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 and prospects.
Risks Relating to Our Financial Matters
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.
From our inception, we have generally incurred operating losses, and we will likely continue to incur operating losses and experience negative operating cash flow for at least the next two years. We have not yet started the construction of two of our three planned LNG receiving terminals or our pipelines. We do not anticipate that our LNG receiving operations or our three pipelines will generate positive operating cash flow until at least one of our planned LNG receiving terminals is built, which we expect will not be until 2008 at the earliest. Although we may commence operations at our LNG receiving terminals, revenues under any particular TUA may not commence for up to one year or more after operations at the related facility commence. We will continue to incur significant capital and operating expenditures while we develop our planned LNG receiving terminals and pipelines. We do not anticipate that our current oil and gas exploration activities, which are limited in scope, or advance sales of regasification capacity at our planned LNG receiving terminals will generate sufficient funds to cover these expenditures. As a result, we expect to continue to have operating losses and negative operating cash flow on a quarterly and an annual basis for at least the next two years.
Any delays beyond the expected development periods for our planned LNG receiving terminals or pipelines would prolong, and could increase the level of, our operating losses and negative operating cash flow. Our future liquidity may also be affected by (i) the timing of construction financing availability in relation to the incurrence of construction costs and other outflows and (ii) 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. However, many factors (including factors beyond our control) could result in a disparity between liquidity sources and cash needs, including factors such as construction delays and breaches of agreements. Our ability to generate positive operating cash flow and achieve profitability in the future is dependent on our ability to successfully complete our LNG development projects and market the capacity of our facilities, and our ability to do so is subject to a number of risks, including those discussed below.
Our ability to develop our planned LNG receiving terminals and pipelines 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.
As of December 31, 2005, we had $693 million in cash and cash equivalents, exclusive of $177 million in restricted cash. We currently estimate that the cost of completing our three LNG receiving terminals will be approximately $3.0 billion, before financing costs, and the cost of constructing our three proposed pipelines will be approximately $800 million to $1 billion. Our cost estimate is subject to change due to such items as cost overruns, change orders under existing or future EPC agreements, changes in commodity prices (particularly steel), escalating labor costs and additional funds that may need to be expanded to maintain construction schedules. In addition, the development of our marketing business will require the expenditure of funds before any revenues are received. To fund these development projects, we will have to draw on our Sabine Pass Credit Facility and pursue a variety of additional sources of funding, including most, if not 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; and
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asset sales, to the extent permitted, and joint venture arrangements by Cheniere and/or our subsidiaries.
Our ability to obtain these types of financing 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 and such markets’ view of our industry and prospects at such time. Accordingly, we may not be able to obtain financing on terms that are acceptable to us, if at all, even if our development projects are otherwise proceeding 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. Any project-level debt financing will also typically be conditioned upon our prior receipt of commitments for a portion of projected regasification capacity under long-term TUAs, and our ability to fund the projects will likely be subject to the achievement of additional milestones in our project financing. A failure to obtain financing at any point in the development process could cause us to delay or fail to complete our business plan, which could cause our business to be unsuccessful.
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 certain 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 LNG projects would reduce our interest in future revenues once the LNG receiving terminals 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 of our common stock;
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sales of oil and gas exploration prospects would reduce potential future revenues from our exploration and production activities;
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our ability to borrow funds under some project financing arrangements will likely be subject to our satisfying the conditions and covenants in the financing and the construction schedule agreed to at the time we enter into such arrangement. If circumstances change, we may 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 may be required to make equity contributions before we can borrow under certain financing arrangements, such as the Sabine Pass Credit Facility.
The actual construction costs of our proposed LNG receiving terminals and pipelines may be significantly higher than our current estimates, which are before financing costs.
We do not have any prior experience in constructing LNG receiving terminals or pipelines, and no LNG receiving terminal has been constructed in the United States in over 25 years. As construction progresses, we may decide or be forced to submit change orders to our EPC contractors that could result in longer construction periods and higher construction costs. Similarly, we may encounter significant cost overruns during some phases of the construction process. In addition, under any agreement with an EPC contractor, we expect to retain the commodity price risk for nickel and various types of steel used in the construction process. As a result, any significant change orders, cost overruns or increases in the commodity price of nickel or steel could have a material adverse effect on our business, results of operations, financial condition and prospects.
Risks Relating to Our LNG Receiving Terminal Development Business
The construction of our planned LNG receiving terminals is subject to a number of development risks, which could cause cost overruns and delays or prevent completion of one or more of our LNG development projects.
Key factors that may affect the timing of, and our ability to complete, our LNG development projects include, but are not limited to:
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the issuance and/or continued availability of necessary permits, licenses and approvals from FERC, other governmental agencies and third parties as are required to construct and operate the facilities;
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the availability of sufficient debt financing and equity financing, both on the part of Cheniere and at the project level;
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our ability to obtain satisfactory long-term TUAs with “anchor tenant” customers for a portion of the capacity at each proposed LNG receiving terminal and for these customers to perform under those TUAs during the terms thereof and to maintain their creditworthiness;
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our ability to enter into a satisfactory agreement with an EPC contractor for each facility and to maintain good relationships with these contractors, and the ability of those EPC contractors to perform their obligations under EPC agreements and to maintain their creditworthiness;
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site development difficulties, including change orders, cost overruns, construction delays and changes in commodity prices (particularly steel);
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unanticipated changes in domestic and international market demand for natural gas or the supply of LNG, which will depend, in part, on supplies of, and prices for, alternative energy sources;
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competition with other domestic and international LNG receiving terminals;
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commercial arrangements for pipelines and related equipment to transport natural gas from each LNG receiving terminal;
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local and general economic conditions;
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catastrophes, such as explosions, fires and product spills;
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resistance in the local community to the development of LNG receiving terminals;
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labor disputes; and
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weather conditions, such as hurricanes.
Delays in the construction of an LNG receiving terminal beyond the estimated development periods, as well as cost overruns, could increase the cost of completion beyond the amounts currently estimated in our capital budget, which could require us to obtain additional sources of financing to fund our operations until the LNG receiving terminal is developed (which could cause further delays). Any delay in completion of the LNG receiving terminals may also cause a delay in the receipt of revenues projected from operation of the facilities or cause a loss of our TUA customers in the event of significant delays. Delays could also erode our competitive advantage of being one of the first companies to develop new LNG receiving terminals. As a result, any significant construction delay, whatever the cause, could have a material adverse effect on our business, results of operations, financial condition and prospects.
Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the development of our LNG receiving terminal business would have a detrimental effect on us and our LNG projects.
The design, construction and operation of LNG receiving terminals are all highly regulated activities. FERC approval under Section 3 of the NGA, as well as several other material governmental and regulatory approvals and permits, is required in order to construct and operate our proposed LNG receiving terminals. Although we
have obtained NGA Section 3 authorization to construct and operate our Sabine Pass and Corpus Christi LNG receiving terminals, we have not yet received an NGA Section 3 FERC order authorizing construction of our Creole Trail project. We also have not obtained several other material governmental and regulatory approvals and permits required in order to construct and operate our proposed LNG receiving terminals. We have no control over the outcome of the review and approval process. We do not know whether or when any such approvals or permits can be obtained, or whether or not any existing or potential interventions or other actions by third parties will interfere with our ability to obtain and maintain such permits or approvals. If we are unable to obtain and maintain the necessary approvals and permits, we may not be able to recover our investment in the projects. Failure to obtain and maintain any of these approvals and permits could have a material adverse effect on our business, results of operations, financial condition and prospects.
We face competition in the LNG receiving terminal development business from competitors with far greater resources and the potential for overcapacity in the LNG receiving terminal marketplace.
Many companies are considering the development of infrastructure in the domestic LNG market, including, without limitation, major oil and gas companies such as ExxonMobil, ConocoPhillips, Royal Dutch/Shell and Chevron. Other energy companies such as Sempra, Tractebel, McMoRan Exploration, Occidental Petroleum, AES, Excelerate Energy and other public and private companies have also proposed developing LNG receiving facilities, both onshore and offshore. Almost all of our competitors have longer operating histories, more development experience, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources than we do. The superior resources that these competitors have available to deploy could allow them to surpass us in terms of the status of their LNG receiving terminal development projects. Among other things, these competitors may not have to rely on external financing.
Industry analysts have predicted that if all of the proposed LNG receiving terminals in North America that have been announced by developers were actually built, there would likely be substantial excess capacity for such terminals in the future. Accordingly, there is a substantial risk that slower-paced LNG receiving terminal development projects may never be completed. Any perception in the LNG receiving terminal marketplace that we may be unable to complete our proposed LNG receiving terminals, because competing projects are further along in their development or otherwise, could have a material adverse effect on our business, results of operations, financial condition and prospects.
In addition, our proposed LNG receiving terminals will likely continue to face competition when and if they are completed, including competition from North American sources of natural gas and onshore, offshore and shipboard LNG regasification facilities. Our proposed Sabine Pass, Corpus Christi and Creole Trail LNG receiving terminals will also compete with the Freeport LNG receiving terminal in which we own a 30% interest. If the number of LNG receiving terminals built outstrips demand for natural gas from those terminals, the excess capacity will likely lead to a decrease in the prices that we will be able to obtain for uncommitted amounts of our regasification services. Because of the substantial likelihood that we will have significant debt service obligations, any such price decreases would impact us more severely than our competitors with greater financial resources. Accordingly, potential overcapacity in the LNG receiving terminal marketplace, or a significant decline in natural gas prices, could have a material adverse effect on our business, results of operations, financial condition and prospects.
Cyclical changes in the demand for LNG regasification capacity may result in reduced operating revenues and may cause operating losses in the future.
The economics of LNG terminal and marketing operations 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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significant additions in regasification capacity, whether through LNG receiving terminal construction or expansion, take several years to become operational and are therefore necessarily based upon estimates of future demand for natural gas;
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when demand for natural gas increases, competition to build new LNG regasification capacity may heighten because new capacity may be more profitable, with a lower marginal cost of production;
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when LNG regasification capacity significantly increases, the competition for the receipt and regasification of LNG increases;
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under-supplies at the foreign supply source of LNG also increase competition among LNG terminals and may cause LNG receiving terminal operators to compete aggressively on price in order to maximize capacity utilization;
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when demand for LNG receiving capacity decreases, the high fixed cost structure of capital-intensive LNG receiving terminals causes producers and transporters of natural gas to compete aggressively on price in order to maximize capacity utilization;
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substantial increases in the receiving capacity of LNG receiving terminals will substantially increase the potential supply of natural gas to U.S. markets, which could substantially amplify the downswings related to the over-supply of available natural gas;
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supplies of, and prices for, alternative energy sources such as coal, oil, nuclear, hydroelectric, wind and solar energy cause changes in the demand for natural gas;
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as competition in natural gas is focused on price, being a low-cost supplier is critical to profitability. This would favor the construction of larger LNG receiving facilities, which maximize economies of scale, but also could cause an increase in capacity that can outstrip the existing growth in demand for natural gas; and
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cyclical trends in general business and economic conditions cause changes in the demand for natural gas.
The increases and decreases in the available supply of natural gas as a result of changes in available LNG receiving capacity available could materially adversely affect our business, results of operations, financial condition and prospects.
We may have difficulty obtaining enough customers for regasification capacity at our proposed LNG receiving terminals to implement and complete our business plan. We may change our business strategy as to how and when we market our capacity.
Our current marketing strategy calls for us to enter into long-term TUAs covering approximately 4 Bcf/d of our total existing and future regasification capacity at our LNG receiving terminals, including a commitment to pay capacity reservation fees, prior to the commencement of construction of each facility. 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 project-level financing for each LNG receiving facility may be contingent on our ability to enter into long-term TUAs covering approximately 4 Bcf/d of regasification capacity in advance of the commencement of construction. In addition, we anticipate that we will be able to rely on these capacity reservation fee payments to cover a portion of operating costs prior to commencement of operations at our proposed LNG receiving terminals. As of the date of this filing, we do not have any TUAs in place for either our proposed Corpus Christi facility or our proposed Creole Trail facility nor do we have any contracts in place for the use of our pipelines.
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 LNG receiving terminal sites and natural gas pipelines that we are developing and that they will be approved by appropriate governmental agencies. We may also change our marketing strategy due to our inability to enter into TUAs prior to construction and our view regarding future prices, demand and supply of natural gas and regasification capacity. If these marketing efforts are not successful, our business, results of operations, financial condition and prospects could be materially adversely affected.
Failure of imported LNG to become a competitive source of energy in the United States could have a detrimental effect on our ability to implement and complete our business plan.
In the United States, due mainly to an abundant supply of natural gas, imported LNG has not historically been a major energy source. Our business plan is based on the belief that LNG can be produced and delivered to the United States 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 would further increase the available supply of natural gas at a lower cost than LNG. In addition to natural gas, LNG also competes with other sources of energy, including coal, oil, nuclear, hydroelectric, wind and solar energy. As a result, LNG may not become a competitive source of energy in the United States. The failure of LNG to become a competitive supply alternative to domestic natural gas, oil and other import alternatives could have a material adverse effect on our business, results of operations, financial condition and prospects.
The inability to import LNG into the United States due to, among other things, governmental regulation or potential instability in countries that supply natural gas, could materially adversely affect our business plans and results of operations.
Upon completion of the LNG receiving terminals, our business will be dependent upon the ability of our third-party customers and Cheniere Marketing to import LNG supplies into the United States. Political instability in foreign countries that have supplies of natural gas, or strained relations between such countries and the United States, may impede the willingness or ability of LNG suppliers in such countries to export LNG to the United States. Such foreign suppliers may also be able to negotiate more favorable prices with other LNG customers around the world than with us and other customers in the United States, thereby reducing the supply of LNG available to be imported into the United States market. In addition, we believe that the existing fleet of tankers that is available to transport LNG is inadequate, and the failure to expand LNG tanker capacity would impede both our and our customers’ ability to import LNG into the United States. Any significant impediment to the ability to import LNG into the United States could have a material adverse affect on our business, results of operations, financial condition and prospects.
Decreases in the price of natural gas in North America could harm our ability to develop our proposed LNG receiving terminals and market the sale of natural gas.
