The adoption of SFAS No. 159 had no impact on our financial position, results of operations and cash flow as management did not elect the fair value option for any financial instruments or other assets and liabilities.
On January 1, 2008, we adopted SFAS No. 157, Fair Value Measurements (“SFAS No. 157”) as it relates to financial assets and financial liabilities. In February 2008, the FASB issued FSP No. FAS 157-2, Effective Date of FASB Statement No. 157, which delayed the effective date of SFAS No. 157 for all nonfinancial assets and
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nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on at least an annual basis, until January 1, 2009 for calendar year-end entities. The adoption of SFAS No. 157 did not have a material impact on our financial position, results of operations or cash flow.
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No. 133 (“SFAS No. 161”). SFAS No. 161 requires enhanced disclosures about an entity’s derivative and hedging activities, including (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedged items are accounted for under SFAS No. 133, and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. This standard becomes effective for us on January 1, 2009. Earlier adoption of SFAS No. 161 and, separately, comparative disclosures for earlier periods at initial adoption are encouraged. As SFAS No. 161 only requires enhanced disclosures, this standard will have no impact on our financial position, results of operations or cash flow.
In April 2008, the FASB issued FASB Staff Position (“FSP”) SFAS No. 142-3, Determination of the Useful Life of Intangible Assets. This FSP amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FASB Statement No. 142, Goodwill and Other Intangible Assets. The intent of this FSP is to improve the consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141R, and other GAAP. This FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption is prohibited. We do not expect the adoption of SFAS FSP No. 142-3 to have a material impact on our financial position, results of operations or cash flow.
In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles. SFAS No. 162 identifies the sources of accounting principles and the framework for selecting principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP in the United States. This statement will be effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board’s amendments to AU section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles. We do not expect the adoption of SFAS No. 162 to have a material impact on our financial position, results of operations or cash flow.
In May 2008, the FASB issued FSP APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement). This FSP clarifies that convertible debt instruments that may be settled in cash upon conversion (including partial cash settlement) are not addressed by paragraph 12 of APB Opinion No. 14, Accounting for Convertible Debt and Debt issued with Stock Purchase Warrants. Additionally, this FSP specifies that issuers of such instruments should separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. This FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. We do not anticipate that this new FSP will have any material impact upon our financial position, results of operations or cash flow.
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NOTE 3-INITIAL PUBLIC OFFERING OF CHENIERE ENERGY PARTNERS, L.P.
On March 26, 2007, Cheniere Partners and Cheniere LNG Holdings, LLC (“Holdings”), our wholly-owned subsidiary, completed an initial public offering of 13,500,000 Cheniere Partners common units (the “Cheniere Partners Offering”). Cheniere Partners is a Delaware limited partnership formed by us to develop, own and operate the Sabine Pass LNG receiving terminal. Upon the closing of the Cheniere Partners Offering, the following transactions occurred:
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Holdings contributed its ownership interests in the entities that directly or indirectly own the Sabine Pass LNG receiving terminal to Cheniere Energy Investments, LLC, a wholly-owned subsidiary of Cheniere Partners;
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Cheniere Partners issued 21,362,193 common units, 135,383,831 subordinated units, 3,302,045 general partner units (representing a 2% general partner interest) and certain general partner incentive distribution rights to wholly-owned subsidiaries of Cheniere;
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Cheniere Partners issued 5,054,164 common units to the public and received net proceeds of $98.4 million; and
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Holdings initially sold 8,445,836 common units to the public and received net proceeds of $164.5 million, after which Cheniere and the public owned 89.8% and 8.2% limited partner interests in Cheniere Partners, respectively. Holdings also granted the underwriters an option to purchase an additional 2,025,000 of its Cheniere Partners common units to cover over-allotments in connection with the Cheniere Partners Offering.
Cheniere Partners used all of the net proceeds of $98.4 million it received from the sale of its common units to purchase U.S. Treasury securities to fund a distribution reserve for payment of initial quarterly distributions of $0.425 per common unit, as well as related quarterly distributions to its general partner, until Cheniere Partners is able to sustain funding of distributions to its unitholders from unrestricted cash, at which time any remaining cash in the distribution reserve is expected to be returned to us.
On April 16, 2007, the underwriters of the Cheniere Partners Offering exercised their over-allotment option to purchase 2,025,000 additional common units, which resulted in net proceeds of approximately $39.4 million to Holdings as the selling unitholder.
The net proceeds of $164.5 million from the initial sale of the common units by Holdings and the net proceeds of $39.4 million that it received from the subsequent exercise of the underwriters’ option to purchase additional common units from Holdings are not assets of Cheniere Partners, and therefore, are unrestricted as to our use and are available for corporate and general business purposes.
As of December 31, 2008, our combined general partner and limited partner ownership interest in Cheniere Partners was approximately 90.6%. As of such date, we held 135,383,831 subordinated units, 10,891,357 common units and 3,302,045 general partner units of Cheniere Partners. During the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the initial quarterly distribution plus any arrearages on the initial quarterly distribution from prior quarters. Our subordinated units do not accrue arrearages. The subordination period generally will end if:
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Cheniere Partners has earned and paid at least $0.425 on each outstanding common unit, subordinated unit and general partner unit for each of the three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2010; or
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Cheniere Partners has earned and paid at least $0.638 (150% of the initial quarterly distribution) on each outstanding common unit, subordinated unit and general partner unit for any four consecutive quarters ending on or after June 30, 2008.
The portion of the common units held by the public is presented as a minority interest on our Consolidated Balance Sheet. Losses attributable to the minority interest are presented separately on our Consolidated Statement of Operations based upon the minority interest’s share of Cheniere Partners’ losses calculated in accordance with Cheniere Partners’ partnership agreement.
NOTE 4-RESTRUCTURING CHARGES
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 receiving terminal and Creole Trail Pipeline and the seeking of alternative arrangements for our time charter interest in two LNG vessels. In connection with this program, we recognized $78.7 million in restructuring charges in 2008, in accordance with SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities, and have presented the financial impact as restructuring charges on the Consolidated Statements of Operations.
Below is a reconciliation of the total restructuring charges expected to be recognized and charged to expense over the restructuring period to the amount of expected restructuring charges at December 31, 2008 (in thousands):
NOTE 5-MINORITY INTEREST
We have consolidated certain joint ventures and partnerships because we have a controlling interest in these ventures. Therefore, the entities’ financial statements are consolidated in our consolidated financial statements and the other entities equity is recorded as minority interest. The following table sets forth the components of our minority interest balance attributable to third-party investors’ interest (in thousands):
(1) Through the Cheniere Partners Offering, Cheniere Partners received $98.4 million in net proceeds from the issuance of its common units to the public. Securities and Exchange Commission (“SEC”) Staff Accounting
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Bulletin (“SAB”) No. 51, Accounting for Sales of Stock by a Subsidiary, provided guidance on accounting by the parent for issuances of a subsidiary’s common equity to unaffiliated parties. Under SAB No. 51, 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. SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements-an amendment of ARB No. 51, establishes new accounting and reporting standards for the noncontrolling interest in a subsidiary. As a result of the adoption of SFAS No. 160 on January 1, 2009, when our subordinated units in Cheniere Partners are converted to common units we will recognize the $98.4 million suspended gain directly in equity. In addition, our minority interest will be presented within the stockholders equity section of our consolidated balance sheet, separate from the parent’s equity.
(2) In conjunction with the Cheniere Partners Offering, Holdings sold a portion of the Cheniere Partners common units held by it to the public, realizing proceeds net of offering costs 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 minority interest. As a result of the adoption of SFAS No. 160 on January 1, 2009, when our subordinated units in Cheniere Partners are converted to common units we will recognize the $203.9 million suspended gain directly in equity. In addition, our minority interest will be presented within the stockholders equity section of our consolidated balance sheet, separate from our equity.