The development of domestic LNG receiving terminals is based on assumptions about the future price of natural gas and the availability of imported LNG. The willingness of potential customers to contract for regasification capacity would be negatively impacted and, once facilities are in operation, LNG throughput volumes would likely decline if the price of natural gas in North America is, or is forecasted to be, lower than the cost to produce and deliver LNG to North American markets. Any significant decline in the price of natural gas could cause the cost of natural gas produced from imported LNG to be higher than domestically produced natural gas. As a result, any significant decline in the price of natural gas could have a material adverse effect on our business, results of operations, financial condition and prospects.
Natural gas prices have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to any of the following factors:
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relatively minor changes in the supply of, and demand for, natural gas;
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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 consumer demand;
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weather conditions;
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the competitive position of natural gas as a source of energy as compared with other energy sources; and
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the effect of federal and state regulation on the production, transportation and sale of natural gas.
Our TUAs are subject to termination by our contractual counterparties under certain circumstances, and we are generally dependent on the performance of those counterparties under the TUAs.
Sabine Pass LNG has entered into long-term TUAs with subsidiaries of Total S.A. and Chevron. Each of the TUAs contains various termination rights. For example, Total may terminate its TUA with Sabine Pass LNG if Sabine Pass LNG fails to deliver a specified amount of natural gas nominations or fails to receive or unload a specified number of cargoes. In addition, in the case of each of our TUAs, we are dependent on the respective counterparties’ creditworthiness and their continued willingness to perform their obligations under the TUAs. If any of these counterparties fails to perform its obligations under its respective TUA, our business, results of operations, financial condition and prospects could be materially adversely affected, even if we were to be ultimately successful in seeking damages from that counterparty for a breach of the TUA.
The construction of our proposed LNG receiving terminals will be dependent on performance by, and our relationship with, the contractors that we engage at each facility.
Sabine Pass LNG entered into an EPC agreement in December 2004 with Bechtel. We also plan to enter into contracts with a major international EPC contractor for the construction of our proposed Corpus Christi and Creole Trail LNG receiving terminals. The success of our LNG receiving terminal development projects is highly dependent on our ability to enter into acceptable contracts with reputable EPC contractors and other contractors performing portions of the construction on our projects and for such contractors to perform their obligations under the contracts, including completing the projects on a timely basis. However, we may not be able to enter into acceptable contracts for the construction of Phase 2 of our Sabine Pass LNG receiving terminal or our proposed Corpus Christi or Creole Trail LNG receiving terminals. Other than with respect to Phase 1 of our Sabine Pass LNG receiving terminal, we have no prior experience working with any EPC contractor, including Bechtel, or other construction contractor. We may encounter unexpected delays or problems in connection with the construction of any of our proposed LNG receiving terminals. In addition, any EPC agreement could be terminated by an EPC contractor under certain circumstances prior to completion of construction. For example, see the description of the termination provisions of the EPC agreement with Bechtel under “-LNG Receiving Terminal Development Business-Our LNG Receiving Terminals-Sabine Pass LNG-EPC Agreement” above. If our relationship with any initial EPC contractor fails for any reason, we would be forced to engage a substitute contractor, which would likely result in a significant delay in our development schedule and could have a material adverse effect on our business, results of operations, financial condition and prospects.
Risks Relating to Our Pipeline Development Business
Expanding our business by constructing 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 or at all or at the budgeted cost. For instance, if we build a new pipeline, the construction will 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. The success of our pipeline construction project may depend upon the level of LNG import activity in the areas proposed to be serviced by the project as well as our ability to obtain commitments from LNG suppliers and other customers to utilize the newly constructed pipelines.
Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the development of our pipelines would have a detrimental effect on us and our LNG 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, is required in order to construct and operate our proposed pipelines. We have obtained authorization from FERC pursuant to Section 7(c) of the NGA to construct and operate our Sabine Pass and Corpus Christi pipelines, subject to certain conditions. However, we have not yet received authorization from FERC to construct and operate our Creole Trail pipelines. We also have not obtained several other material governmental and regulatory approvals and permits required in order to construct and operate our proposed pipelines. We have no control over the timing of the review and approval process nor can we predict the outcome of the process. We do not know whether or when any such approvals or permits can be obtained, or whether or not any third parties will attempt to interfere with our ability to obtain and maintain such permits or approvals. If we are unable to obtain and maintain the necessary approvals and permits, we may not be able to recover our investment in the projects. Failure to obtain and maintain any of these approvals and permits could have a material adverse effect on our business, results of operations, financial condition and prospects.
Our proposed pipelines will be subject to FERC rate-making, which could have an adverse impact on our ability to recover the full cost of operating our pipelines, including a reasonable return.
Our FERC tariffs will 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. 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 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 recently enacted Energy Policy Act of 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation.
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 proposed pipelines, which would adversely affect our revenues and cash flow.
We will depend upon third-party pipelines and other facilities that will provide delivery options to and from our proposed 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 temporary or permanent interruption at any key pipeline interconnect which caused a material reduction in volumes transported on our proposed 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 proposed 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 the 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 OPS has issued a final rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate certain areas along their pipelines and 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;
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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 proposed pipeline facilities. Any repair, remediation, preventative or mitigating actions may require significant capital and operating expenditures. Should we fail to comply with OPS rules, and related regulations and orders, we could be subject to penalties and fines.
Because our proposed pipelines will be dependent upon a few customers, including an affiliate, for a significant portion of the revenues anticipated to be generated by our pipeline business, our business may be materially and adversely affected if we lose any one of these customers.
We do not currently have any third-party customers for our pipelines. We anticipate that customers with whom we enter into TUAs for our LNG receiving terminals will enter into agreements for the transportation of revaporized gas on our proposed pipelines. However, the number of such customers is anticipated to be limited, and we anticipate being substantially dependent on them for a significant percentage of the revenues generated by our pipeline business. In addition, the largest customer of our proposed pipelines is anticipated to be our affiliate, Cheniere Marketing. The loss of any of these customers, a decline in their creditworthiness or a substantial reduction in their shipments on our proposed pipelines, could have a material adverse effect on our business, results of operations and financial condition.
Risks Relating to Our LNG and Natural Gas Marketing Business
We are in the early stages of developing our LNG and natural gas marketing business.
We have just recently begun developing our LNG and natural gas marketing business. To date, the business has only a few employees, has generated no revenues and has no operating history upon which you can evaluate our business strategy or the future prospects of the business. 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 may use futures, swaps and option contracts traded on NYMEX, 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.
If we do not attract and retain qualified personnel for our developing LNG and natural gas marketing business, our operations could be adversely affected.
Our success in developing and operating an LNG and natural gas marketing business will be, in part, dependent upon the number and quality of personnel that we can hire and our ability to maintain good relationships with them. We anticipate that we will need to hire additional employees to conduct our natural gas marketing activities. If we are unable to retain qualified employees and then successfully maintain good relationships them, our results of operations may be adversely affected.
Other risks related to our LNG receiving terminal development business could have similar adverse effects on our marketing business.
Some of the risks described above under “-Risks Relating to Our LNG Receiving Terminal Development Business” could have an adverse impact on our marketing business, including those set forth under the following headings:
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“Cyclical changes in the demand for LNG regasification capacity may result in reduced operating revenues and may cause operating losses in the future;”
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“Failure of imported LNG to become a competitive source of energy in the United States could have a detrimental effect on our ability to implement and complete our business plan;”
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“The inability to import LNG into the United States due to, among other things, governmental regulation or potential instability in countries that supply natural gas, could materially adversely affect our business plans and results of operations;” and
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“Decreases in the price of natural gas in North America could harm our ability to develop our proposed LNG receiving terminals and market the sale of natural gas.”
Risks Relating to Our Oil and Gas Exploration and Development Business
We are subject to significant exploration risks, including the risk that we may not be able to find or produce enough oil and gas to generate any profits.
Our exploration activities involve significant risks, including the risk that we may not be able to find or produce enough oil and gas to generate any profits. The wells we drill may not discover any oil or gas. Furthermore, there is no way to know in advance of drilling and testing whether any prospect will yield oil or gas in sufficient quantities to make money for us. In addition, we are highly dependent on seismic activity and the related application of new technology as a primary exploration methodology. This methodology, however, requires greater pre-drilling expenditures than traditional drilling strategies. Even when fully used and properly interpreted, 3D seismic data can only assist us in identifying subsurface reservoirs and hydrocarbon indicators, and will not allow us to determine conclusively if hydrocarbons will in fact be present and recoverable. If our exploration efforts are unsuccessful, our business, results of operations, financial condition and prospects could be materially adversely affected.
We may not be able to acquire the oil and gas leases we need to sustain profitable operations.
In order to engage in oil and gas exploration in the areas covered by our 3D seismic data, we must first acquire rights to conduct exploration and recovery activities on such properties. We may not be successful in
acquiring farm-outs (agreements whereby the owner of lease interests grants to a third party the right to earn an assignment of an interest in the lease, typically by drilling one or more wells), seismic permits, lease options, leases or other rights to explore for or recover oil and gas. Both the U.S. Department of the Interior and the States of Texas and Louisiana award oil and gas leases on a competitive bidding basis. Non-governmental owners of the onshore mineral interests within the area covered by our exploration program are not obligated to lease their mineral rights to us except where we have already obtained lease options. In addition, other major and independent oil and gas companies with financial resources significantly greater than ours may bid against us for the purchase of oil and gas leases. If we are unsuccessful in acquiring these leases, permits, options and other interests, the area covered by our 3D seismic data that could be explored through drilling will be significantly reduced, and our business, results of operations, financial condition and prospects could be materially adversely effected.
If we are unable to obtain satisfactory turnkey contracts, we may have to assume additional risks and expenses when drilling wells.
We anticipate that any wells drilled in which we have an interest will be drilled by established industry contractors under turnkey contracts that limit our financial and legal exposure. Under a turnkey drilling contract, a negotiated price is agreed upon and the money placed in escrow. The contractor then assumes all of the risk and expense, including any cost overruns, of drilling a well to contract depth and completing any agreed upon evaluation of the wellbore. Upon performance of all these items, the escrowed money is released to the contractor.
Circumstances may arise, however, where a turnkey contract is not economically beneficial to us or is otherwise unobtainable from proven industry contractors. In such instances, we may decide to drill wells on a day-rate basis. Under a day-rate drilling contract, the operator pays an agreed sum for each day of drilling required to reach contract depth. All risk and expense of drilling a well to total depths lies with the operator in day-rate contracts. The drilling of such test wells would subject us to the usual drilling hazards such as cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, pollution and other environmental risks. We would also be liable for any cost overruns attributable to drilling problems that otherwise would have been covered by a turnkey contract. These liabilities, if incurred, could have a materially adverse effect on our business, results of operations, financial condition and prospects.
If we are unsuccessful at marketing our oil and gas at commercially acceptable prices, our profitability will decline.
Our ability to market oil and gas at commercially acceptable prices depends on, among other factors, the following:
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the availability and capacity of gathering systems and pipelines;
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federal and state regulation of production and transportation;
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changes in supply and demand; and
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general economic conditions.
Our inability to respond appropriately to changes in these factors could have a material adverse effect on our business, results of operations, financial condition and prospects.
Shortage of rigs, equipment, supplies or personnel may restrict our operations.
Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies or personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, demand for, and wage rates of, qualified drilling rig crews rises with increases in the number
of active rigs in service. Shortages of drilling rigs, equipment or supplies could delay or restrict our exploration and development operations, which in turn could have a material adverse effect on our business, results of operations, financial condition and prospects.
We depend on industry partners and could be seriously harmed if they do not perform satisfactorily, which is usually not within our control.
Because our oil and gas exploration and development business has few employees and limited operating revenues, we are and will continue to be largely dependent on industry partners for the success of our oil and gas exploration projects. We could be seriously harmed if we fail to attract industry partners to participate in the drilling of prospects which we identify or if our industry partners do not perform satisfactorily on projects that affect us. We often have and will continue to have no control over factors that would influence the performance of our partners.
There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and future net cash flows.
Numerous uncertainties, including those beyond our control, are inherent in estimating quantities of proved oil and gas reserves. Information included herein for 2005 relating to estimates of our proved reserves is based on reports prepared by Sharp Petroleum Engineering, Inc. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and gas reserves and of future net cash flows may vary considerably from the actual results because of a number of variable factors and assumptions involved. These include:
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historical production from the area compared with production from other producing areas;
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the effects of regulation by governmental agencies;
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future oil and gas prices;
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operating costs;
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severance and excise taxes;
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development costs; and
•
workover and remedial costs.
Therefore, the estimates of the quantities of oil and gas and the expected future net cash flows computed by different engineers or by the same engineers (but at different times) may vary significantly. The actual production, revenues and expenditures related to our reserves may vary materially from the engineers’ estimates. In addition, we may make changes to our estimates of reserves and future net cash flows. These changes may be based on the following factors:
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production history;
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results of future development;
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oil and gas prices;
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performance of counterparties under agreements to which we are a party; and
•
operating and development costs.
Do not interpret the PV-10 values included in this Form 10-K as the current market value of our properties’ estimated oil and gas reserves. According to the SEC, the PV-10 is generally based on prices and costs as of the date of the estimate. In contrast, the actual future prices and costs may be materially higher or lower. Actual future net cash flows may also be affected by the following factors:
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the amount and timing of actual production;
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the supply of, and demand for, oil and gas;
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the curtailment or increases in consumption by natural gas purchasers; and
•
the changes in governmental regulations or taxation.
The timing in producing and the costs incurred in developing and producing oil and gas will affect the timing of actual future net cash flows from proved reserves. Ultimately, the timing will affect the actual present value of oil and gas. In addition, the SEC requires that we apply a 10% discount factor in calculating PV-10 for reporting purposes. This is not necessarily the most appropriate discount factor to apply because it does not take into account the interest rates in effect, the risks associated with us and our properties, or the oil and gas industry in general.
Because of our lack of diversification, factors harming the oil and gas industry in general, including downturns in prices for oil and gas, would be especially harmful to us.
We are an independent energy company and are not actively engaged in any other industry. Our revenues and results of operation are substantially dependent on the oil and gas industry in general and the prevailing prices for oil and gas in particular. Circumstances that harm the oil and gas industry in general will have an especially harmful effect on us. Oil and gas prices have been and are likely to continue to be volatile and subject to wide fluctuations in response to any of the following factors:
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relatively minor changes in the supply of and demand for oil and gas;
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political conditions in international oil producing regions;
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the extent of domestic production and importation of oil in relevant markets;
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the level of consumer demand;
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weather conditions;
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the competitive position of oil or gas as a source of energy as compared with other energy sources;
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the refining capacity of oil purchasers; and
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the effect of federal and state regulation on the production, transportation and sale of oil and gas.