NOTE 6-TREASURY STOCK
During the second half of 2007, we purchased 9.2 million shares of our common stock through the exercise of call options acquired in the issuer call spread purchased by us in connection with the issuance of the Convertible Senior Unsecured Notes (See Note 18-“Long-Term Debt and Long-Term Debt-Related Parties”). These purchases completed the acquisition of our common stock under the call option, bringing our total stock purchased under the issuer call spread to 9.2 million shares with an aggregate purchase price of approximately $325.0 million. These shares were held as treasury stock at December 31, 2007. During 2008, we retired 9.5 million shares of treasury stock, which brings the shares held in treasury at December 31, 2008 to 0.2 million shares.
NOTE 7-RESTRICTED CASH AND CASH EQUIVALENTS AND U.S. TREASURY SECURITIES
Restricted cash and cash equivalents and U.S. Treasury securities are composed of cash that has been contractually restricted as to usage or withdrawal, as follows:
Sabine Pass LNG Receiving Terminal Construction Reserve
In November 2006, Sabine Pass LNG, L.P., our wholly-owned subsidiary (“Sabine Pass LNG”), consummated a private offering of an aggregate principal amount of $2,032.0 million of Senior Secured Notes consisting of $550.0 million of 7 1/4% Senior Secured Notes due 2013 (the “2013 Notes”) and $1,482.0 million of 7 1/2% Senior Secured Notes due 2016 (the “2016 Notes” and collectively with the 2013 Notes, the “Senior Notes”) (See Note 18-“Long-Term Debt and Long-Term Debt-Related Parties”). 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. The additional issuance and the previously outstanding 2016 Notes are treated as a single series of notes under the indenture governing the Senior Notes (“Sabine Pass Indenture”). Under the terms and conditions of the Senior Notes, we were required to fund a cash reserve account for approximately $987 million to pay the remaining costs to complete the Sabine Pass LNG receiving terminal. The
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cash accounts are controlled by a collateral trustee, and therefore, are shown as restricted cash and cash equivalents on our Consolidated Balance Sheet. As of December 31, 2008 and 2007, $27.4 million and $40.2 million related to accrued construction costs had been classified as part of current restricted cash and cash equivalents, and $43.7 million and $380.2 million related to remaining construction costs had been classified as a non-current asset on our Consolidated Balance Sheet, respectively.
Senior Notes Debt Service Reserve
As described above, Sabine Pass LNG consummated private offerings of an aggregate principal amount of $2,215.5 million Senior Notes (See Note 18-“Long-Term Debt and Long-Term Debt-Related Parties”). Under the terms and conditions of the Senior Notes, we were required to fund a cash reserve account with $335.0 million related to future interest payments on the Senior Notes through May 2009. The cash accounts are controlled by a collateral trustee, and therefore, are shown as restricted cash and cash equivalents on our Consolidated Balance Sheet. As of December 31, 2008 and 2007, $13.7 million and $151.0 million related to the payment of interest due within twelve months had been classified as part of current restricted cash, and $82.4 million and $61.8 million related to the remaining payments of interest had been classified as non-current restricted cash, respectively.
Cheniere Partners Distribution Reserve
At the closing of the Cheniere Partners Offering, Cheniere Partners funded a distribution reserve of $98.4 million, which was invested in U.S. Treasury securities (See Note 3-“Initial Public Offering of Cheniere Energy Partners, L.P.”). The distribution reserve, including interest earned thereon, is available to pay quarterly distributions of $0.425 per common unit for all common units, as well as related distributions to Cheniere Partners’ general partner, through the distribution made in respect of the quarter ending September 30, 2009. The U.S. Treasury securities were acquired at a discount from their maturity values equal to an average of approximately 4.87% per year. As of December 31, 2008, we classified the $20.8 million balance of U.S. Treasury securities as Non-Current Restricted U.S. Treasury Securities on our Consolidated Balance Sheet, as these securities had original maturities greater than three months.
TUA Reserve
Under the terms and conditions of the 2008 Convertible Loans described below in Note 18-“Long-Term Debt and Long-Term Debt-Related Parties”, we were required to fund a reserve account with $135.0 million to pay Cheniere Marketing’s TUA obligations to Sabine Pass LNG and as additional collateral for the 2008 Convertible Loans. The cash account is controlled by a collateral trustee, and therefore, is shown as restricted cash and cash equivalents on our Consolidated Balance Sheet. In September 2008 and December 2008, Cheniere Marketing utilized $15.0 million and $62.7 million, respectively, of this TUA reserve to pay its fourth quarter 2008 and first quarter 2009 TUA obligations to Sabine Pass LNG. As of December 31, 2008, we classified the remaining $62.8 million as part of current restricted cash on our Consolidated Balance Sheet.
Other Restricted Cash and Cash Equivalents
As of December 31, 2008 and 2007, $197.7 million and $36.9 million related to various other contractual restrictions had been classified as part of current restricted cash and cash equivalents, and $12.4 million and $36.2 million had been classified as a non-current asset on our Consolidated Balance Sheet, respectively.
Index to Financial Statements CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
NOTE 8-LEASES
Future Annual Minimum Lease Payments
Future annual minimum lease payments are as follows (in thousands):
(1) Includes certain lease option renewals as they were reasonably assured, as defined in SFAS No. 13, Accounting for Leases.
(2) Future annual minimum lease payments do not include $6.3 million expected to be recovered through sublease agreements for our Texas Avenue office lease in Houston, Texas, and $7.4 million expected to be recovered for our Pennzoil office lease.
Tug Boat Agreements
Sabine Pass TUG Services, LLC, our 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 receiving 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 Emerging Issues Task Force (“EITF”) 01-08, Determining Whether an Arrangement Contains a Lease, we have determined that the Tug Agreement contains a lease for the tugs specified in the Tug Agreement. In addition, we have concluded that the tug boat lease contained in the Tug Agreement is an operating lease as defined in SFAS No. 13, and as such, the equipment component of the Tug Agreement will be charged to expense over the term of the Tug Agreement as it becomes payable.
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.
In January 2005, we exercised our options and entered into three land leases for the site of the Sabine Pass LNG receiving 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. 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 $1.5 million of site lease expense on our Consolidated Statement of Operations for 2008 and 2007.
NOTE 9-ADVANCES UNDER LONG-TERM CONTRACTS
We have entered into certain engineering, procurement and construction (“EPC”) contracts and purchase agreements related to the construction of our Sabine Pass LNG receiving terminal that require us to make
Index to Financial Statements CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
payments to fund costs that will be incurred or equipment that will be received in the future. Advances made under long-term contracts on purchase commitments are carried at face value and transferred to property, plant and equipment as the costs are incurred or equipment is received. As of December 31, 2008 and 2007, our advances under long-term contracts were $10.7 million and $28.5 million, respectively.
NOTE 10-PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consists of LNG terminal construction-in-process expenditures, LNG site and related costs, investments in oil and gas properties, and fixed assets, as follows (in thousands):
LNG Terminal Costs
Costs associated with the construction of the Sabine Pass LNG receiving terminal have been capitalized as construction-in-process since the date the project satisfied our criteria for capitalization. For 2008 and 2007, we capitalized $80.7 million and $66.2 million of interest expense related to the construction of the Sabine Pass LNG receiving terminal, respectively. In March 2006, our Corpus Christi LNG receiving terminal satisfied the
Index to Financial Statements CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
criteria for capitalization. Accordingly, costs associated with the initial site work for the Corpus Christi LNG receiving terminal have been capitalized. For the years ended December 31, 2008 and 2007, we capitalized $0.6 million and $2.1 million, respectively, of interest expense related to this construction project.
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 receiving terminal when they were ready for use in the third quarter of 2008. The Sabine Pass LNG receiving terminal is depreciated using the straight-line depreciation method applied to groups of LNG receiving terminal assets with varying useful lives. The identifiable components of the Sabine Pass LNG receiving terminal with similar estimated useful lives have a depreciable range between 10 and 50 years.
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, and we have determined that our pipelines have met the criteria set forth in SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. For the years ended December 31, 2008 and 2007, we capitalized $17.0 million and $15.1 million, respectively, of AFUDC to our natural gas pipeline projects.
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. Depreciation expense related to our property, plant and equipment totaled $24.3 million and $5.7 million for the years ended December 31, 2008 and 2007, respectively.