It is likely that adverse changes in the oil and gas market or the regulatory environment would have an adverse effect on our business, results of operations, financial condition and prospects, including our ability to develop and implement our LNG project and to obtain capital from lending institutions, industry participants, private or public investors or other sources.
Risks Relating to Our Business in General
We are currently a small, developing company with limited operating history in the businesses that we are developing. Our business plans are contingent on our ability to manage successfully our anticipated expansion and transition to operating these businesses.
As of February 28, 2006, we had 130 full-time employees, who, for the most part, are focused on the pre-construction stages of the development of our three proposed LNG receiving terminals. As we begin construction of the LNG receiving terminals, we will have to hire new onsite employees to manage the construction of each facility. Before our proposed LNG receiving terminals commence operations, we will have to hire an entire staff to operate each facility. We have no experience in the construction or operation of LNG receiving terminals or pipelines or the marketing of LNG or natural gas, and, as a result, we will be forced to rely to a significant extent on the new employees we hire to perform these functions. During 2006, we anticipate hiring approximately 110 employees. As our operations expand, we will also have to expand our administrative staff. If we are not able to successfully manage the expansion of our business, our business, results of operation, financial condition and prospects could be materially adversely affected.
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 use to greater and unanticipated risks.
We have little or no prior experience in some of the downstream opportunities that we are pursuing, such as natural gas pipeline development or natural gas marketing. We also have limited experience in some of the upstream opportunities that we are pursuing, such as investment in LNG shipping businesses and oil and gas exploration, development and transportation. Similarly, we have little or no prior experience in other upstream opportunities that we are pursuing, such as securing foreign LNG supply arrangements and developing foreign natural gas reserves that could be converted into LNG and imported into either domestic or international markets. We may not be successful in our efforts to pursue any or all of these initiatives. 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 depend on key personnel, and we could be seriously harmed if we lost their services.
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 agreements 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. In addition, our future success will depend in part on our ability to attract and retain additional qualified personnel.
We are subject to significant operating hazards and uninsured risks, one or more of which may create significant liabilities for us.
The construction and operation of our proposed LNG receiving terminals and pipelines will be subject to the inherent risks normally 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 a significant delay in the timing of commencement of operations and/or in damage to or destruction of our facilities or damage to persons and property. In addition, our operations face possible risks associated with acts of aggression or terrorism on our facilities and the facilities and tankers of third parties on which our operations are dependent.
In accordance with customary industry practices, we intend to maintain insurance against some, but not all, of these risks and losses. We may not be able to maintain insurance (as our project lenders may require) 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 and prospects.
Existing and future United States governmental regulation, taxation and price controls could seriously harm us.
Our LNG receiving terminal and pipeline businesses are subject to extensive federal, state and local laws and regulations that regulate the discharge of materials into the environment or otherwise relate to the protection of the environment. Failure to comply with such rules and regulations can result in substantial penalties and may harm us. Present, as well as future, legislation and regulations could cause additional expenditures, restrictions and delays in our business, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances.
The construction and operation of our LNG receiving terminals and pipelines are subject to issuance of necessary permits, licenses, consultations and approvals from numerous federal agencies, including from FERC under Section 3 of the NGA. The costs that we incur to obtain and maintain FERC and other governmental
approvals authorizing us to commence construction of our proposed LNG receiving terminals and pipelines and to comply with the ongoing regulation of the operation and maintenance of such terminals and pipelines could have a material adverse effect on our business, results of operations, financial condition and prospects. In addition, delay in the receipt of, or modification or other regulatory action with respect to, FERC or other required governmental authorization could cause substantial delays in the commencement of construction or operations of our LNG receiving terminals or pipelines, increased costs or even result in the cessation of operations. Any interstate pipeline transmission system connected to our LNG receiving terminals, as will be the case with each of our LNG receiving terminals, is subject to FERC regulation under Section 7 of the NGA. Such regulation may restrict the ability of our customers to transport gas to and from our terminals, which could have a material adverse effect on our business, results of operations, financial condition and prospects. FERC has in the past regulated the prices at which natural gas could be sold. Federal reenactment of price controls or increased regulation of the transport of natural gas could have a material adverse effect on our business, results of operations, financial condition and prospects.
Our LNG receiving terminal and pipeline development businesses are also subject to extensive federal, state and local laws and regulations governing the discharge of natural gas, hazardous substances, materials and other compounds into the environment or otherwise relating to environmental protection. These laws and regulations may restrict or prohibit the types, quantities and concentration of substances that can be released into the environment and impose substantial liabilities for pollution or releases of hazardous substances, materials or compounds or impose conditions that require additional costs or changes in operations that could have a material adverse effect on our business, results of operations, financial condition and prospects. Failure to comply with these laws and regulations may also result in civil and criminal fines and penalties. Moreover, state and federal environmental laws and regulations may become more stringent.
Federal laws and regulations such as CERCLA, the CAA, the OPA and the CWA, and analogous state laws have regularly imposed increasingly strict requirements for water and air pollution control, hazardous waste and materials management and strict financial responsibility and remedial response obligations. The cost of complying with such environmental legislation could have a material adverse effect on our business, results of operations, financial condition and prospects.
Existing environmental laws and regulations may be revised or reinterpreted or new laws and regulations may be adopted or become applicable to us. Revised, reinterpreted or additional laws and regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our business, results of operations, financial condition and prospects.
Some of our economic value is derived from our ownership of minority interests in entities over which we exercise no day-to-day control.
We own a 30% limited partner interest in Freeport LNG and a minority interest in J & S Cheniere. Some of our value is attributable to these investments. In this annual report, we may use the words “our,” “we” or “us” in describing these investments or their assets and operations; however, we do not exercise control over Freeport LNG or J & S Cheniere. The management team of Freeport LNG or J & S Cheniere could make business decisions without our consent that could impair the economic value of our investments in those entities. Any such diminution in the value of either investment could have an adverse impact on our business, results of operations, financial condition and prospects.
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 minority equity interests in certain entities that could be counted as investment securities. 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 plan to engage in operations and make 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 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 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 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.
Terrorist attacks or sustained military campaigns may adversely impact our business.
The terrorist attacks that took place in the United States on September 11, 2001 were unprecedented events that have created many economic and political uncertainties, some of which may materially adversely impact our business. The continued threat of terrorism and the impact of military and other action will likely lead to continued volatility in prices for natural gas and could affect the markets for the operations of our LNG customers on which we will be dependent, as well as lead to increased costs incurred by us in implementing security measures against such threats. Furthermore, the United States government has issued public warnings that indicate that pipelines and other energy assets might be specific targets of terrorist organizations. These potential targets might include our assets. The continuation of these developments may subject our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, results of operations, financial condition and prospects.
Hurricanes Katrina and Rita, or future similar storms, could have a material adverse effect on our business, financial condition and results of operations.
In August and September of 2005, Hurricanes Katrina and Rita and related storm activity, such as windstorms, storm surges, floods and tornadoes, caused extensive and catastrophic physical damage in and to coastal and inland areas located in the Gulf Coast region of the United States (parts of Texas, Louisiana, Mississippi and Alabama) and certain other parts of the southeastern United States. Construction at our Sabine Pass 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.
Bechtel has claimed events of force majeure arising out of three hurricanes in 2005 along the U.S. Gulf Coast. Sabine Pass LNG is currently in negotiations with Bechtel and certain subcontractors concerning additional activities and expenditures in order, among other things, to attract sufficient skilled labor to mitigate potential schedule delays and provide a reasonable opportunity for Bechtel to attain the initial target bonus date of April 3, 2008 (the date originally anticipated for completion of construction sufficient to achieve a sendout rate of at least 2.0 Bcf/d for a minimum sustained test period of 24 hours and that, if attained, would entitle Bechtel to a scheduled $12 million bonus). As part of these negotiations, we have agreed in principle to defer the date by which substantial completion of the entire project is required to be accomplished under the EPC contract from September 3 to December 20, 2008. In the absence of substantial completion by such date, Bechtel would be obligated to pay us certain liquidated damages as provided under the terms of the contract. We expect that the above-described arrangement will not exceed $50 million, although such amount is subject to change, requires approval of the lenders under our Sabine Pass Credit Facility and requires that a change order be agreed upon with Bechtel. These storms and their collateral effects, mainly labor availability, could result in additional delays or cost increases for construction of our Sabine Pass LNG receiving terminal.
Future similar storms and related storm activity and collateral effects could result in damage to, delays or cost increases in construction of, or interruption of operations at, our planned LNG receiving terminals or related pipelines.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
We are, and 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, 2005, 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.
As previously disclosed, we received a letter dated December 17, 2004 advising us of a nonpublic, informal inquiry being conducted by the SEC. On August 9, 2005, the SEC informed us that it had issued a formal order and commenced a nonpublic factual investigation of actions and communications by Cheniere, its current or former directors, officers and employees and other persons in connection with our agreements and negotiations with Chevron USA, the Company’s December 2004 public offering of common stock, and trading in our securities. The scope, focus and subject matter of the SEC investigation may change from time to time, and we may be unaware of matters under consideration by the SEC. We have cooperated fully with the SEC informal inquiry and intend to continue cooperating fully with the SEC in its investigation.
Neither Cheniere, nor any entity required to be consolidated with Cheniere for purposes of this annual report, has been required to pay a penalty to the Internal Revenue Service for failing to make disclosures required with respect to certain transactions that have been identified by the Internal Revenue Service as abusive or that have a significant tax avoidance.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
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 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 American Stock Exchange, for each quarter during 2004 and 2005.
The above historical share prices have been adjusted to reflect our two-for-one stock split that occurred on April 22, 2005.
As of February 28, 2006, we had 54.7 million shares of common stock outstanding held by approximately 8,500 beneficial 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 credit agreements, as well as other factors the board of directors deems relevant.
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.
(1) The year ended 2002 includes $1.7 million in recoveries of general and administrative expenses reimbursable under the term of an agreement related to our sale of the Freeport LNG site, which closed in February 2003. See Note 8 to our Consolidated Financial Statements.
(2) Effective January 1, 2003, we began accounting for this investment in Gryphon using the cost method of accounting. The amounts listed for 2002 and 2001 represent our equity in the net loss of Gryphon under the equity method of accounting. In 2005, Gryphon was sold to Woodside Energy (USA), generating net cash proceeds and a gain to Cheniere of $20.2 million. See Note 22 to our Consolidated Financial Statements.
(3) Represents our equity in the net loss of Freeport LNG. See Note 8 to our Consolidated Financial Statements.
(4) Represents minority interest in the net loss of Corpus Christi LNG. See Note 13 to our Consolidated Financial Statements.
(5) Net loss per share and weighted average shares outstanding have been restated to reflect a two-for-one split that occurred on April 22, 2005.
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION
General
We are engaged primarily in the business of developing and constructing, and then owning and operating, a network of three onshore LNG receiving terminals, and related natural gas pipelines, along the Gulf Coast of the United States. We are also engaged, to a limited extent, in oil and natural gas exploration and development activities in the Gulf of Mexico. We operate four business activities: LNG receiving terminal development, natural gas pipeline development, LNG and natural gas marketing and oil and gas exploration and development. At this stage in our development, our operations are divided into two reporting segments in our financial statements: LNG Receiving Terminal Development and Oil and Gas Exploration and Development.
LNG Receiving Terminal Development Business
We have focused our development efforts on three, 100% owned LNG receiving terminal projects at the following locations: Sabine Pass LNG in western Cameron Parish, Louisiana on the Sabine Pass Channel; Corpus Christi LNG near Corpus Christi, Texas; and Creole Trail LNG at the mouth of the Calcasieu Channel in central Cameron Parish, Louisiana. In addition, we own a 30% interest in a fourth project, Freeport LNG, located on Quintana Island near Freeport, Texas. Our three terminals have an aggregate designed regasification capacity of approximately 10 Bcf/d, subject to expansion. We have entered into long-term TUAs with Total and Chevron USA for an aggregate of 2 Bcf/d of the available regasification capacity, and we anticipate retaining a portion of regasification capacity for our own use.
Construction of Phase 1 of our Sabine Pass LNG receiving terminal commenced in March 2005, and we anticipate commencing operations at the terminal in 2008. Construction of the Corpus Christi and Creole Trail LNG receiving terminals is anticipated to commence in 2006 and 2007, respectively, and we anticipate commencing operations at the facilities in 2010 and 2011, respectively.
Natural Gas Pipeline Development Business
We anticipate developing natural gas pipelines from each of our three LNG receiving terminals to provide optimal access to North American natural gas markets. Development efforts to date have focused primarily on advancing our pipeline projects through the regulatory review and authorization process. Recently, our development efforts have also included the construction and operation of our proposed natural gas pipelines. We anticipate commencing construction of our Sabine Pass pipeline in early 2007 and that it will be operational in the fourth quarter of 2007.
LNG and Natural Gas Marketing Business
Our LNG and natural gas marketing business is in its early stages of development. Utilizing a portion of our planned LNG receiving terminal regasification capacity that we intend to reserve for use by Cheniere Marketing at our three LNG receiving terminals, we intend to purchase LNG from foreign suppliers, arrange transportation of LNG to our network of LNG receiving terminals, arrange the transportation of revaporized natural gas through our pipelines and other interconnected pipelines and sell natural gas to buyers in the North American market. In addition, we also expect to enter into domestic natural gas purchase and sale transactions as part of our marketing activities.
Oil and Gas Exploration and Development Business
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, and in exploitation of our existing 3D seismic database through prospect generation. We have historically focused on evaluating and generating
drilling prospects using a regional and integrated approach with a large seismic database as a platform. Our current oil and gas exploration and development activities are focused on the Cameron Project and the Offshore Texas Project Area. From time to time, we will invest in drilling a share of these prospects and may pursue opportunities in other geographic locations as well.