Asset Retirement Costs
Our asset retirement obligations relate primarily to the retirement of certain LNG receiving terminal and natural gas pipeline assets and obligations related to right-of-way agreements. In accordance with SFAS No. 143, Accounting for Asset Retirement Obligations, we determined that due to an indeterminate life of such assets, the fair value of the retirement obligation is not reasonably estimable. A liability for such asset retirement obligation will be recorded when a fair value is determinable.
NOTE 11-INTANGIBLE ASSETS
The fair values, net book values and estimated useful lives of our intangible assets as of December 31, 2008 and 2007 are presented in the following tables (in thousands).
Index to Financial Statements CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Amortizable Intangible Assets
We assigned $1.6 million and $14.2 million to intangible assets acquired either individually or with a group of assets that are subject to amortization as of December 31, 2008 and 2007, respectively. The weighted average amortization period for these assets is 5 years. For 2008 and 2007, we had not recognized amortization expense.
Intangible Assets Not Subject to Amortization
We assigned $4.5 million and $6.2 million to intangible assets acquired either individually or with a group of assets that are not subject to amortization as of December 31, 2008 and 2007, respectively.
NOTE 12-DEBT ISSUANCE COSTS
We have incurred debt issuance costs in connection with our long-term debt. These costs are capitalized and are being amortized over the term of the related debt. As of December 31, 2008, we had capitalized $57.7 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 $43.7 million.
NOTE 13-INVESTMENT IN LIMITED PARTNERSHIP
We account for our 30% limited partnership investment in Freeport LNG Development, L.P. (“Freeport LNG”) using the equity method of accounting. As of December 31, 2008 and 2007, we had unrecorded cumulative suspended losses of $27.2 million and $19.8 million, respectively, related to our investment in Freeport LNG as the basis in this investment had been reduced to zero. In March 2008 and May 2008, we received cash call notices from Freeport LNG requesting that we provide further financial support due to higher than expected commissioning and performance testing costs. During 2008, we funded the cash calls and recorded $4.8 million of additional losses in Freeport LNG. In addition, Freeport LNG distributed $4.8 million to us in October 2008.
We recorded $4.8 million for 2008, and zero for 2007 and 2006 related to net losses of Freeport LNG.
Index to Financial Statements CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The financial position of Freeport LNG at December 31, 2008 and 2007 and the results of Freeport LNG’s operations for the years ended December 31, 2008, 2007 and 2006 are summarized as follows (in thousands):
(1) During 2008, 2007 and 2006, we did not record $12.2 million, $6.8 million and $9.0 million of the net losses for such periods, respectively, as the basis in this investment had been reduced to zero and because we did not guarantee any obligations and had not been committed to provide any further financial support since December 2005, other than $4.8 million in cash calls which we received and funded in 2008.
NOTE 14-GOODWILL
In February 2005, we acquired the minority interest in Corpus Christi LNG, L.P. (“Corpus Christi LNG”), through the acquisition of BPU LNG, Inc. (“BPU”), in exchange for 2 million restricted shares of our common stock. BPU held as its sole asset the 33.3% limited partner interest in Corpus Christi LNG. As a result of this transaction, we own 100% of the limited partner interests in Corpus Christi LNG. This transaction was accounted for using the purchase method of accounting as prescribed by SFAS No. 141, Accounting for Business Combinations, and was valued at $77.2 million, including direct transaction costs. Of this amount, $76.8 million has been recorded as goodwill and will be accounted for in accordance with SFAS No. 142. The goodwill is the difference between the deemed value of the shares conveyed and the historical carrying value of the minority interest under GAAP plus direct transaction costs. For the calculation of federal income taxes, none of this goodwill amount will be deductible.
We performed annual goodwill impairment reviews in the fourth quarters of 2008 and 2007. These impairment reviews 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 receiving terminal business as the reporting unit under review due to similar economic characteristics. Our reviews indicated that no impairment of goodwill was necessary.
Index to Financial Statements CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
NOTE 15-DERIVATIVE INSTRUMENTS
Interest Rate Derivative Instruments
In connection with the closing of the original Sabine Pass credit facility in February 2005 (“the Sabine Pass Credit Facility”), we entered into swap agreements (“Sabine Swaps”). Under the terms of the Sabine Swaps, we were able to hedge against rising interest rates, to a certain extent, with respect to drawings under the Sabine Pass Credit Facility, up to a maximum amount of $700 million. The Sabine Swaps had the effect of fixing the LIBOR component of the interest rate payable under the Sabine Pass Credit Facility with respect to hedged drawings under the Sabine Pass Credit Facility up to a maximum of $700 million at 4.49% from July 25, 2005 through March 25, 2009 and at 4.98% from March 26, 2009 through March 25, 2012. The final termination date of the Sabine Swaps was March 25, 2012.
The Sabine Pass Credit Facility was amended and restated in July 2006, increasing the amount available to Sabine Pass LNG from $822 million to $1.5 billion. In connection with the closing of the amended Sabine Pass Credit Facility in July 2006, we entered into additional interest rate swap agreements (the “Amended Sabine Swaps” and collectively with the Sabine Swaps, the “Swaps”). The Swaps had the combined effect of fixing the LIBOR component of the interest rate payable on borrowings up to a maximum of $1.25 billion at a blended rate of 5.26% from July 25, 2006 through July 1, 2015.
In connection with the closing of a $600 million term loan (the “Term Loan”) on August 31, 2005, Holdings entered into interest rate swap agreements (“Term Loan Swaps”) to hedge against rising interest rates. Under the terms of the Term Loan Swaps, Holdings hedged an initial notional amount of $600 million. The notional amount declined in accordance with anticipated principal payments under the Term Loan. The Term Loan Swaps had the effect of fixing the LIBOR rate component of the interest rate payable under the Term Loan at 3.75% from August 31, 2005 to September 27, 2007, at 3.98% from September 28, 2007 to September 27, 2008, and at 5.98% from September 28, 2008 to September 30, 2010. The final termination date of the Term Loan Swaps was September 30, 2010.
In conjunction with the termination of the amended Sabine Pass Credit Facility and the Term Loan in November 2006, we terminated the Swaps and the Term Loan Swaps, and recognized a loss of $20.1 million. In accordance with EITF 00-9, Classification of a Gain or Loss from a Hedge of Debt That Is Extinguished, the loss recognized as the result of early termination of the Swaps and the Term Loan Swaps is presented on our Consolidated Statement of Operations as a derivative loss.
Accounting for Hedges
SFAS No. 133, as amended and interpreted by other related accounting literature, establishes accounting and reporting standards for derivative instruments. Under SFAS No. 133, we are required to record derivatives on our balance sheet as either an asset or liability measured at their fair value, unless exempted from derivative treatment under the normal purchase and normal sale exception. Changes in the fair value of derivatives are recognized currently in earnings unless specific hedge criteria are met. These criteria require that the derivative is determined to be effective as a hedge and that it is formally documented and designated as a hedge.
We determined that the Swaps and the Term Loan Swaps qualified as cash flow hedges within the meaning of SFAS No. 133 and designated them as such. We assessed both at the inception of each of the Swaps and the Term Loan Swaps and on an on-going basis, whether the Swaps and the Term Loan Swaps that were used in our hedging transactions were highly effective in offsetting changes in cash flows of the hedged items. At inception, we determined the hedging relationship of the Swaps and the Term Loan Swaps and the underlying debt to be highly effective. On an on-going basis, we monitored the actual dollar offset of the market values of the Swaps
Index to Financial Statements CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
and the Term Loan Swaps compared to hypothetical cash flow hedges. Any ineffective portion of the cash flow hedges was reflected in earnings. We continued to assess the hedge effectiveness of the Swaps and the Term Loan Swaps on a quarterly basis in accordance with the provisions of SFAS No. 133 until they were terminated in November 2006. Ineffectiveness is the amount of gains or losses from derivative instruments which are not offset by corresponding and opposite gains or losses on the expected future transaction.