Liquidity and Capital Resources
We are primarily engaged in LNG-related business activities. Our three LNG terminal projects, as well as our proposed pipelines, will require significant amounts of capital and are subject to risks and delays in completion. In addition, our marketing business will need a substantial amount of capital for hiring employees, satisfying creditworthiness requirements of contracts and developing the systems necessary to implement our business strategy. Even if successfully completed and implemented, our LNG-related business activities are not expected to begin to operate and generate significant cash flows before 2008. As a result, our business success will depend to a significant extent upon our ability to obtain the funding necessary to construct our three LNG terminals and related pipelines, to bring them into operation on a commercially viable basis and to finance the costs of staffing, operating and expanding our company during that process.
We currently estimate that the cost of completing our three LNG receiving terminals will be approximately $3.0 billion, before financing costs. In addition, we expect that capital expenditures of approximately $800 million to $1 billion will be required to construct our three proposed pipelines.
As of December 31, 2005, we had working capital of $810.1 million. While we believe that we have adequate financial resources available to us through 2006, we must augment our existing sources of cash with significant additional funds in order to carry out our long-term business plan. We currently expect that our capital requirements will be financed in part through cash on hand, issuances of project-level debt, equity or a combination of the two and in part with net proceeds of debt or equity securities issued by Cheniere or other Cheniere borrowings.
Our LNG Receiving Terminals
Sabine Pass LNG
We currently estimate that the cost of constructing Phase 1 of the Sabine Pass LNG facility will be approximately $900 million to $950 million, before financing costs, which will be funded as described below. Phase 2 of the Sabine Pass LNG facility may be constructed in stages. The first stage is estimated to cost approximately $500 million to $550 million, before financing costs. We are currently evaluating funding alternatives for the first stage of construction of Phase 2 of the Sabine Pass LNG facility, which may include existing cash balances, proceeds from debt or equity offerings, or a combination thereof. The second stage of constructing Phase 2 of the Sabine Pass LNG facility is still under evaluation.
Sabine Pass Credit Facility
In February 2005, Sabine Pass LNG entered into the $822 million Sabine Pass Credit Facility with an initial syndicate of 47 financial institutions. Société Générale serves as the administrative agent and HSBC serves as collateral agent. The Sabine Pass Credit Facility will be used to fund a substantial majority of the costs of constructing and placing into operation Phase 1 of the Sabine Pass LNG receiving terminal. Unless Sabine Pass LNG decides to terminate availability earlier, the Sabine Pass Credit Facility will be available until no later than April 1, 2009, after which time any unutilized portion of the Sabine Pass Credit Facility will be permanently canceled. Before Sabine Pass LNG could make an initial borrowing under the Sabine Pass Credit Facility, it was required to provide evidence that it had received equity contributions in amounts sufficient to fund $233.7 million of the project costs. As of December 31, 2005, the $233.7 million equity contributions had been funded and, as a result, we began drawing under the Sabine Pass Credit Facility in January 2006. As of February 28, 2006, $58.5 million had been drawn under the Sabine Pass Credit Facility. In addition, we made a $37.4 million subordinated loan to Sabine Pass LNG in late 2005.
Borrowings under the Sabine Pass Credit Facility bear interest at a variable rate equal to LIBOR plus the applicable margin. The applicable margin varies from 1.25% to 1.625% during the term of the Sabine Pass Credit Facility. The Sabine Pass Credit Facility provides for a commitment fee of 0.50% per annum on the daily committed, undrawn portion of the Sabine Pass Credit Facility. Administrative fees must also be paid annually to the agent and the collateral agent. The principal of loans made under the Sabine Pass Credit Facility must be repaid in semi-annual installments commencing six months after the later of (i) the date that substantial completion of the project occurs under the EPC agreement and (ii) the commercial start date under the Total TUA. Sabine Pass LNG may specify an earlier date to commence repayment upon satisfaction of certain conditions. In any event, payments under the Sabine Pass Credit Facility must commence no later than October 1, 2009, and all obligations under the Sabine Pass Credit Facility mature and must be fully repaid by February 25, 2015.
Under the terms and conditions of the Sabine Pass Credit Facility, all cash held by Sabine Pass LNG is controlled by the collateral agent. These funds can only be released by the collateral agent upon receipt of satisfactory documentation that the Sabine Pass LNG project costs are bona fide expenditures and are permitted under the terms of the Sabine Pass Credit Facility. The Sabine Pass Credit Facility does not permit Sabine Pass LNG to hold any cash, or cash equivalents, outside of the accounts established under the agreement. Because these cash accounts are controlled by the collateral agent, the Sabine Pass LNG cash balance of $8.9 million held in these accounts as of December 31, 2005 is classified as restricted on our balance sheet.
The Sabine Pass Credit Facility contains customary conditions precedent to the initial borrowing and any subsequent borrowings, as well as customary affirmative and negative covenants. Sabine Pass LNG has obtained, and may in the future seek, consents, waivers and amendments to the Sabine Pass Credit Facility documents. The obligations of Sabine Pass LNG under the Sabine Pass Credit Facility are secured by all of Sabine Pass LNG’s personal property, including the Total and Chevron USA TUAs and the partnership interests in Sabine Pass LNG.
In connection with the closing of the Sabine Pass Credit Facility, Sabine Pass LNG entered into swap agreements with HSBC and Société Générale. Under the terms of the swap agreements, Sabine Pass LNG will be able to hedge against rising interest rates, to a certain extent, with respect to its drawings under the Sabine Pass Credit Facility up to a maximum amount of $700 million. The swap agreements have 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 to March 25, 2009 and at 4.98% from March 26, 2009 through March 25, 2012. The final termination date of the swap agreements will be March 25, 2012.
EPC Agreement
Sabine Pass LNG issued an NTP in early April 2005, which required Bechtel to commence all other aspects of the work under the EPC agreement. Sabine Pass LNG agreed to pay to Bechtel a contract price of $646.9 million plus certain reimbursable costs for the work under the EPC agreement. This contract price is subject to adjustment for changes in certain commodity prices, contingencies, change orders and other items. Payments under the EPC agreement will be made in accordance with the payment schedule set forth in the EPC agreement. The contract price and payment schedule, including milestones, may be amended only by change order. Bechtel will be liable to Sabine Pass LNG for certain delays in achieving substantial completion, minimum acceptance criteria and performance guarantees. Bechtel will be entitled to a scheduled bonus of $12 million, or a lesser amount in certain cases, if on or before April 3, 2008, Bechtel completes construction sufficient to achieve, among other requirements specified in the EPC agreement, a sendout rate of at least 2.0 Bcf/d for a minimum sustained test period of 24 hours. Bechtel will be entitled to receive an additional bonus of $67,000 per day (up to a maximum of $6 million) for each day that commercial operation is achieved prior to April 1, 2008. As of February 28, 2006, change orders for $64.8 million were approved, thereby increasing the total contract price to $711.8 million. We anticipate additional change orders intended to mitigate ongoing effects of the 2005
hurricanes that would increase the contract price by an amount not expected to exceed $50 million. We expect to submit any such change orders to our lenders by May 3, 2006 for approval under the Sabine Pass Credit Facility.
Bechtel has claimed events of force majeure arising out of three hurricanes in 2005 along the U.S. Gulf Coast. Sabine Pass LNG is currently in negotiations with Bechtel and certain subcontractors concerning additional activities and expenditures in order, among other things, to attract sufficient skilled labor to mitigate potential schedule delays and provide a reasonable opportunity for Bechtel to attain the initial target bonus date of April 3, 2008. As part of these negotiations, we have agreed in principle to defer the date by which substantial completion of the entire project is required to be accomplished under the EPC contract from September 3 to December 20, 2008. In the absence of substantial completion by such date, Bechtel would be obligated to pay us certain liquidated damages as provided under the terms of the contract. We expect that the above-described arrangement will not exceed $50 million, although such amount is subject to change, requires approval of the lenders under our Sabine Pass Credit Facility and requires that a change order be agreed upon with Bechtel.
Customer TUAs
Total has paid Sabine Pass LNG nonrefundable advance capacity reservation fees of $20 million in the aggregate ($10 million in each of 2004 and 2005) in connection with the reservation under a 20-year TUA (with extension options) of approximately 1.0 Bcf/d of LNG regasification capacity at the Sabine Pass LNG receiving terminal. These capacity reservation fee payments will be amortized over a 10-year period as a reduction of Total’s regasification capacity fee under the TUA.
Chevron USA has paid Sabine Pass LNG nonrefundable advance capacity reservation fees of $20 million in the aggregate ($12 million in 2004 and $8 million in 2005) in connection with the reservation under a 20-year TUA (with extension options) of approximately 1.0 Bcf/d of LNG regasification capacity at the Sabine Pass LNG receiving terminal, taking into account the option exercised by Chevron USA in December 2005. These capacity reservation fee payments will be amortized over a 10-year period as a reduction of Chevron USA’s regasification capacity tariff under the TUA.
Corpus Christi LNG
We currently estimate that the cost of constructing the Corpus Christi LNG facility will be approximately $650 million to $750 million, before financing costs. This estimate is based in part on our negotiations with a major international EPC contractor. Our cost estimate is subject to change due to such items as cost overruns, change orders, changes in commodity prices (particularly steel) and escalating labor costs.
BPU LNG was required to fund 100% of the first $4.5 million of Corpus Christi LNG’s expenditures, which amount was funded as of March 31, 2004. From that date until February 8, 2005, when we acquired BPU LNG’s 33.3% interest, we funded 66.7% of the expenditures of Corpus Christi LNG, with BPU LNG funding the balance. Since February 8, 2005, BPU LNG has not been required to fund any expenditures, and as the sole owner of Corpus Christi LNG, we are now required to fund 100% of expenditures.
We expect to begin site preparation and detailed engineering work in the second quarter of 2006 and to commence operations at the Corpus Christi LNG receiving terminal in early 2010.
We currently expect to fund the project costs for our Corpus Christi LNG receiving terminal from cash balances, project financing similar to that used for our Sabine Pass LNG facility, proceeds from debt or equity offerings, or a combination thereof. If these types of financing are not available, we will be required to seek alternative sources of financing, which may not be available on acceptable terms, if at all.
Creole Trail LNG
We currently estimate that the cost of constructing the Creole Trail LNG facility will be approximately $850 million to $950 million, before financing costs. Our cost estimate is preliminary and subject to change. We
currently expect to fund the costs of the Creole Trail LNG terminal project using financing similar to that used for our Sabine Pass LNG facility, proceeds from future debt or equity offerings, existing cash or a combination thereof. If these types of financing are not available, we will be required to seek alternative sources of financing, which may not be available on acceptable terms, if at all.
Other LNG Interests
We have a 30% limited partner interest in 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 July 2004, Freeport LNG entered into a credit agreement with ConocoPhillips to provide a substantial majority of the debt financing. We received capital calls, and made capital contributions, in the amount of approximately $2.1 million in 2005. In December 2005, Freeport LNG announced that it had closed a $383 million private placement of notes, which will 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 the development of 7.5 Bcf of underground salt cavern gas storage. As a result of such financing being obtained, we do not anticipate that any capital calls will be made upon the limited partners of Freeport LNG in the foreseeable future.
Although no capital calls are currently outstanding, and we do not anticipate any in the foreseeable future, additional capital calls may be made upon us and the other limited partners in Freeport LNG. 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 and funds raised through the issuance of Cheniere equity or debt securities or other Cheniere borrowings.
Our Proposed Pipelines
We estimate that approximately $800 million to $1 billion of total capital expenditures will be required to construct our three proposed pipelines. We currently expect to fund the costs of our three proposed pipelines from our existing cash balances, project financing, proceeds from future debt or equity offerings, or a combination thereof.
On February 21, 2006, Cheniere Sabine Pass Pipeline Company entered into an EPC pipeline contract with Willbros. Under the EPC pipeline contract, which is effective as of February 1, 2006, Willbros will provide Cheniere Sabine Pass Pipeline Company with services for the management, engineering, material procurement, construction and construction management of the Sabine Pass pipeline. Cheniere Sabine Pass Pipeline Company entered into the EPC pipeline contract sufficiently in advance of commencement of physical construction of the pipeline in order to perform detailed engineering and procure materials. This EPC pipeline contract, among other things, provides for a guaranteed maximum price of approximately $67.7 million, subject to adjustment under certain circumstances, as provided in the contract. We estimate that the total cost to construct the pipeline, including certain work not included in the EPC pipeline contract, such as interconnection with third-party pipelines, will be approximately $90 million. Our total cost estimate is preliminary and subject to change due to such items as cost overruns, change orders, changes in commodity prices (particularly steel) and escalation of labor costs. Construction contracts for the Corpus Christi and Creole Trail pipelines have not been negotiated.
Our Marketing Business
We are in the early stages of developing our LNG and natural gas marketing business. We will need to spend funds to develop our marketing business, including capital required to satisfy any creditworthiness requirements under contracts. These costs are expected to be incurred to develop the systems necessary to implement our business strategy and to hire additional employees to conduct our natural gas marketing activities. We expect to fund these expenses with available cash balances.
Other Capital Resources
Convertible Senior Unsecured Notes
In July 2005, we consummated a private offering of $325 million aggregate principal amount of Convertible Senior Unsecured Notes due August 1, 2012 to qualified institutional buyers pursuant to Rule 144A under the Securities Act. The notes bear interest at a rate of 2.25% per year. The notes are convertible into our common stock pursuant to the terms of the indenture governing the notes 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. 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 rate plus 50 basis points. The indenture governing the notes contains customary reporting requirements.
Concurrent with the issuance of the Convertible Senior Unsecured Notes, we also entered into hedge transactions in the form of an issuer call spread (consisting of a purchase and a sale of call options on our common stock) with an affiliate of the initial purchaser of the notes, having a term of two years and a net cost to us of $75.7 million. These hedge transactions are expected to offset potential dilution from conversion of the notes up to a market price of $70.00 per share. The net cost of the hedge transactions will be recorded as a reduction to Additional Paid-in-Capital in accordance with the guidance of EITF Issue 00-19, Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company’s Own Stock. Net proceeds from the offering were $239.8 million, after deducting the cost of the hedge transactions, the underwriting discount and related fees. As of December 31, 2005, no holders had elected to convert their notes.
We currently intend to use the net proceeds from the Convertible Senior Unsecured Notes offering primarily for the following purposes: (i) to fund Phase 2 of the Sabine Pass LNG receiving terminal, development and construction of the Corpus Christi and/or Creole Trail LNG receiving terminals and pipelines, (ii) to pay debt service obligations and/or (iii) for general corporate purposes.