SFAS No. 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of accumulated other comprehensive income (“AOCI”) and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. In our case, the impact on earnings was a reduction of interest expense of zero, zero and $7.2 million for 2008, 2007 and 2006, respectively. The ineffective portion of the gain or loss on the derivative instruments, if any, must be recognized currently in earnings. If the forecasted transaction is no longer probable of occurring, the associated gain or loss recorded in AOCI is recognized currently in earnings. For 2008 and 2007, we have recognized a net derivative gain of $4.7 million and zero, respectively.
NOTE 16-ACCRUED LIABILITIES
As of December 31, 2008 and 2007, accrued liabilities consisted of the following (in thousands):
NOTE 17-DEFERRED REVENUE
As of December 31, 2008 and 2007, we had recorded $2.5 million and zero, respectively, as current deferred revenue and $37.5 million and $40.0 million, respectively, as non-current deferred revenue related to advance capacity reservation fee payments.
In November 2004, Total LNG USA, 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 receiving 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 will be amortized over a 10-year period after operations commence as a reduction of Total’s regasification capacity fee under its TUA. As a result, we recorded the advance capacity reservation fee payments that we received, although non-refundable, as deferred revenue to be amortized to income over the corresponding 10-year period.
In November 2004, we 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 receiving 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 and paid Sabine Pass LNG an additional $3.0 million advance capacity reservation fee. As of
Index to Financial Statements CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
December 31, 2008, Chevron USA had made advance capacity reservation fee payments to Sabine Pass LNG totaling $20.0 million. These capacity reservation fee payments will be amortized over a 10-year period as a reduction of Chevron’s regasification capacity fee under its TUA. As a result, we recorded the advance capacity reservation payments that we received, although non-refundable, as deferred revenue to be amortized to income over the corresponding 10-year period.
NOTE 18-LONG-TERM DEBT AND LONG-TERM DEBT-RELATED PARTIES
As of December 31, 2008 and 2007, our long-term debt consisted of the following (in thousands):
Below is a schedule of future principal payments that we are obligated to make on our outstanding long-term debt at December 31, 2008 (in thousands):
Sabine Pass LNG Senior Notes
In November 2006, Sabine Pass LNG issued an aggregate principal amount of $2,032.0 million of Senior Notes, consisting of $550.0 million of the 2013 Notes and $1,482.0 million of 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. The net proceeds from the additional issuance of the 2016
Index to Financial Statements CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Notes were $145.0 million. One of the lenders of the additional issuance of the 2016 Notes is GSO Capital Partners, L.P. (“GSO”), an affiliate of two members of Cheniere’s board of directors. GSO did not receive any fees in connection with making the additional issuance of 2016 Notes. The additional issuance and the previously outstanding 2016 Notes are treated as a single series of notes under the Sabine Pass Indenture. Sabine Pass LNG placed $100.0 million of the $145.0 million of net proceeds from the additional issuance of the 2016 Notes into a construction account to pay construction expenses of cost overruns related to the construction, cool down, commissioning and completion of the Sabine Pass LNG receiving terminal. In addition, Sabine Pass LNG placed $40.8 million of the remaining net proceeds into an account in accordance with the cash waterfall requirements of the security deposit agreement, which are used by Sabine Pass LNG for working capital and other general business purposes.
Sabine Pass LNG placed $335.0 million of net proceeds from the original issuance of the Senior Notes in a reserve account to fund scheduled interest payments on the original Senior 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. 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. In addition, 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 will be permitted only after satisfaction of the foregoing funding requirements, after satisfying a fixed charge coverage ratio test of 2:1 and after satisfying other conditions specified in the Sabine Pass Indenture.
Convertible Senior Unsecured Notes
In July 2005, we consummated a private offering of $325.0 million aggregate principal amount of Convertible Senior Unsecured Notes due 2012 to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended (“Securities Act”). The notes bear interest at a rate of 2.25% 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, 2008, no holders had elected to convert their notes.
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 a 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 Sabine Pass Indenture governing the notes contains customary reporting requirements.
2007 Term Loan
In May 2007, Cheniere Subsidiary Holdings, LLC (“Cheniere Subsidiary”), 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 9.75% 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 net proceeds of $391.7 million from the 2007 Term Loan are being used for general corporate purposes, including our repurchase, completed during 2007, of approximately 9.2 million shares of our outstanding common stock
Index to Financial Statements CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
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. The 2007 Term Loan is secured by a pledge of our 135,383,831 subordinated units in Cheniere Partners and our equity interests in the entities that own our 30% interest in Freeport LNG.
2008 Convertible Loans
In August 2008, we entered into a credit agreement pursuant to which we obtained $250.0 million in convertible term loans (“2008 Convertible Loans”). The 2008 Convertible Loans will mature in 2018, but the lenders can require prepayment of the loan for thirty days following August 15, 2011, 2013 and 2015, and upon a change of control. The 2008 Convertible 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. At our option, until August 15, 2011, accrued interest may be added to the principal on each semi-annual interest date. The aggregate amount of all accrued interest to August 15, 2011 will be payable upon the maturity date. The 2008 Convertible Loans are secured by Cheniere’s rights and fees payable under management services agreements with Sabine Pass LNG and Cheniere Partners, by Cheniere’s common units in Cheniere Partners, by the equity and non-real property assets of Cheniere’s pipeline entities, by the equity of various other subsidiaries and certain other assets and subsidiary guarantees. The principal amount of $250.0 million may be exchanged for newly-created Series B Convertible Preferred Stock, par value $0.0001 per share (“Series B Preferred Stock”) with voting rights limited to the equivalent of 10,125,000 shares of common stock. The exchange ratio is one share of Series B Preferred Stock for each $5,000 of outstanding borrowings, subject to adjustment. The aggregate preferred stock is exchangeable into 50 million shares of common stock at a price of $5.00 per share pursuant to a broadly syndicated offering. No portion of any accrued interest is eligible for conversion into Series B Preferred Stock. We placed $135.0 million of the borrowings under the 2008 Convertible Loans into a TUA reserve account to pay the reservation fee and operating fee as defined under Cheniere Marketing’s TUA. We utilized $95.0 million of the borrowings under the 2008 Convertible Loans to repay the Bridge Loan. The remaining borrowings were utilized to pay for interest on the Bridge Loan, to pay expenses incurred in connection with the issuance of the 2008 Convertible Loans and consideration of other strategic alternatives and to fund working capital and general corporate needs of Cheniere and its subsidiaries.
One of the lenders is Scorpion Capital Partners LP (“Scorpion”), an affiliate of one of the Cheniere’s directors. Scorpion’s portion of the 2008 Convertible Loans was $8.5 million and Scorpion did not receive any fees in connection with making the 2008 Convertible Loans.
As long as the 2008 Convertible Loans are exchangeable for shares of Series B Preferred Stock or shares of Series B Preferred Stock remain outstanding, the holders of a majority of the 2008 Convertible Loans and Series B Preferred Stock, acting together, shall have the right to nominate two individuals to the Company’s Board, and together with the Board, a third nominee, who shall be an independent director.
Bridge Loan
In May 2008, Cheniere Common Units Holding, LLC (“Cheniere Common Units Holding”), a newly formed wholly-owned subsidiary of Cheniere, entered into the Bridge Loan pursuant to which the lenders agreed to make a term loan of $95.0 million to Cheniere Common Units Holding. We received approximately $82.3 million of net proceeds. This loan was repaid in the third quarter of 2008 using a portion of the proceeds from the 2008 Convertible Loans.
Index to Financial Statements CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
NOTE 19-FINANCIAL INSTRUMENTS
We entered into financial derivatives to hedge the exposure to variability in expected future cash flows attributable to the future sale of natural gas from our LNG commissioning cargoes (“LNG commissioning cargo derivatives”). The net cost (LNG commissioning cargo purchase price less natural gas sales proceeds) of our LNG commissioning cargoes is capitalized on our Consolidated Balance Sheet as it is directly related to the LNG receiving terminal construction and is incurred to place the LNG receiving terminal in usable condition. However, changes in the fair value of our LNG commissioning cargo derivatives are reported in earnings because they are not able to be designated as a qualifying hedge in accordance with FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities.
Effective January 1, 2008, we adopted SFAS No. 157, Fair Value Measurements, and SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities-Including an amendment of FASB Statement No. 115. As a result of the adoption, we elected not to measure any additional financial assets or liabilities at fair value, other than those which were recorded at fair value prior to adoption.
The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The financial assets and liabilities at December 31, 2008, measured at fair value on a recurring basis, are summarized below (in thousands):
Trading derivatives relate to positions held by Cheniere Marketing and include exchange-traded derivative contracts and over-the-counter derivative contracts. Other derivatives reflect positions held by Cheniere Marketing on behalf of Sabine Pass LNG related to natural gas swaps entered into to hedge the cash flows from the sale of excess LNG purchased for commissioning.
SFAS No. 107, Disclosures about Fair Value of Financial Instruments, requires the disclosure of the estimated fair value of financial instruments including those financial instruments for which the SFAS No. 159 fair value option was not elected. The carrying amounts reported on the Consolidated Balance Sheets for cash and cash equivalents, restricted cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to their short-term nature. The carrying amounts of the fair values of financial instruments for which SFAS No. 159 was not elected are as follows:
Financial Instruments (in thousands):
Index to Financial Statements CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
(1) The fair value of the Senior Notes, net of discount, is based on quotations obtained from broker-dealers who made markets in these and similar instruments as of December 31, 2008 and December 31, 2007, as applicable.
(2) The fair value of our Convertible Senior Unsecured Notes is based on the closing trading prices on December 31, 2008 and December 31, 2007, as applicable.
(3) The 2007 Term Loan bears interest at a fixed rate; therefore, the estimated fair value is expected to vary with changes in market interest rates. At December 31, 2008 and December 31, 2007, the fair value of the debt instrument was stated at its carrying amount due to it being a non-trading instrument with no liquid market.
(4) The 2008 Convertible Loans bear interest at a fixed rate; therefore, the estimated fair value is expected to vary with changes in market interest rates. At December 31, 2008, the fair value of the debt instrument was stated at its carrying amount due to it being a non-trading instrument with no liquid market.
(5) The fair value of our restricted U.S. Treasury securities is based on quotations obtained from broker-dealers who made markets in these and similar instruments as of December 31, 2008 and December 31, 2007, as applicable.
NOTE 20-INCOME TAXES
Income tax (provision) benefit included in our reported net loss consisted of the following (in thousands):
From our inception, we have reported net operating losses for both financial reporting purposes and for federal, international and state income tax reporting purposes. Accordingly, we are not presently a taxpayer and have not recorded a net liability for federal, international or state income taxes in any of the years included in the accompanying financial statements. Our Consolidated Statement of Operations for the year ended December 31, 2006 included a deferred income tax provision of $2.0 million. The deferred income tax provision was recorded in accordance with the guidance in paragraph 140 of SFAS No. 109 and EITF Abstracts, Topic D-32 which requires items reported in accumulated other comprehensive income (“AOCI”) to be stated separately from the tax benefits associated with a loss from continuing operations. In our specific situation, the circumstance relates to after-tax Other Comprehensive Income (“OCI”) of $3.8 million (consisting of pre-tax OCI income of $5.8 net of the related deferred federal income tax expense of $2.0 million) that was recorded for the year ended December 31, 2005 related to our Swaps and Term Loan Swaps.
The reconciliation of the federal statutory income tax rate to our effective income tax rate follows:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Deferred tax assets and liabilities reflect the net tax effect of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and amounts used for income tax purposes. Significant components of our deferred tax assets and liabilities at December 31, 2008 and 2007 are as follows (in thousands):
FIN No. 48
In July 2006, the FASB issued FIN No. 48, Accounting for Uncertainty in Income Taxes-An Interpretation of FASB Statement No. 109. FIN No. 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, Accounting for Income Taxes. It prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This new standard also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition rules. The Company adopted the provisions of FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, on January 1, 2007. On the date of adoption, we determined that all of the material tax positions taken in our income tax returns previously filed and tax positions to be taken in our future income tax returns with respect to items originating before January 1, 2007 met the more likely-than-not recognition threshold prescribed by FIN No. 48.
During 2007, we recognized $54.4 million of deferred tax benefits for tax positions related to the accelerated recovery of a substantial portion of the costs of the Sabine Pass LNG receiving terminal for which the ultimate deductibility was highly certain, but for which there was some uncertainty corresponding to the timing
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
of the related prior, current and future year tax deductions. During the first quarter of 2008, based on discussions with representatives from the relevant taxing authorities, we determined that the deferred tax benefits associated with the accelerated depreciation deductions would not be available in 2007. Therefore, during the first quarter of 2008 we reduced the amount of the deferred tax benefits recognized in 2007 by $54.4 million and reduced our FIN No. 48 liability by the same amount. At December 31, 2008, we had $22.2 million of unrecognized federal income tax benefits that pertain to tax positions taken in the current and prior years for which there is still some uncertainty as to the timing of the corresponding tax deductions, but which the ultimate deductibility is highly certain. Under SFAS No. 109, the timing of the corresponding tax deductions will not affect our annual reported effective income tax rate in any of the prior, current or future financial reporting periods, but could result in the acceleration of tax payments for a prior reporting period. Adjustments to our federal taxable income in prior tax reporting periods would largely be offset by our available net operating loss (“NOL”) carryovers, and therefore, the potential underpayment of tax, interest and penalties have not been accrued with respect to this liability.
It is not likely that the amount of our unrecognized tax benefits will decrease significantly within the next twelve months. To date, the adoption of FIN No. 48 has had no impact on our financial position, results of operations or cash flows. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in thousands):
During the first quarter of 2008, we resolved the uncertainty related to the tax positions associated with the timing of the current and future tax deductions for a substantial portion of our 2007 capital costs. Therefore, we reduced the deferred tax benefits that were recognized in 2007 by $54.4 million which caused us to reduce our FIN No. 48 liability in the first quarter of 2008 by an equal amount. As discussed above, we have not previously recorded a liability for international, federal or state income taxes and therefore we have not been subject to any penalties or interest expense related to any income tax liabilities. In future reporting periods, if any interest or penalties are imposed in connection with an income tax liability, we expect to include both of these items in the our income tax provision.
Our federal consolidated income tax returns filed to date have not been audited by the Internal Revenue Service; we have not been notified of any pending federal, state or international income tax audits. We have not entered into any agreements with any taxing authorities to extend the period of time in which they may assert or assess additional income tax, penalties or interest. However, because we are presently in an NOL carryover position and have been since our inception, under the applicable Internal Revenue Service (“IRS”) guidelines, in the event of an audit, our available federal NOL carryover amount is subject to adjustment until the normal three-year federal statute of limitations closes for the year in which the NOL is fully utilized. The Texas Comptroller’s Office recently completed an audit of Cheniere’s Texas franchise tax returns for the three-year period ended December 31, 2004; the Louisiana Department of Revenue recently completed an income and franchise audit of Cheniere and one of our wholly-owned affiliates for the two-year period ended December 31, 2003. We expect that all of our significant operating affiliates will be audited by the States of Texas and Louisiana for annual tax reporting periods ended on or after December 31, 2004. To date, all of the state-level income tax audits have
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
been settled favorably and without changes. None of our foreign affiliates have been audited by any foreign taxing authorities and none have been notified of any pending income tax audits.
At December 31, 2008, our NOL carryforward for financial and tax reporting purposes were $392.1 million and $510.6 million, respectively. Our tax NOL carryforward exceeds our financial NOL carryforward because our financial NOL carryforward does not include $63.4 million of deductions related to our uncertain tax positions as discussed above, and $55.1 million of share-based compensation deductions as provided for in SFAS No. 123R. Both amounts have been included in our tax NOL carryforward amount. The full amount of the deferred tax benefit attributable to our financial NOL has been included in our deferred tax asset valuation allowance.