Term Loan
In August 2005, Cheniere LNG Holdings, LLC, or Cheniere LNG Holdings, a wholly-owned subsidiary of Cheniere, entered into a $600 million term loan, or Term Loan, with Credit Suisse. The Term Loan interest rate equals LIBOR plus a 2.75% margin and terminates on August 30, 2012. In connection with the closing, Cheniere LNG Holdings entered into swap agreements with Credit Suisse to hedge the LIBOR interest rate component of the Term Loan. The blended rate of the swap agreements on the Term Loan results in an annual fixed interest rate of 7.25% (including the 2.75% margin) for the first five years (See Note 10 to our Consolidated Financial Statements). On December 30, 2005, Cheniere LNG Holdings made the first required quarterly principal payment of $1.5 million. Quarterly principal payments of $1.5 million are required through June 30, 2012, and a final principal payment of $559.5 million is required on August 30, 2012. The Term Loan contains customary affirmative and negative covenants. The obligations of Cheniere LNG Holdings are secured by its 100% equity interest in Sabine Pass LNG and its 30% limited partner equity interest in Freeport LNG.
Under the conditions of the Term Loan, Cheniere LNG Holdings was required to fund from the loan proceeds a total of $216.2 million into two collateral accounts. These funds are restricted and to be disbursed only for the payment of interest and principal due under the Term Loan, reimbursement of certain expenses, and funding of additional capital contributions to Sabine Pass LNG as required under the Sabine Pass Credit Facility. Because these accounts are controlled by Credit Suisse, the collateral agent, our cash and cash equivalent undisbursed balance of $168.5 million held in these accounts as of December 31, 2005 is classified as restricted on our consolidated balance sheet. Of this amount, $16.5 million is classified as non-current due to the timing of certain required debt amortization payments.
We currently intend to use the remaining proceeds from the Term Loan primarily for the following purposes: (i) to fund requirements in excess of amounts available under the Sabine Pass Credit Facility for the construction of the Sabine Pass LNG receiving terminal, (ii) to pay specified Term Loan debt service obligations and certain other expenses, (iii) to fund Phase 2 of the Sabine Pass LNG receiving terminal, (iv) to fund the development and construction of the Corpus Christi and/or Creole Trail LNG receiving terminals and pipelines and/or (v) for general corporate purposes.
Short-Term Liquidity Needs
We anticipate funding our more immediate liquidity requirements, including some expenditures related to the construction of our LNG receiving terminals, the development of our pipeline business, the growth of our marketing business and our oil and gas exploration, development and exploitation activities, through a combination of any or all of the following:
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cash balances;
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drawings under the Sabine Pass Credit Facility;
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issuances of Cheniere debt and equity securities, including issuances of common stock pursuant to exercises by the holders of existing options;
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LNG receiving terminal capacity reservation fees;
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collection of receivables; and
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sales of prospects generated by our oil and gas exploration and development business.
Historical Cash Flows
Net cash used in operations increased to $18.4 million in 2005 compared to $661,000 in 2004. This $17.7 million increase was primarily due to continued development of our LNG receiving terminals and related pipelines and increased costs to support such activities.
Net cash used in investing activities was $406.1 million during 2005 compared to net cash provided by investing activities of $1.2 million in 2004. During 2005, we funded $177.4 million related to restricted cash balances as required by the Term Loan and the Sabine Pass Credit Facility. We also advanced $8.1 million to the Sabine Pass LNG EPC contractor (net of $24.2 million applied against invoices and transferred to construction-in-progress related to the Sabine Pass LNG receiving terminal). We recorded $229.7 million to construction-in-progress related to Phase 1 of the Sabine Pass LNG facility. The remaining cash used in investing activities during 2005 was used primarily for the purchase of fixed assets, advances to Freeport LNG, and oil and gas property additions. These uses were partially offset by $20.2 million in proceeds received from the sale of our interest in Gryphon and $1.2 million received from the sale of interests in oil and gas prospects. During 2004, cash provided by investing activities of $1.2 million included a reimbursement from our limited partnership investment, proceeds from the sale of a limited partnership interest, and sales of our interests in oil and gas prospects, partially offset by oil and gas property and fixed asset additions.
Net cash provided by financing activities was $808.7 million during 2005 compared to $306.7 million in 2004. During 2005, we received proceeds from the issuance of our Convertible Senior Unsecured Notes and completion of the Term Loan in the amounts of $249.3 million (net of $75.7 million for the issuer call spread) and $600 million, respectively. In addition, we received $3.0 million in proceeds from the exercise of stock options and warrants. These proceeds were partially offset by $42.1 million in debt issuance costs related to the Sabine Pass Credit Facility, the Convertible Senior Unsecured Notes and the Term Loan. During 2004, we received proceeds from our $300.0 million public equity offering of common stock in December 2004 (before related offering costs of $14.1 million). In addition, we received $20.9 million from a private sale of our common stock (before offering costs of $965,000) and exercises of warrants and stock options. We also received $3.1 million in partnership contributions in 2004 made by the minority owner in Corpus Christi LNG. Cash flows from financing activities in 2004 were partially offset by the repayment of a $1.0 million note payable.
Due to the factors described above, our cash and cash equivalents increased to $692.6 million as of December 31, 2005 compared to $308.4 million at December 31, 2004, and our working capital increased to $810.1 million as of December 31, 2005 compared to $305.8 million at December 31, 2004.
Issuances of Common Stock
From our inception until August 2005, the primary source of financing for our operating expenses, investments in our exploration program and investments in our development of LNG receiving terminals was the sale of our equity securities. During 2005 and 2004, we raised $3 million and $305.9 million, respectively, net of offering costs, from the exchange or exercise of warrants, the exercise of stock options, a public equity offering of common stock and the sale of Cheniere common stock to accredited investors pursuant to Regulation D.
In February 2005, our stockholders approved an increase in Cheniere’s authorized common stock from 40 million to 120 million shares. On April 22, 2005, we issued 26,789,242 shares of our common stock in a two-for-one stock split. The stock split entitled all stockholders of record at the close of business on April 8, 2005 to receive one additional share of common stock for each share held on that date. All per share amounts and outstanding and weighted share amounts included in this annual report on Form 10-K have been restated to give effect to the two-for-one stock split.
In February 2005, we acquired the 33.3% minority interest in Corpus Christi LNG through the acquisition of BPU LNG in exchange for 2 million restricted shares of our common stock valued at $77 million plus direct transaction costs.
In December 2005, 160,151 shares were issued to employees and outside directors in the form of non-vested (restricted) stock awards related to our performance in 2005. We recorded $6.2 million of deferred compensation as a reduction to stockholders’ equity. In 2005, we also issued 15,000 shares of non-vested stock to certain employees. As a result, we recorded $498,000 of deferred compensation as a reduction of stockholders’ equity. During 2005, we recorded $3.5 million (before capitalization of $145,000 as oil and gas property costs) in total non-cash compensation expense related to the amortization of deferred compensation.
During 2005, a total of 864,000 shares of our common stock were issued pursuant to the exercise of stock options, resulting in net cash proceeds of $2.5 million. A total of 433,000 shares of common stock were also issued pursuant to the exercise of warrants, resulting in net cash proceeds of $520,000. In addition, 97,000 shares were issued in satisfaction of cashless exercises of warrants to purchase 100,000 shares of common stock, and 33,000 shares were issued in satisfaction of cashless exercises of options to purchase 34,000 shares of common stock.
We issued a total of 17.9 million shares of common stock in 2004. In January 2004, we issued 2.2 million shares of common stock in a private placement under Regulation D to twelve accredited investors for total consideration of $14.9 million. We paid a 6.5% sales commission totaling $965,000, resulting in $13.9 million of net proceeds received from the offering. In February 2004, 766,000 shares were issued to employees and outside directors in the form of vested stock and non-vested stock awards related to our performance in 2003. This included 322,000 shares of stock for which we recorded $2.4 million in non-cash compensation expense, and 444,000 shares of non-vested stock for which we recorded $3.3 million in deferred compensation as a reduction in stockholders’ equity. In November 2004, 236,000 shares were issued to employees and outside directors in the form of non-vested stock awards related to our performance in 2004. We recorded $4.9 million of deferred compensation as a reduction to stockholders’ equity. In December 2004, we issued 10 million shares of common stock in connection with a public offering, for which we received net proceeds of $285.9 million. Throughout 2004, we issued a total of 1.8 million shares pursuant to the exercise of warrants, resulting in net cash proceeds of $3.4 million. We also issued 2.4 million shares pursuant to the exercise of stock options, resulting in net proceeds of $2.7 million and 553,000 shares in satisfaction of cashless exercises of stock options and warrants to purchase 390,000 and 250,000 shares, respectively.
We issued a total of 6.4 million shares of common stock in 2003. In April 2003, we issued 1.5 million shares of common stock pursuant to a contingent contractual obligation related to Cheniere’s 2001 acquisition of an option to lease the Freeport LNG receiving terminal site. In May 2003, we issued 1.6 million shares of common stock to seventeen investors in a private placement made pursuant to Regulation D. The purchase price of the shares included cash of $1.2 million and the surrender of existing warrants to purchase 1.6 million shares of our common stock. Offering expenses relating to the private placement were $57,000. In August 2003, we issued 757,000 shares pursuant to a cashless exercise of warrants to purchase 1.4 million shares. Throughout 2003, we issued a total of 2.2 million shares pursuant to the exercise of warrants, resulting in net cash proceeds of $2.9 million. We also issued 375,000 shares pursuant to the exercise of stock options, resulting in proceeds of $292,000.
Contractual Obligations
We are committed to making cash payments in the future on certain of our contracts. We have no off-balance sheet debt or other such unrecorded obligations, and we have not guaranteed the debt of any other party. Below is a schedule of the future payments that we are obligated to make based on agreements in place as of December 31, 2005 (in thousands).
(1) A discussion of these obligations can be found at Note 14 to our Consolidated Financial Statements.
(2) A discussion of these obligations can be found at Note 21 to our Consolidated Financial Statements.
(3) Includes obligations for telecommunication services and software licensing.
Lease Commitments and Other Obligations
We currently have lease commitments for approximately 56,000 square feet of office space in downtown Houston, Texas. In October 2003, we entered into a lease agreement for office space having a term which runs from December 2003 through April 2014. Beginning in April 2004, our monthly lease rental for this space is $21,000 and escalates to $24,000 beginning in February 2009 through the remaining term of the lease. We have an option to renew the lease for an additional five years at the then-current market rate. In May 2004, we amended our office lease agreement to increase our rentable square footage (the “Expansion Space”). The lease term for the Expansion Space runs from September 2004 through August 2009. Our monthly lease rental for the Expansion Space is $14,000 beginning in June 2005. We have the option, subject and subordinate to another tenants’ renewal option, to renew the lease for an additional five years. In March 2005, we further amended our office lease to increase our rentable square footage to include an additional floor on the premises. The lease term for the additional floor runs from May 2005 through January 2014. We have an option to renew the lease for an additional five years at the then-current market rate as part of the renewal of our original lease space. Under the amended lease, there are no monthly lease payments for the additional floor from May 2005 through April 2007, after which time the lease payments range from approximately $30,000 to $39,000 per month through January 2014. We have prepaid $201,000 in rent related to 2013 and have included such amount in Other Assets on the consolidated balance sheet as of December 31, 2005.
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 our Sabine Pass LNG receiving terminal site. The leases have an initial term of 30 years, with options to renew for six 10-year extensions. 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. For 2005, these payments have been capitalized as part of the construction cost of the Sabine Pass LNG receiving terminal; however, beginning in January 2006, these lease payments have been expensed as required by Financial Accounting Standards Board, or FASB, Staff Position, or FSP, 13-1, Accounting for Rental Costs Incurred During Construction.
Restricted Certificate of Deposit and Letter of Credit
Under the terms of our office lease, we are required to post a standby letter of credit in favor of the lessor. The initial amount of the letter of credit was increased from $865,000 to $1.1 million in April 2004 related to the expansion of our office space; and the amount will be reduced by approximately $225,000 per annum over a five-year period. This letter of credit was initially established under the terms of our bank line of credit at that time.
Upon the termination of our bank line of credit in June 2004, we purchased a certificate of deposit in the amount of $1.1 million and entered into a pledge agreement in favor of the commercial bank that had previously issued the standby letter of credit for $1.1 million. In October 2004 and 2005, both the letter of credit and certificate of deposit were amended to decrease the face amounts by approximately $225,000 to $898,000 and $674,000, respectively. The renewed letter of credit and the certificate of deposit both mature on November 30, 2005. Under the terms of the pledge agreement, the commercial bank was assigned a security interest in the certificate of deposit as collateral for the letter of credit. As a result, the certificate of deposit plus $2,000 of accrued interest is classified as restricted on our balance sheet at December 31, 2005.
Off-Balance Sheet Arrangements
As of December 31, 2005, 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
During 2003, 2004 and 2005, inflation and changing commodity prices have had an impact on our revenues but have not significantly impacted our results of operations. However, we have experienced escalated steel prices relating to the construction of our LNG receiving terminals and labor costs in connection with the collateral effects of the 2005 hurricanes.
Prior Bank Line of Credit
In June 2004, we terminated our $5 million line of credit with a commercial bank. This facility was originally established in July 2003 with a borrowing base of $2 million. During 2003, we borrowed $1 million under the facility to acquire oil and gas leases, which we subsequently repaid in January 2004.
Short-Term Promissory Notes
In February 2003, we executed a promissory note payable in the amount of $225,000. The proceeds of the note were used to pay certain costs related to our 3-D seismic database. In July 2003, we repaid the note payable.
Results of Operations-Comparison of the Fiscal Years Ended December 31, 2005 and 2004
Overview-Our financial results for the year ended December 31, 2005 reflect a net loss of $29.8 million, or $0.56 per share (basic and diluted), compared to a net loss of $24.6 million, or $0.63 per share (basic and diluted), in 2004.
The major factors contributing to our net loss of $29.8 million in 2005 were LNG receiving terminal development expenses of $22.0 million and general and administrative expenses of $29.1 million, which were
significantly offset by the $20.2 million gain on the sale of our investment in Gryphon. Absent the gain on the sale of our investment in Gryphon, we would have reported a net loss of $50.0 million, or $0.94 per share (basic and diluted), for 2005. The major factors contributing to our $24.6 million net loss in 2004 were LNG receiving terminal development expenses of $17.2 million and general and administrative expenses of $12.5 million, which were partially offset by a $2.9 million minority interest in the operations of Corpus Christi LNG and by a $2.5 million reimbursement from our limited partner investment in Freeport LNG.