As discussed in Note 21-”Share-Based Compensation”, we adopted SFAS No. 123R effective January 1, 2006. For companies like Cheniere that have NOL carryforwards, SFAS No. 123R affects the manner in which share-based compensation tax deductions are treated for financial reporting purposes. We may claim share-based compensation deductions in our federal corporate income tax returns in an amount equal to the related income that is included in our employees’ reported federal taxable income subject to any other applicable limitations. Under SFAS No. 123R, tax benefits generated in 2006 and subsequent reporting periods related to the excess of tax deductible share-based compensation over the amount recognized for financial accounting purposes may not be recorded to additional paid-in-capital (“APIC”) for financial reporting purposes until the share-based compensation deductions actually reduce our cash income tax liability. Any tax benefits attributable to these deductions will not be recorded to APIC for financial reporting purposes until such time as all existing and future NOL carryforwards have been fully utilized.
Our federal NOL carryforwards are subject to expiration starting in 2011 extending through 2028. In addition to the normal NOL expiration rules, Internal Revenue Code (“IRC”) Section 382 imposes additional limitations on a corporation’s ability to utilize its NOL carryforwards in the tax years following an “ownership change.” For this purpose, an ownership change results from stock transactions that increase the ownership of certain existing and new stockholders in the corporation by more than 50 percentage points during a three preceding year testing period. The minimum annual NOL utilization limitation amount is determined first by multiplying the company’s market capitalization value on the ownership change date by the applicable federal interest rate that generally ranges between three and five percent. The amount of the limitation may, under certain circumstances, be increased to reflect both recognized and deemed recognized “built-in gains” that occur, or are deemed to occur, during the five-year period immediately following the ownership change. Any unused annual limitation may be carried over to later years. Several ownership changes in our stock have occurred between 1998 and 2007 that subjected our NOL carryforwards that existed in those years to the annual NOL utilization limitations provided for in Section 382. However, the annual NOL utilization limitations applicable to these ownership changes have not had a material impact on our ability to utilize the NOL carryforwards generated in prior years.
During the second quarter of 2008, largely due to the increased level of trading activity in our shares, we experienced an ownership change that will subject approximately $300 million of our existing tax NOL carryforwards to the annual NOL utilization limitations under Section 382. However, we do not believe that the applicable NOL utilization limitations will significantly affect our ability to fully utilize our existing tax NOL carryforwards after consideration of the additional limitation created by deemed recognition of built-in gains in the five-year period following this change.
At December 31, 2008, we also have a capital loss carryforward of $62.6 million that may be carried forward for up to five years. The capital loss carryforward represents the portion of our 2008 restructuring charges that represent capital losses for federal income tax reporting purposes. This carryforward may only be
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
used to reduce future year gains derived from the sale or exchange of investments or other capital assets. The portion of our capital loss carryover that is not utilized within the five-year carryforward period is subject to expiration. The full amount of the deferred tax benefit attributable to our capital loss carryforward has been included in our deferred tax asset valuation allowance.
In accordance with SFAS No. 109, a valuation allowance equal to our net deferred tax asset balance has been established due to the uncertainty of realizing the tax benefits related to our net operating loss carryforwards, our capital loss carryforward and our other deferred tax assets. The change in the deferred tax asset valuation allowance was $117.4 million and $62.9 million for the years ended December 31, 2008 and 2007, respectively.
NOTE 21-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”). Effective January 1, 2006, we adopted SFAS No. 123R (revised 2004), Share-Based Payment, which revised SFAS No. 123 and superseded Accounting Principles Bulletin (“APB”) No. 25. No adjustments to prior periods were made as a result of adopting SFAS No. 123R. SFAS No. 123R requires that all share-based payments to employees be recognized in the 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 under SFAS No. 123R. We consider many factors when estimating expected forfeitures, including types of awards, employee class and historical experience.
For the years ended December 31, 2008, 2007 and 2006 the total share-based compensation expense recognized in our net loss (net of capitalization) was $55.0 million, $56.6 million and $21.8 million, respectively. As required by SFAS No. 123R, 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, 2008 and 2007, the cumulative adjustment recognized in our compensation expense was $14.5 million and $4.8 million, respectively. For the years ended December 31, 2008, 2007 and 2006, the total share-based compensation cost capitalized as part of the cost of capital assets was $2.4 million, $1.7 million and $1.6 million, respectively.
The impact of adopting SFAS No. 123R on our results of operations for the year ended December 31, 2006 was an increase in expenses of $17.3 million, with a corresponding increase in our loss from operations, loss before income taxes and minority interest, and net loss resulting from the first-time recognition of compensation expense associated with employee stock options. The impact on our basic and diluted net loss per common share was an increase in per share net loss of $0.32.
The total unrecognized compensation cost at December 31, 2008 relating to non-vested share-based compensation arrangements granted under the 1997 Plan and 2003 Plan, before any capitalization, was $20.9 million. That cost is expected to be recognized over 4.0 years, with a weighted average period of 1.08 years.
Tax deductions are generally available to us in an amount equal to the share-based compensation income included in the taxable income of our employees, to the extent our corporate-level tax deductions are not otherwise limited by Section 162(m) of the IRC. As previously discussed in Note 20-“Income Taxes”, SFAS
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No. 123R specifically provides that tax benefits associated with share-based payments to employees may not be recognized unless or until the corresponding tax deductions have reduced current taxes payable. As a result of our cumulative NOL carryovers and resulting valuation allowance, the tax benefits associated with deductions related to share-based payments to employees will not be recognized for financial reporting purposes until such time as all existing and future NOLs have been utilized.
The adoption of SFAS No. 123R had no effect on our net cash flow. Had we been a taxpayer, we would have recognized cash flow resulting from tax deductions in excess of recognized compensation cost as a financing cash flow. We received total proceeds from the exercise of stock options of $0.5 million, $3.2 million and $2.0 million in the years ended December 31, 2008, 2007 and 2006, respectively.
Phantom Stock
In May 2007, the Company established the 2007 Incentive Compensation Plan (“2007 Plan”) and the 2008-2010 Incentive Compensation Plan (“2008-2010 Plan”) covering executive officers and other key employees for the performance periods of 2007, 2008, 2009 and 2010. A total of 537,000 and 1,794,000 shares of phantom stock were granted under the 2007 Plan and 2008-2010 Plans, respectively, payable in shares of our common stock upon achievement of stock price hurdles established by the plans. Using a Monte Carlo simulation, fair values were calculated for the performance periods 2008, 2009 and 2010, respectively and a projected earnings date was also forecasted on which the stock price hurdle would be achieved for the award related to each performance period. The fair value of the award for each performance period was to be amortized as compensation expense ratably from the date of plan approval to the date expected to be earned. In January 2008, 537,000 of shares of our common stock were issued as the stock price hurdle for the 2007 Plan was achieved. During the fourth quarter of 2008, certain executives and key employees forfeited 1,041,000 shares of their 2008-2010 phantom shares with no concurrent consideration. In connection with the cancellation of the phantom shares, a total of $5.1 million of unrecognized compensation cost was recognized.
Stock Options
We estimate the fair value of stock options under SFAS No. 123R at the date of grant using a Black-Scholes valuation model, which is consistent with the valuation technique we previously utilized to value stock options for the footnote disclosures required under SFAS No. 123. 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 allowed by SAB No. 107, Valuation of Share-based Payment Agreements for Public Companies, 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 year ended December 31, 2008.
During 2005 and 2006, retention stock options were granted to executives and key employees as a future incentive for employment. The retention grants included vesting periods beginning in 2009 through 2012 as well as exercise prices ranging from $36.25 to $90.00. During the fourth quarter of 2008, certain executives and key employees forfeited 2,000,000 shares of their out-of-the-money option retention grants with no concurrent consideration. In connection with the cancellation of the phantom shares, a total of $19.6 million of unrecognized compensation expense was recorded.
Index to Financial Statements CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
During 2007, we issued options to purchase 20,000 shares of our common stock under the 2003 Plan to employees as hiring incentives, having an exercise price equal to the stock price on the date of grant, graded vesting over four years, and a 10-year contractual life.
During 2006, we issued options to purchase 501,000 shares of our common stock under the 2003 Plan. This included options to purchase 131,000 shares, granted to employees primarily as hiring incentives, having an exercise price equal to the stock price on the date of grant, graded vesting over four years, and a 10-year contractual life; an option to purchase 300,000 shares granted to our Chairman of the Board of Directors and Chief Executive Officer having an exercise price of $90.00, graded vesting over three years beginning in March 2010, and a 10-year contractual life; fully vested options to purchase a total of 50,000 shares granted to two of our directors having an exercise price equal to the stock price on the date of grant and a 10-year contractual life; and an option to purchase 20,000 shares having an exercise price equal to the stock price on the date of grant, graded vesting over two years, and a five-year contractual life granted to a consultant in exchange for services. These options are being accounted for in accordance with the guidance in SFAS No. 123R, with the exception of the consultant grant, which is being accounted for in accordance with the relevant accounting guidance for equity instruments granted to a non-employee.
The table below provides a summary of option activity under the combined plans as of December 31, 2008:
The weighted average grant-date fair value of options granted during the years ended December 31, 2008, 2007 and 2006 was zero, $19.44 and $23.07, respectively. The total intrinsic value of options exercised during the years ended December 31, 2008, 2007 and 2006 was $1.0 million, $19.3 million and $12.0 million, respectively.
Effective March 28, 2007, 69 employee stock option grants were amended to provide for acceleration of vesting upon termination under certain circumstances, within one year of a change of control event, or upon the death or disability of the stock option holder. This amendment did not have an impact on our assessment of stock options ultimately expected to vest, and, therefore, resulted in no change in their valuation of our forfeiture assumptions.
Stock and Non-Vested Stock
We have granted stock and non-vested (restricted) stock to employees, executive officers, outside directors and consultants under the 2003 Plan. Under SFAS No. 123R, grants of non-vested stock are accounted for on an intrinsic value basis. No recognition of deferred compensation is made in stockholders’ equity. Instead, the amortization of the calculated value of non-vested stock grants is accounted for as a charge to compensation and
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
an increase in additional paid-in-capital over the requisite service period. With the adoption of SFAS No. 123R, we offset the remaining unamortized deferred compensation balance ($9.7 million at December 31, 2005) in stockholders’ equity against additional paid-in-capital. Amortization of the remaining unamortized balance will continue under SFAS No. 123R as described above.
In January 2008, 479,802 shares having three-year graded vesting were issued to our employees in the form of non-vested stock awards and 537,000 shares were issued to our executive officers in the form of vested stock awards related to our performance in 2007. In May 2008 and June 2008, as a part of the short-term and long-term retention plans approved by the Compensation Committee, 374,000 shares vesting on December 1, 2008 and 1,525,000 shares having a three-year graded vesting beginning December 31, 2008 were issued to our employees and a consultant in the form of non-vested stock awards. In December 2008, 1,702,600 non-vested stock having a three year graded vesting were issued to employees as an incentive award. During 2008, an additional 272,000 shares having a one-year graded vesting were issued to our directors and 26,000 shares of non-vested stock having three- or four-year graded vestings were issued to employees.
In January 2007, 630,000 shares having three-year graded vesting were issued to our employees and executive officers in the form of non-vested stock awards related to our performance in 2006. In May 2007, 31,000 shares having a one-year graded vesting were issued to our directors. In June 2007 and November 2007, 150,000 shares were issued as retention grants to certain employees vesting 50% on December 1, 2008, 30% on December 1, 2009, and 20% on June 1, 2010. In 2007, an additional 250,000 shares of non-vested stock having three or four-year graded vestings were issued primarily to new employees.
On May 25, 2007, the Compensation Committee of our Board of Directors 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.
During 2006, 30,000 and 79,000 shares having three-year graded vesting were issued to our directors and certain of our executive officers, respectively. During the year ended December 31, 2006, a total of 241,000 shares of stock having four-year graded vesting were issued primarily to new employees.
The table below provides a summary of the status of our non-vested shares under the 2003 Plan as of December 31, 2008, (in thousands except for per share information):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The weighted average grant-date fair values of non-vested stock granted during the years ended December 31, 2008, 2007 and 2006 were $9.40, $31.99 and $35.60, respectively. The total grant-date fair values of shares vested during the years ended December 31, 2008, 2007 and 2006 were $6.8 million, $7.8 million and $5.4 million, respectively.
Share-based Plan Descriptions and Information
Our 1997 Plan provided 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. Option terms for the remaining unexercised options are five years with vesting that generally occurs on a graded basis over three years.
Awards providing for the issuance of up to an aggregate of 11.0 million shares of our common stock may be made under our 2003 Plan. 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, bonus stock and phantom shares. In general, stock options granted to employees as hiring incentives were granted at the money with 10-year terms and graded vesting over four years. Retention grants made to employees have provided for exercise prices at or in excess of the stock price on the grant date, 10-year terms and graded vesting over three years. Restricted stock that has been granted as a hiring incentive vests over three or four years on a graded basis, while restricted stock granted from a bonus pool generally vests over three years. Shares issued under the 2003 Plan are generally newly issued 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 $2.3 million, $1.8 million and $0.9 million for the years ended December 31, 2008, 2007, and 2006, respectively. We have made no discretionary contributions to the 401(k) Plan to date.
NOTE 22-COMPREHENSIVE LOSS
The following table is a reconciliation of our net loss to our comprehensive loss for the periods shown (in thousands):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
NOTE 23-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 receiving terminal.
Freeport LNG
Under the limited partnership agreement of Freeport LNG, development expenses of the Freeport LNG project and other Freeport LNG cash needs generally are to be funded out of Freeport LNG’s own cash flows, borrowings or other sources, and, up to a pre-agreed total amount, with capital contributions by the limited partners. In December 2005, Freeport LNG announced that it had closed a $383.0 million private placement of notes, which would be used to fund the remaining portion of the initial phase of the project, a portion of the cost of expanding the LNG receiving terminal and development of underground salt cavern gas storage. We do not anticipate that any capital calls will be made upon the limited partners of Freeport LNG in the foreseeable future. Capital calls may be made upon us and the other limited partners in Freeport LNG and in the event of each such future capital call, we will have the option either to contribute the requested capital or to decline to contribute. If we decline to contribute, the other limited partners could elect to make our contribution and receive back twice the amount contributed on our behalf, without interest, before any Freeport LNG cash flows are otherwise distributed to us. We currently expect to evaluate Freeport LNG capital calls on a case-by-case basis and to fund additional capital contributions that we elect to make using cash on hand or funds raised through the issuance of Cheniere equity or debt securities or other Cheniere borrowings.
Under a settlement agreement dated as of June 14, 2001, we agreed 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. The Freeport LNG and Sabine Pass LNG receiving terminals are covered facilities. The Crest Royalty is subject to a maximum of approximately $11.0 million per production year at throughput of approximately 1.0 Bcf/d and a minimum of $2.0 million. The Crest Royalty will be payable after natural gas is first processed on a commercial basis by a covered LNG receiving terminal. That has not occurred at the Sabine Pass LNG facility, and we are advised that it has not occurred at the Freeport LNG receiving terminal. We do not know when or at which LNG receiving terminal the first commercial processing will occur. Freeport LNG has assumed the obligation to pay the Crest Royalty for natural gas processed at Freeport LNG’s receiving terminal. We are advised that Freeport LNG has entered into long-term TUAs, with each of ConocoPhillips Company (“ConocoPhillips”); the Dow Chemical Company (“Dow”) and a subsidiary of Mitsubishi Corporation (“Mitsubishi”), for an aggregate of approximately 1.55 Bcf/d of terminal throughput capacity. The ConocoPhillips TUA is for approximately 0.9 Bcf/d. The Dow TUA is for approximately 0.5 Bcf/d; and the Mitsubishi TUA is for approximately 0.15 Bcf/d.
In March 2008 and May 2008, we received cash call notices from Freeport LNG requesting that we provide further financial support due to higher than expected commissioning and performance testing costs. During 2008, we funded the cash calls and have recorded $4.8 million of additional losses in Freeport LNG. In addition, Freeport LNG distributed $4.8 million to us in October 2008.