LNG Receiving Terminal Development and Related Pipeline Activities-LNG receiving terminal development expenses increased $4.8 million, or 28%, to $22.0 million in 2005 compared to $17.2 million in 2004. Our development expenses primarily included professional fees associated with front-end engineering and design work, obtaining orders from FERC authorizing construction of our facilities and other required permitting for our planned LNG receiving terminals, their related natural gas pipelines as well as other initiatives that complement the development of our LNG receiving terminal business. Expenses of our LNG employees involved in development activities are also included. Beginning in the first quarter of 2005, costs related to the construction of Phase 1 of our Sabine Pass LNG receiving terminal have been capitalized.
LNG receiving terminal development expenses for 2005 totaled $7.1 million and were mainly attributable to our Creole Trail LNG and Corpus Christi LNG terminal projects and Phase 2 of the Sabine Pass LNG project. In 2005, we incurred $6.4 million in LNG pipeline development expenses primarily related to our Sabine Pass LNG and Creole Trail LNG projects. In addition, we incurred $8.5 million in other LNG receiving terminal development expenses, including $7.3 million in LNG employee-related costs. Our LNG staff increased from an average of 14 employees in 2004 to an average of 25 employees in 2005 as a result of the expansion of our business. LNG employee-related costs for 2005 included cash bonus costs of $1.7 million related to 2005 company performance and non-cash compensation of $1.2 million related to the amortization of deferred compensation associated with non-vested stock.
In 2004, we recorded $5.8 million in terminal development expenses related to the Corpus Christi LNG receiving terminal. This amount was partially offset by $2.9 million related to the minority interest of our 33.3% limited partner. Substantially all expenditures incurred through March 31, 2004 were the obligation of the minority owner, as the minority owner was required to fund 100% of the first $4.5 million of project expenditures. As project expenditures had reached $4.5 million by March 31, 2004, the minority owner began sharing all subsequent project expenditures based on its 33.3% limited partner interest. During 2004, we also incurred direct receiving terminal development expenses of $6.4 million related to Phase 1 of our Sabine Pass LNG receiving terminal and $375,000 related to our Creole Trail LNG receiving terminal, in each of which we own 100% of the projects. In addition, during 2004, we incurred $4.8 million in LNG employee-related costs. LNG employee-related costs for 2004 also included cash bonuses of $2.0 million and non-cash compensation of $928,000 (which included stock awards and amortization of deferred compensation associated with non-vested stock awards).
In 2005, our 30% equity share of the net loss of Freeport LNG resulted in a reported net loss of $1 million. In contrast, in 2004, our 30% equity share of the net loss of Freeport LNG was $1.3 million, including $278,000 of loss that was suspended as of December 31, 2003 (see Note 8 to our Consolidated Financial Statements).
In January 2004, we received the final $2.5 million payment from Freeport LNG pursuant to the terms of the agreement related to our February 2003 disposition of LNG assets in exchange for cash and a limited partner interest in Freeport LNG. Because our investment basis in Freeport LNG had been previously reduced to zero, the $2.5 million payment was recorded as a reimbursement from limited partnership investment in our consolidated statement of operations during the first quarter of 2004.
General and Administrative Expenses-General and administrative, or G&A, expenses increased $16.7 million, or 134%, to $29.1 million in 2005 compared to $12.5 million in 2004. The increase in G&A resulted primarily from the expansion of our business (including increases in corporate staff from an average of 14
employees in 2004 to an average of 47 employees in 2005). Corporate employee-related costs for 2005 included cash bonuses of $4.3 million and non-cash compensation of $2.2 million related to the amortization of deferred compensation associated with non-vested stock awards. Corporate employee-related costs for 2004 included cash bonuses of $2.2 million and non-cash compensation of $2.7 million (which included stock awards and amortization of deferred compensation associated with non-vested stock awards). We capitalize as oil and gas property costs that portion of G&A expenses directly related to our exploration and development activities. We capitalized $927,000 in 2005 compared to $1.6 million in 2004.
Depreciation, Depletion and Amortization Expenses-Depreciation, Depletion and Amortization, or DD&A, expenses increased $2.4 million, or 180%, to $3.7 million in 2005 from $1.3 million in 2004. The increase included $1.6 million in higher oil and gas DD&A as a result of an increase in our DD&A rate from $2.48 per Mcfe to $5.90 per Mcfe and the higher production volumes discussed below. Other DD&A also increased by $797,000 primarily as a result of higher depreciation expense associated with the acquisition of furniture, fixtures and equipment and office space leasehold improvements associated with the expansion of our business.
Derivative gain, net-During 2005, we recorded a net derivative gain of $837,000 attributable to the ineffective portion of our interest rate swaps.
Interest Expense-Interest expense, net of capitalization, was $17.4 million in 2005 compared to zero in 2004. This increase was attributable to the issuance of our Convertible Senior Unsecured Notes and completion of the Term Loan during the third quarter of 2005. Capitalized interest of $6.1 million in 2005 was primarily related to the amortization of debt issuance cost and commitment fees associated with the Sabine Pass Credit Facility.
Interest Income-Interest income increased to $17.5 million in 2005 from $501,000 in 2004 as a result of an increase in our cash and cash equivalent balances attributable primarily to our common stock offering in December 2004 and the issuance of our Convertible Senior Unsecured Notes and completion of the Term Loan in the third quarter of 2005.
Gain on Sale of Investment in Unconsolidated Affiliate-On August 31, 2005, Gryphon was sold for $283 million, plus assumption of $14 million of net debt in a merger with Woodside Energy (USA). We received net cash proceeds of $20.2 million for our interest, and since our investment balance was zero, we recognized a gain in 2005 equal to the net cash proceeds amount.
Oil and Gas Activities-Oil and gas revenues increased by $1.0 million, or 50%, to $3.0 million in 2005 from $2.0 million in 2004 as a result of a 22% increase in production volumes (409,000 Mcfe in 2005 compared with 337,000 Mcfe in 2004) and a 24% increase in average natural gas prices to $7.34 per Mcf in 2005 from $5.93 per Mcf in 2004. We produced from an average of 10 wells in both 2005 and 2004. Oil and gas production costs increased 102% to $237,000 in 2005 compared to $117,000 in 2004. This increase was primarily due to higher production taxes attributable to the higher production volumes and commodity prices during 2005.
Income Tax Benefit-A tax benefit of $2.0 million was recognized in 2005 relating to the portion of the change in our tax asset valuation account that is allocable to the deferred income tax on items reported in other comprehensive income on derivative instruments in accordance with Statement of Financial Accounting Standards, or SFAS, No. 109, Accounting for Income Taxes, and EITF Abstracts, Topic D-32.
Results of Operations-Comparison of the Fiscal Years Ended December 31, 2004 and 2003
Overview-Our financial results for the year ended December 31, 2004 reflected a net loss of $24.6 million, or $0.63 per share (basic and diluted), compared to a net loss of $5.3 million, or $0.18 per share (basic and diluted), in 2003.
The major factors contributing to our net loss during 2004 were: LNG receiving terminal development expenses of $17.2 million (which were partially offset by a $2.9 million minority interest in the operations of
Corpus Christi LNG) and general and administrative expenses of $12.5 million. These factors were partially offset by a $2.5 million reimbursement from our limited partnership investment in Freeport LNG.
LNG Receiving Terminal Development and Related Pipeline Activities-LNG receiving terminal development expenses were 156% higher in 2004 ($17.2 million) than in 2003 ($6.7 million). Because we have been in the preliminary stage of developing our LNG receiving terminals through December 31, 2004, substantially all of the costs to such date related to such activities were expensed. These costs primarily included professional fees associated with front-end engineering and design work, obtaining an order from FERC authorizing construction of our terminals and other required permitting for Phase 1 of the Sabine Pass LNG, Corpus Christi LNG and Creole Trail LNG receiving terminals and their related natural gas pipelines. The expenses of our LNG employees directly involved in the development of our LNG receiving terminals are also included. LNG receiving terminal development expenses were significantly higher in 2004 because we accelerated, beginning in the third quarter of 2003, the schedule of LNG receiving terminal development for Phase 1 of our Sabine Pass LNG receiving terminal as well as our Corpus Christi LNG receiving terminal. We accelerated the development of our Creole Trail LNG receiving terminal in the fourth quarter of 2004.
In 2004, we recorded $5.8 million in terminal development expenses related to the Corpus Christi LNG receiving terminal. This amount was partially offset by $2.9 million related to the minority interest of our 33.3% limited partner. Substantially all expenditures incurred through March 31, 2004 were the obligation of the minority owner, as the minority owner was required to fund 100% of the first $4.5 million of project expenditures. As project expenditures had reached $4.5 million by March 31, 2004, the minority owner began sharing all subsequent project expenditures based on its 33.3% limited partner interest. Also during 2004, we incurred direct receiving terminal development expenses of $6.4 million related to Phase 1 of our Sabine Pass LNG receiving terminal and $375,000 related to our Creole Trail LNG receiving terminal, in each of which we own 100% of the projects. In addition, during 2004, we incurred $4.8 million in LNG employee-related costs. In connection with the expansion of our LNG receiving terminal business, our employee costs increased, as we expanded our LNG staff from four employees during 2003 to an average of 15 employees during 2004. LNG employee-related costs for 2004 also included cash bonuses of $2 million and non-cash compensation of $928,000 (which included stock and non-vested stock awards) related to our 2003 and 2004 company performance.
In 2003, we incurred $6.7 million in LNG receiving terminal development expenses. Of this amount, $3 million related to development costs for the Corpus Christi LNG project. However, these costs were entirely offset by the minority interest of our 33.3% limited partner as discussed above. Also during 2003, we incurred $3.7 million primarily for development expenses related to Phase 1 of our Sabine Pass LNG project and LNG employee-related costs.
In February 2003, our Freeport LNG receiving terminal project was acquired by Freeport LNG, from whom we retained a 40% limited partnership interest and received payments totaling $5 million over time. In connection with the sale of LNG assets to Freeport LNG, we reported a gain of $4.8 million. We also sold a 10% interest in Freeport LNG in March 2003 for $2.3 million, resulting in a gain of $423,000. During 2003, we received payments totaling $2.5 million from Freeport LNG, plus $1.7 million in reimbursement of project costs, which were recorded as a reduction to our investment in the partnership. In addition, during 2003 we recorded our equity share ($4.5 million) related to the 2003 loss incurred by Freeport LNG, which reduced our investment basis to zero as of December 31, 2003. In January 2004, we received the final $2.5 million payment from Freeport LNG. Because our investment basis in Freeport LNG had been reduced to zero, the payment was recorded as a reimbursement from limited partnership investment in our consolidated statement of operations for 2004.
In 2004, our 30% equity share of the net loss from Freeport LNG was $1.3 million, including $278,000 of loss that was suspended as of December 31, 2003 (see Note 8 to our Consolidated Financial Statements). This compares to our equity share of the loss of $4.5 million for 2003. The significant improvement between periods for Freeport LNG was a result of Freeport LNG’s receipt of a non-refundable fee of $10 million from ConocoPhillips in January 2004.
General and Administrative Expenses-G&A expenses increased $9.9 million, or 391%, to $12.5 million in 2004 compared to $2.5 million in 2003. The increase in G&A resulted primarily from the expansion of our business (including increases in average corporate staff from an average of 5 employees in 2003 to an average of 16 employees in 2004). Corporate employee-related costs for 2004 also included cash bonuses of $2.2 million and non-cash compensation of $2.7 million (which included stock and non-vested stock awards) related to our 2003 and 2004 company performance. We capitalize as oil and gas property costs that portion of G&A expenses directly related to our exploration and development activities. We capitalized $1.6 million in 2004 compared to $976,000 in 2003.
Depreciation, Depletion and Amortization Expenses-DD&A expenses increased $895,000, or 209%, to $1.3 million in 2004 from $429,000 in 2003. The increase primarily resulted from higher oil and gas DD&A as a result of an increase in our DD&A rate from $0.98 per Mcfe to $2.48 per Mcfe and higher production volumes discussed below. DD&A also increased as a result of more depreciation expense resulting from the acquisition of furniture, fixtures and equipment associated with the expansion of our business.
Interest Income-Interest income increased to $501,000 in 2004 from $3,000 in 2003 primarily because of an increase in our cash balance resulting from our $300 million public equity offering of our common stock in December 2004 (before related offering costs of $14.1 million). In addition, we received $22 million in advance regasification capacity payments in November and December of 2004 and raised $20 million in net cash proceeds related to a private placement of our common stock and exercises of options and warrants to purchase our common stock during 2004.
Oil and Gas Activities-Oil and gas revenues increased by $1.3 million, or 204%, to $2 million in 2004 from $658,000 in 2003 as a result of a 173% increase in production volumes (336,849 Mcfe in 2004 compared with 123,494 Mcfe in 2003) and an 11% increase in average natural gas prices to $5.93 per Mcf in 2004 from $5.33 per Mcf in 2003. We produced from an average of 10 wells in 2004 as compared with an average of 7 wells in 2003. We incurred little or no production cost in 2003 and 2004 because all of our revenues were generated from non-cost bearing overriding royalty interests, or ORRI, until December 2004. The small amount of production costs in 2004 is attributable to our share of production taxes on two producing wells located in Texas state waters and operating costs attributable to a well converted from an ORRI to a working interest at payout in December 2004.
Other Matters
Critical Accounting Estimates and Policies
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. We make every effort to properly comply with all applicable rules on or before their adoption, and believe 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.
Accounting for LNG Activities
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 natural gas pipelines.
Costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land costs, costs of lease options and the cost of certain permits which are capitalized as intangible LNG assets. The costs of lease options are amortized over the life of the lease once it is obtained. If no lease is obtained, the costs are expensed. Site rental costs and related amortization of capitalized options have been capitalized during the construction period through the end of 2005. Beginning in 2006, such costs will be expensed as required by FSP 13-1.
During the construction periods of our LNG receiving terminals and related pipelines, we capitalize interest and other related debt costs in accordance with the FASB 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.