Index to Financial Statements CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
LNG Terminal EPC Agreements
In July 2006, Sabine Pass LNG entered into an engineering, procurement, construction and management (“EPCM”) Agreement with Bechtel for engineering, procurement, construction and management of construction services in connection with our 1.4 Bcf/d expansion at the Sabine Pass LNG receiving terminal. Under the terms of the EPCM agreement, Bechtel will be paid on a cost reimbursable basis, plus a fixed fee in the amount of $18.5 million. A discretionary bonus may be paid to Bechtel at Sabine Pass LNG’s sole discretion upon completion of the expansion. As of December 31, 2008, we are committed to make cash payments of approximately $56.5 million in the future pursuant to this contract.
In July 2006, Sabine Pass LNG entered into an EPC LNG Tank Contract with Diamond LNG LLC (“Diamond”) and Zachry Construction Corporation (“Zachry” and collectively with Diamond, the “Tank Contractor”) for the construction of two LNG storage tanks in connection with the 1.4 Bcf/d expansion. Milestone payments for work incurred, minus a 5% retainage that will be paid upon final completion, will be based on a lump-sum, fixed price, subject to adjustments based on fluctuations in the cost of labor and change orders. As of December 31, 2008, we are committed to make cash payments of approximately $23.5 million in the future pursuant to this contract.
Restricted Net Assets
At December 31, 2008, our restricted net assets of consolidated subsidiaries were approximately $250.2 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.
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 and legal counsel, as of December 31, 2008 and 2007, 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 24-BUSINESS SEGMENT INFORMATION
We have three operating business segments: LNG receiving 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 receiving terminal business segment is in various stages of developing three LNG receiving terminal projects along the U.S. Gulf Coast at the following locations: Sabine Pass LNG, approximately 90.6% owned (at December 31, 2008), in western Cameron Parish, Louisiana on the Sabine Pass Channel; Corpus Christi LNG, 100% owned, near Corpus Christi, Texas; and Creole Trail LNG, 100% owned, at the mouth of the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Calcasieu Channel in central Cameron Parish, Louisiana. In addition, we own a 30% limited partner interest in a fourth project, Freeport LNG, located on Quintana Island near Freeport, Texas.
Our natural gas pipeline business segment is in various stages of developing natural gas pipelines to provide access to North American natural gas markets.
Our LNG and natural gas marketing business segment is seeking to develop a portfolio of long-term, short-term, and spot LNG purchase agreements, and will focus on entering into business relationships for the domestic marketing of natural gas that is imported by Cheniere Marketing as LNG to the Sabine Pass LNG receiving terminal.
Index to Financial Statements 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 financial statements. Prior periods were restated to include oil and gas exploration, development and exploitation activities within corporate and other.
(2) Natural gas pipeline income from operations for the year ended December 31, 2006, includes the impact of the regulatory asset recorded in the second quarter of 2006 as prescribed by SFAS No. 71. Not including the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
impact of the recognition of this regulatory asset, natural gas pipeline income from operations would have been a net loss of $4.1 million for the year ended December 31, 2006.
(3) Primarily represents recognized losses on the termination of the Sabine Pass Credit Facility and the Term Loan in November 2006. See Note 18-“Long-Term Debt and Long-Term Debt-Related Parties.”
NOTE 26-SUPPLEMENTAL CASH FLOW INFORMATION AND DISCLOSURES OF NON-CASH TRANSACTIONS
The following table provides supplemental disclosure of cash flow information (in thousands):
During 2007, 688,249 shares of common stock were issued in satisfaction of cashless exercises of options to purchase 731,670 shares of common stock.
Index to Financial Statements 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)
Index to Financial Statements 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
Based on their evaluation as of the end of the fiscal year ended December 31, 2008, 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 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 Report on Internal Control Over Financial Reporting is included in the Financial Statements on page 57 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, 2008.
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
Report of Independent Registered Public Accounting Firm-UHY LLP
Consolidated Balance Sheet
Consolidated Statement of Operations
Consolidated Statement of Stockholders’ (Deficit) Equity
Consolidated Statement of Cash Flows
Notes to Consolidated Financial Statements
Supplemental Information to Consolidated Financial Statements-Summarized Quarterly Financial Data
Index to Financial Statements
(2) Financial Statement Schedules:
Schedule I-Condensed Parent Company Financial Statements for the years ended December 31, 2008, 2007 and 2006
(3) Exhibits:
Index to Financial Statements
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* Incorporated by reference
 Management contract or compensatory plan or arrangement
Index to Financial Statements SCHEDULE I-CONDENSED FINANCIAL INFORMATION OF REGISTRANT-
CHENIERE ENERGY, INC.
CONDENSED BALANCE SHEET
(in thousands)
See accompanying notes to condensed financial statements.
Index to 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.
Index to Financial Statements SCHEDULE I-CONDENSED FINANCIAL INFORMATION OF REGISTRANT-
CHENIERE ENERGY, INC.
CONDENSED STATEMENT OF CASH FLOWS
(in thousands)
SUPPLEMENTAL CASH FLOW INFORMATION AND
DISCLOSURES OF NON-CASH TRANSACTIONS
(1) Amounts represent equity losses of affiliates not funded by Cheniere.
See accompanying notes to condensed financial statements.
Index to Financial Statements 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 sheets. 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, 2008 and 2007, our long-term debt consisted of the following (in thousands):
Below is a schedule of future principal payments that we are obligated to make on our outstanding long-term debt at December 31, 2008 (in thousands):
Long-Term Note-Affiliate
In May 2007, we entered into a $391.7 million long-term note (“Long-Term Note-Affiliate”) with Cheniere Subsidiary Holdings, LLC (“Cheniere Subsidiary”), a newly formed 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 Long-Term Note-Affiliate bear interest equal to the terms of Cheniere Subsidiary’s credit agreement at a fixed rate of 9.75% per annum. Interest is calculated on the unpaid principal amount of the Long-Term Note-Affiliate outstanding and is payable quarterly in arrears on March 31, June 30, September 30 and December 31 of each year. The Long-Term Note-Affiliate will mature on May 31, 2012. The $391.7 million proceeds from the Long-Term 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.
Index to Financial Statements CHENIERE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
NOTE 3-GUARANTEES
Guarantees on Behalf of Cheniere Marketing, LLC
TUA Agreement
Cheniere Marketing, LLC, (“Cheniere Marketing”), formerly Cheniere Marketing, Inc., a wholly owned subsidiary of Cheniere, has a 20-year, firm commitment Terminal Use Agreement (“TUA”) with Sabine Pass LNG, L.P. for regasification capacity at the Sabine Pass LNG receiving terminal. Cheniere Marketing must make the full contracted amount of capacity reservation fee payments under its TUA whether or not it uses any of its reserved capacity. In September 2008, Cheniere Marketing made a capacity reservation fee payment of $15 million for October, November and December of 2008. In December 2008, Cheniere Marketing made a capacity reservation fee payment of $62.7 million for the first three months of 2009. Cheniere Marketing is required to make monthly capacity reservation fee payments aggregating approximately $250 million per year for the period from January 1, 2009, through at least the third quarter of 2028. Cheniere has guaranteed Cheniere Marketing’s obligations under its TUA
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 Cheniere Marketing’s reserved 2.0 Bcf/fd of regasification capacity at the Sabine Pass LNG receiving terminal. 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 Marketing. Many of Cheniere Marketing’s natural gas purchase, sale, transportation and shipping agreements have been guaranteed by Cheniere. These contracts that have been guaranteed by Cheniere have a $18.1 million maximum potential of future payments and various expiration dates. The carrying amount of the liability related to these guaranteed contracts was zero as of December 31, 2008.
Guarantee on behalf of Sabine Pass Tug Services, LLC
In November 2006, Sabine Pass Tug Services, LLC (“Sabine Pass Tug Services”) entered into a marine services agreement for three tugs with Alpha Marine Services, LLC (“Alpha Marine Services”). The initial term of the marine services agreement ends on the tenth anniversary of the service date, with Sabine Pass 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.
Index to Financial Statements 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 26, 2009
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.