Full Cost Method of Accounting
We follow the full cost method of accounting for our oil and gas properties. Under this method, all productive and non-productive exploration and development costs incurred for the purpose of finding oil and gas reserves are capitalized. Such capitalized costs include lease acquisition, geological and geophysical work, delay rentals, drilling, completing and equipping oil and gas wells, together with internal costs directly attributable to property acquisition, exploration and development activities.
The costs of our oil and gas properties, including the estimated future costs to develop proved reserves and the carrying amounts of any asset retirement obligations, are depreciated using a composite unit-of-production rate based on estimates of proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, then the amount of the impairment is added to the capitalized costs to be amortized. Net capitalized costs are limited to a capitalization ceiling, calculated on a quarterly basis as the aggregate of the present value, discounted at 10%, of estimated future net revenues from proved reserves (based on current economic and operating conditions), but excluding asset retirement obligations, plus the lower of cost or fair market value of unproved properties, less related income tax effects.
Our allocation of seismic exploration costs between proved and unproved properties involves an estimate of the total reserves to be discovered through our exploration program. This estimate includes a number of assumptions that we have incorporated into a three-year plan. Such factors include an estimate of the number of exploration prospects generated, prospect reserve potential, success ratios and ownership interests. We transfer unproved properties to proved properties based on a ratio of proved reserves discovered at a point in time to the estimate of total reserves to be discovered in our exploration program. The carrying value of unproved properties is evaluated for possible impairment by comparing it to the estimated future net cash flows associated with the estimated total reserves to be discovered in our exploration program. To the extent that the carrying value of unproved properties is greater than the estimated future net revenue, any excess is transferred to proved properties. It is reasonably possible, based on the results obtained from future drilling and prospect generation, that revisions to this estimate of total reserves to be discovered could affect our capitalization ceiling.
Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved oil and gas reserves.
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 using the unit-of-production method used to depreciate oil and gas properties under the full cost method of accounting.
Oil and Gas Reserves
The process of estimating quantities of proved reserves is inherently uncertain, and our reserve data are only estimates. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and crude oil that cannot be measured in an exact manner. The process relies on interpretations of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgment of the persons preparing the estimate. At least annually, our reserves are estimated by an independent petroleum engineer.
Because these estimates depend on many assumptions, all of which may substantially differ from actual results, reserve estimates may be different from the quantities of natural gas and crude oil that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.
The present value of future net cash flows does not necessarily represent the current market value of our estimated proved natural gas and oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate.
Our rate of recording DD&A is dependent upon our estimate of proved reserves. If the estimate of proved reserves declines, the rate at which we record DD&A expense increases thereby reducing net income. Such a decline may result from lower market prices, which may make it uneconomical to drill for and produce higher cost fields.
Cash Flow Hedges
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. Any ineffective portion will be reflected in earnings.
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 9 to our Consolidated Financial Statements.
New Accounting Pronouncements
In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment, that addresses the accounting for share-based payment transactions in which a company receives employee services in exchange for equity instruments of the company, such as stock options and non-vested stock. SFAS No. 123R eliminates the ability to account for share-based compensation transactions using APB Opinion No. 25 and requires instead that such transactions be accounted for using a fair value-based method. From inception through December 31, 2005, we have accounted for stock-based compensation using the intrinsic value method pursuant to APB Opinion No. 25. SFAS No. 123R requires that all stock-based payments to employees, including grants of employee stock options and non-vested stock, be recognized as compensation expense in the financial statements based on their fair values (intrinsic value in the case of non-vested stock) at the time such awards are granted. SFAS No. 123R is effective January 1, 2006 for companies with fiscal years ending December 31. Accordingly, we will begin reporting the results of SFAS No. 123R on our operations in the quarter ending March 31, 2006. We are adopting the new standard using the modified-prospective transition method. The adoption of the new standard will have a significant future impact on our results of operations, but will have no impact on our cash flows. Had we adopted SFAS No. 123R in prior periods, the effects of that standard on net income and earnings per share would have been approximately the same as the effects of SFAS No. 123 presented in the Stock-Based Compensation pro forma disclosure included in Note 2 of our Consolidated Financial Statements.
In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections-A Replacement of APB Opinion No. 20 and FASB Statement No. 3. SFAS No. 154 changes the requirements for accounting and reporting on a change in accounting principle, while carrying forward the guidance in APB Opinion No. 20, Accounting Changes and FASB Statement No. 3, Reporting Accounting Changes in Interim Financial Statements, with respect to accounting for changes in estimates, changes in the reporting entity and the correction of errors. APB Opinion No. 20 previously required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change, the cumulative effect of changing to the new accounting principle. SFAS No. 154 requires retrospective application to prior periods’ financial statements for voluntary changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The impact of SFAS No. 154 will depend on the accounting change that may occur in a future period.
In October 2005, the FASB issued FSP 13-1 to address the accounting for rental costs associated with operating leases that are incurred during a construction period. FSP 13-1 requires rental costs associated with ground or building operating leases that are incurred during a construction period to be recognized as rental expense. FSP 13-1 is effective in fiscal years beginning after December 15, 2005. Accordingly, we will adopt the new standard in the quarter ending March 31, 2006. As of December 31, 2005, we have capitalized $1.5 million in rental expenses related to our Sabine Pass LNG terminal site lease.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The development of our LNG receiving terminal business is based upon the foundational premise that prices of natural gas in the U.S. will be sustained at levels of $3.00 per Mcf or more. Should the price of natural gas in the U.S. decline to sustained levels below $3.00 per Mcf, our ability to develop and operate LNG receiving terminals could be significantly negatively affected.
We produce and sell natural gas, crude oil and condensate. As a result, our financial results can be affected as these commodity prices fluctuate widely in response to changing market forces. We have not entered into any derivative transactions related to our oil and gas producing activities.
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.
Interest Rates
We are exposed to changes in interest rates, primarily as a result of our debt obligations. The fair value of our fixed rate debt is affected by changes in market rates. We utilize interest rate swap agreements to mitigate exposure to rising interest rates. We do not use interest rate swap agreements for speculative or trading purposes.
In connection with the closing of the Sabine Pass Credit Facility in February 2005, we entered into interest rate swap agreements to hedge against increases in floating interest rates with respect to draws, up to a maximum of $700 million under this facility. No debt was outstanding under this facility at December 31, 2005.
At December 31, 2005, we had $923.5 million of debt outstanding. Of this amount, our $325 million of Convertible Senior Unsecured Notes bore a fixed interest rate of 2.25%. The Term Loan, totaling $598.5 million, bore interest at floating rates; however, concurrent with the closing of the Term Loan, we entered into interest rate swaps with respect to this loan. (See Note 10 to our Consolidated Financial Statements)
The following table summarizes the fair market values of our existing interest rate swap agreements as of December 31, 2005 (in thousands):
Variable to Fixed Swaps
(1) The fair market value is based upon a marked-to-market calculation utilizing an extrapolation of third-party mid-market LIBOR rate quotes at December 30, 2005.
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
Consolidated Balance Sheet
Consolidated Statement of Operations
Consolidated Statement of Stockholders’ Equity
Consolidated Statement of Cash Flows
Notes to Consolidated Financial Statements
Supplemental Information to Consolidated Financial Statements-Oil and Gas Reserves and Related Financial Data
Supplemental Information to Consolidated Financial Statements-Summarized Quarterly Financial Data
MANAGEMENT’S REPORTS TO THE STOCKHOLDERS OF CHENIERE ENERGY, INC.
Management’s Report on Internal Control Over Financial Reporting
As management, we are responsible for establishing and maintaining adequate internal control over financial reporting for Cheniere Energy, Inc. and its subsidiaries, or 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, 2005, based on criteria in Internal Control-Integrated Framework issued by the COSO. Our assessment of the effectiveness of Cheniere’s internal control over financial reporting as of December 31, 2005, has been audited by UHY Mann Frankfort Stein & Lipp CPAs, LLP, an independent registered public accounting firm, as stated in their report which is included herein.
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
Don A. Turkleson
Senior Vice President
and Chief Financial Officer
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and
Stockholders of Cheniere Energy, Inc.:
We have audited the accompanying consolidated balance sheets of Cheniere Energy, Inc. and subsidiaries, or the Company, as of December 31, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2005. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We did not audit the financial statements of Freeport LNG Development, L.P., or Freeport LNG, an investment which, as discussed in Note 8 to the consolidated financial statements, is accounted for by the equity method of accounting. The investment in Freeport LNG was zero and $(1,071,000) as of December 31, 2005 and 2004, respectively, and the equity in its net loss was $1,031,000, $1,346,000 and $4,471,000, respectively, for each of the three years in the period ended December 31, 2005. The financial statements of Freeport LNG were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Freeport LNG, are based solely on the report of the other auditors.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report of other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Cheniere Energy, Inc. and subsidiaries at December 31, 2005 and 2004, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Cheniere Energy, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 10, 2006 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.
/s/ UHY MANN FRANKFORT STEIN & LIPP CPAs, LLP
UHY MANN FRANKFORT STEIN & LIPP CPAs, LLP
Houston, Texas
March 10, 2006
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and
Stockholders of Cheniere Energy, Inc.:
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting appearing on page 73, that Cheniere Energy, Inc. and subsidiaries, or the Company, maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’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. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, 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, management’s assessment that Cheniere Energy, Inc. and subsidiaries maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control-Integrated Framework issued by COSO. Also, in our opinion, Cheniere Energy, Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control-Integrated Framework issued by COSO.
We have also 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, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2005, and our report dated March 10, 2006 expressed an unqualified opinion on those consolidated financial statements.
/s/ UHY MANN FRANKFORT STEIN & LIPP CPAs, LLP
UHY MANN FRANKFORT STEIN & LIPP CPAs, LLP
Houston, Texas
March 10, 2006
CHENIERE ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(in thousands, except share data)
The accompanying notes are an integral part of these 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.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(in thousands)
The accompanying notes are an integral part of these 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.
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. As used in these Notes to Consolidated Financial Statements, the terms “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 LNG receiving terminals, and related natural gas pipelines, along the Gulf Coast of the United States. We are also engaged, to a limited extent, in oil and natural gas exploration and development activities in the Gulf of Mexico.
NOTE 2-SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
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 and cost methods of accounting. All significant intercompany accounts and transactions have been eliminated in consolidation. Certain items in the prior year financial statements have been reclassified to conform with the 2005 presentation.
All references to issued and outstanding shares, weighted average shares, and per share amounts in the accompanying consolidated financial statements have been retroactively adjusted to reflect our two-for-one stock split that occurred on April 22, 2005.
Accounting for LNG Activities
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 natural gas pipelines.
Costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land costs, costs of lease options and the cost of certain permits which are capitalized as intangible LNG assets. The costs of lease options are amortized over the life of the lease once it is obtained. If no lease is obtained the costs are expensed. Site rental costs and related amortization of capitalized options have been capitalized during the construction period through the end of 2005. Beginning in 2006, such costs will be expensed as required by Financial Accounting Standards Board, or FASB, Staff Position, or FSP, 13-1, Accounting for Rental Cost Incurred During Construction.
During the construction periods of our LNG receiving terminals and related pipelines, we capitalize interest and other related debt costs in accordance with Statement of Financial Accounting Standards, or 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.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Full Cost Method of Accounting
We follow the full cost method of accounting for our oil and gas properties. Under this method, all productive and nonproductive exploration and development costs incurred for the purpose of finding oil and gas reserves are capitalized. Such capitalized costs include lease acquisition, geological and geophysical work, delay rentals, drilling, completing and equipping oil and gas wells, together with internal costs directly attributable to property acquisition, exploration and development activities. We capitalized general and administrative expenses, totaling $927,000, $1,569,000 and $976,000 for the years 2005, 2004 and 2003, respectively.
The costs of our oil and gas properties, including the estimated future costs to develop proved reserves and the carrying amounts of any asset retirement obligations, are depreciated using a composite unit-of-production rate based on estimates of proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, then the amount of the impairment is added to the capitalized costs being amortized. Net capitalized costs are limited to a capitalization ceiling, calculated on a quarterly basis as the aggregate of the present value, discounted at 10%, of estimated future net revenues from proved reserves (based on current economic and operating conditions), but excluding asset retirement obligations, plus the lower of cost or fair market value of unproved properties, less related income tax effects.
Our allocation of seismic exploration costs between proved and unproved properties involves an estimate of the total reserves to be discovered through our exploration program. This estimate includes a number of assumptions that we have incorporated into a three-year plan. Such factors include an estimate of the number of exploration prospects generated, prospect reserve potential, success ratios and ownership interests. We transfer seismic exploration costs to proved properties based on a ratio of proved reserves discovered at a point in time to the estimate of total reserves to be discovered in our exploration program. The carrying value of unproved properties is evaluated for possible impairment by comparing it to the estimated future net cash flows associated with the estimated total reserves to be discovered in our exploration program. To the extent that the carrying value of unproved properties is greater than the estimated future net revenue, any excess is transferred to proved properties. It is reasonably possible, based on the results obtained from future drilling and prospect generation, that revisions to this estimate of total reserves to be discovered could affect our capitalization ceiling.
Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved oil and gas reserves.
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 using the unit-of-production method used to depreciate oil and gas properties under the full cost method of accounting.
On January 1, 2003, the date of adoption of SFAS No. 143, we had no legal obligations associated with the retirement of any long-lived assets, as all of our oil and gas property interests were non-cost bearing overriding royalty interests, or ORRI. In 2004, we converted an ORRI to a working interest at well payout. As a result, we recorded $97,000, the present value of the expected abandonment cost of the well and related equipment, as a long-term asset retirement obligation and a corresponding amount to proved oil and gas properties. Accretion expense for 2005 and 2004 was $3,000 and $2,000, respectively, and was included in depreciation, depletion and amortization expense. The resulting long-term asset retirement obligation was $102,000 at December 31, 2005.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Revenue Recognition
LNG regasification capacity fees are recognized as revenue over the term of the respective terminal use agreement, or TUA. Advance 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 under produced 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, 2005 and 2004, we had no gas imbalances.
Fixed Assets
Fixed assets are recorded at cost. Repairs and maintenance costs are charged to operations as incurred. Depreciation is computed using the straight-line method over estimated useful lives of the assets, which range from two to ten years. Upon retirement or other disposition of fixed assets, the cost and related accumulated depreciation are removed from the account and the resulting gains or losses are recorded.
Offering Costs
Offering costs consist primarily of underwriter’s fees, placement fees, professional fees, legal fees and printing costs. These costs are charged against the related proceeds from the sale of common stock in the periods in which they occur or charged to expense in the event of a terminated offering.
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
Cash flow hedges are used to limit our exposure to variability in expected future cash flows (in our case, the variability of floating interest rate exposure). 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, Accounting for Derivative Instruments and Hedging Activities, as amended, 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. Any ineffective portion will be reflected in earnings.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires that we make estimates and assumptions that affect the amounts reported in the consolidated financial statements and the accompanying notes. Actual results could differ from the estimates and assumptions used. Depletion of oil and gas properties is determined using estimates of proved oil and gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves. Similarly, total reserves to be discovered through our exploration program are subject to numerous uncertainties including estimates of future recoverable reserves and commodity price outlook. Other estimates which may impact our financial statements include the fair value of our interest rate derivatives and estimates used in determining the effectiveness of derivatives designated as hedges.
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.
Commodity Price Risk
We produce and sell natural gas, crude oil and condensate. As a result, our financial results can be affected as these commodity prices fluctuate widely in response to changing market forces. We had not entered into any commodity hedging transactions as of December 31, 2005.
Concentration of Credit Risk
All of our revenues are attributable to properties operated by three companies. These companies sell our share of production for us, pay the associated severance taxes, and remit the balance to us. Our products are commodities and have a readily available market for sale.
We maintain funds in bank accounts that exceed the limit insured by the Federal Deposit Insurance Corporation, or FDIC. Accounts are guaranteed by the FDIC up to $100,000. The risk of loss attributable to these uninsured balances is mitigated by depositing funds only in commercial banks with minimum Standard & Poor’s and Moody’s Investor Service ratings of A and Aa3, respectively. We have not experienced any losses in such accounts.
We have entered into certain long-term TUAs with unaffiliated third parties for regasification capacity at our proposed 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 with creditworthy third-party customers with a minimum Standard & Poor’s rating of AA.
Goodwill
As further described in Note 9-“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
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
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 indicate 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 amortized to interest expense over the term of the related debt facility.
Stock-Based Compensation
SFAS No. 123, Accounting for Stock-Based Compensation, encourages, but does not require, companies to record compensation cost for stock-based employee compensation plans at fair value. In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based Compensation-Transition and Disclosure-an amendment of SFAS No. 123, to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. The statement also amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based compensation and the effect of the method used on reported results.
We have chosen to continue to account for stock-based compensation issued to employees using the intrinsic value method prescribed in Accounting Principles Board, or APB, Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. Accordingly, compensation cost for stock options is measured as the excess, if any, of the quoted market price of our stock at the date of the grant over the amount an employee must pay to acquire the stock. We grant options at or above the market price of its common stock at the date of each grant.
The fair value of options is calculated using the Black-Scholes option-pricing model. Had we adopted the fair value method of accounting for stock-based compensation, compensation expense would have been higher, and net loss attributable to common stockholders would have increased for the periods presented. No change in cash flows would occur. The effects of applying SFAS No. 123 in this pro forma disclosure are not indicative of future amounts.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
From our inception, we have recorded annual net operating losses for both financial reporting purposes and for federal and state income tax reporting purposes. Accordingly, we are not presently a taxpayer, and therefore there is no tax effect on stock-based employee compensation expense.
The weighted average fair value of warrants and options granted as employee compensation during 2005, 2004 and 2003 was $20.16, $5.82 and $0.72, respectively. The fair values were determined using the Black-Scholes option-pricing model with the following weighted average assumptions, and a forfeiture rate that is assumed to be negligible:
Net Loss Per Share
Net loss per share, or 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 and warrants 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 2005, 2004 and 2003 were 5,680,000, 3,133,000 and 6,519,000 respectively. In addition, common shares of 3,972,000 on a weighted average basis, issuable upon conversion of the Convertible Senior Unsecured Notes (described in Note 14-“Long-Term Debt”), were not included in the computation of diluted net loss per share for 2005 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.
We entered into an issuer call spread (an instrument that combines the purchase and sale of call options on our common stock) to offset the potential dilution from conversion of our Convertible Senior Unsecured Notes. Purchased call options are always excluded from the calculation of diluted earning per share because they are anti-dilutive. SFAS No. 128 requires that we include the sold call options in the calculation of diluted earnings per share using the treasury stock method whenever the average market price of our common shares exceeds the strike price of the call options. The strike price of the sold call options is $70 per share, which is greater than the average market price of our common stock for 2005; thus, the sold call options were not included in the calculation of diluted earning per share. The total number of shares that could potentially be included under the sold call options is 9,176,000.
New Accounting Pronouncements
In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment, that addresses the accounting for share-based payment transactions in which a company receives employee services in exchange for equity instruments of the company, such as stock options and non-vested stock. SFAS No. 123R eliminates the ability to account for share-based compensation transactions using APB Opinion No. 25 and requires instead that such
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
transactions be accounted for using a fair value-based method. From inception through December 31, 2005, we have accounted for stock-based compensation using the intrinsic method pursuant to APB Opinion No. 25. SFAS No. 123R requires that all stock-based payments to employees, including grants of employee stock options and non-vested stock, be recognized as compensation expense in the financial statements based on their fair values (intrinsic valued in the case of restricted stock) at the time such awards are granted. SFAS No. 123R is effective January 1, 2006 for companies with fiscal years ending December 31. Accordingly, we will begin reporting the results of SFAS No. 123R on our operations in the quarter ending March 31, 2006. We are adopting the new standard using the modified-prospective transition method. The adoption of the new standard will have a significant future impact on our results of operations, but will have no impact on our future cash flows. Had we adopted SFAS No. 123R in prior periods, the effects of that standard on net income and earnings per share would have been approximately the same as the effects of SFAS No. 123 shown in the Stock-Based Compensation proforma disclosure presented previously.
In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections-A Replacement of APB Opinion No. 20 and FASB Statement No. 3. SFAS No. 154 changes the requirements for accounting and reporting on a change in accounting principle, while carrying forward the guidance in APB Opinion No. 20, Accounting Changes and FASB Statement No. 3, Reporting Accounting Changes in Interim Financial Statements, with respect to accounting for changes in estimates, changes in the reporting entity and the correction of errors. APB Opinion No. 20 previously required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change, the cumulative effect of changing to the new accounting principle. SFAS No. 154 requires retrospective application to prior periods’ financial statements for voluntary changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The impact of SFAS No. 154 will depend on an accounting change that may occur in a future period.
In October 2005, the FASB issued FSP 13-1, Accounting for Rental Costs Incurred During a Construction Period, to address the accounting for rental costs associated with operating leases that are incurred during a construction period. FSP 13-1 requires rental costs associated with ground or building operating leases that are incurred during a construction period to be recognized as rental expense. FSP 13-1 is effective in fiscal years beginning after December 15, 2005. Accordingly, we will adopt the new standard in the quarter ending March 31, 2006. As of December 31, 2005, we have capitalized $1,501,000 in rental costs related to our Sabine Pass LNG receiving terminal site lease. We began expensing these rental costs effective January 1, 2006.
NOTE 3-RESTRICTED CASH AND CASH EQUIVALENTS
In February 2005, Sabine Pass LNG, L.P., our wholly-owned subsidiary, or Sabine Pass LNG, entered into an $822,000,000 credit facility, or the Sabine Pass Credit Facility, with an initial syndicate of 47 financial institutions. Société Générale serves as the administrative agent and HSBC Bank USA, National Association, or HSBC, serves as collateral agent. Under the terms and conditions of the Sabine Pass Credit Facility, all cash held by Sabine Pass LNG is controlled by the collateral agent. These funds can only be released by the collateral agent upon receipt of satisfactory documentation that the Sabine Pass LNG Phase 1 project costs are bona fide expenditures and are permitted under the terms of the Sabine Pass Credit Facility. The Sabine Pass Credit Facility does not permit Sabine Pass LNG to hold any cash, or cash equivalents, outside of the accounts established under the agreement. Because these cash accounts are controlled by the collateral agent, the Sabine Pass LNG cash balance of $8,871,000 held in these accounts as of December 31, 2005 is classified as restricted on our balance sheet.
In August 2005, Cheniere LNG Holdings, LLC, our wholly-owned subsidiary, or Cheniere LNG Holdings, entered into a $600,000,000 Senior Secured Term Loan, or the Term Loan, with Credit Suisse, Cayman Islands
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Branch, or Credit Suisse, who also serves as collateral agent and administrative agent. Under the conditions of the Term Loan, Cheniere LNG Holdings was required to fund from the loan proceeds a total of $216,200,000 into two collateral accounts: $181,000,000 into a debt service reserve collateral account and $35,200,000 into a capital contribution reserve collateral account. These funds are restricted to the payment of interest and principal due under the Term Loan, reimbursement of certain expenses, and funding of additional capital contributions to Sabine Pass LNG as required under the Sabine Pass Credit Facility. As of December 31, 2005, all additional capital contributions contemplated by the Term Loan have been funded to Sabine Pass LNG. Because the accounts are controlled by the collateral agent, our cash and cash equivalent balance of $168,514,000 held in these accounts as of December 31, 2005 is classified as restricted on our consolidated balance sheet. Of this amount, $16,500,000 is classified as non-current due to the timing of certain required debt amortization payments.
NOTE 4-RESTRICTED CERTIFICATE OF DEPOSIT AND LETTER OF CREDIT
Under the terms of our office lease, we are required to post a standby letter of credit in favor of the lessor. The initial amount of the letter of credit was increased from $865,000 to $1,123,000 in April 2004, which related to the expansion of our office space; and the amount will be reduced by approximately $225,000 per annum over a five-year period. This letter of credit was initially established under the terms of our bank line of credit in effect at that time.
Upon the termination of our bank line of credit in June 2004, we purchased a certificate of deposit in the amount of $1,123,000 and entered into a pledge agreement in favor of the commercial bank that had previously issued the standby letter of credit for $1,123,000. In October 2004 and 2005, both the letter of credit and certificate of deposit were amended to decrease the face amounts by approximately $225,000 to $898,000 and $674,000, respectively. The current letter of credit and the certificate of deposit both mature on November 30, 2006. Under the terms of the pledge agreement, the commercial bank was assigned a security interest in the certificate of deposit as collateral for the letter of credit. As a result, the certificate of deposit plus $2,000 of accrued interest is classified as restricted on our balance sheet at December 31, 2005.
NOTE 5-ADVANCES TO EPC CONTRACTOR
In December 2004, Sabine Pass LNG entered into a lump-sum turnkey EPC contract with Bechtel Corporation, or Bechtel, to construct the initial phase, or Phase 1, of the Sabine Pass LNG receiving terminal. Under the EPC contract, we were required to make a 5% advance payment to Bechtel upon issuance of the final notice to proceed, or NTP, related to the construction of Phase 1. A payment of $32,347,000 was made to Bechtel in March 2005 when the NTP was issued and that amount was classified on our consolidated balance sheet as a current asset. In accordance with the payment schedule included in the EPC contract, $2,696,000 per month is being reclassified to construction-in-progress over a twelve-month period. As of December 31, 2005, the remaining balance of the advance was $8,087,000.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
NOTE 6-PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment is comprised of LNG terminal construction-in-progress expenditures, LNG site and related costs, investments in oil and gas properties, and fixed assets, as follows (in thousands):
In February 2005, Phase 1 of our Sabine Pass LNG project satisfied the criteria for capitalization. Accordingly, costs associated with the construction of Phase 1 of our Sabine Pass LNG project have been capitalized as construction-in-progress since that time.
We have made investments in acquiring, processing and reprocessing our seismic databases covering a 6,800-square-mile project area offshore Texas and Louisiana and a 228-square-mile project area onshore and offshore Louisiana. The costs of these projects become subject to amortization on a ratable basis as the oil and gas reserves expected to be recovered from the projects are discovered. We began drilling prospects identified within our seismic databases in 1999. We did not participate directly in drilling any wells during the period from 2001 through 2004, but we retained overriding royalty interests in wells drilled by others on prospects we generated during such period; however, in 2005, we participated directly in the drilling of two wells.
Depreciation, depletion and amortization of oil and gas property costs totaled $2,415,000, $835,000 and $121,000 for the years ended December 31, 2005, 2004 and 2003, respectively. Depreciation, depletion and amortization per equivalent Mcf (using an Mcf-to-barrel conversion factor of 6 to 1) was $5.90, $2.48 and $0.98 for the years ended December 31, 2005, 2004 and 2003, respectively.
Depreciation expense related to our fixed assets totaled $1,284,000, $410,000 and $165,000 for the years ended December 31, 2005, 2004 and 2003, respectively.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
NOTE 7-DEBT ISSUANCE COSTS
As of December 31, 2005, we have capitalized $43,008,000 of costs directly associated with the arrangement of debt financing, net of accumulated amortization, as follows:
(1) Debt issuance costs are amortized over the term of the related debt facility.
(2) Although no borrowings were outstanding as of December 31, 2005, the amortization of the debt issuance cost is recorded to interest expense and subsequently capitalized as construction-in-progress during the construction period of the Sabine Pass LNG receiving terminal. For the year ended December 31, 2005, the amount amortized and capitalized was $1,679,000.
(3) For the year ended December 31, 2005, the amount amortized to interest expense was $589,000.
(4) For the year ended December 31, 2005, the amount amortized to interest expense was $761,000.
Scheduled amortization of these debt issuance costs for each of the next five years is estimated at $5,693,000.
NOTE 8-INVESTMENT IN LIMITED PARTNERSHIP
In August 2002, we entered into an agreement with entities controlled by Michael S. Smith, or Smith entities, to sell a 60% interest in the Freeport site and project. On February 27, 2003, we sold our interest in the site and project to Freeport LNG Development, L.P., or Freeport LNG, in which we held a 40% limited partner interest. Smith entities held the general partner interest and remaining 60% limited partner interest in Freeport LNG. We recovered $1,740,000 in costs that we had incurred on the project and received an additional $5,000,000 ($2,500,000 during 2003 and $2,500,000 in January 2004) from Freeport LNG. For the funding of Freeport LNG project development costs, Smith entities also committed to contribute up to $9,000,000 and to allocate available proceeds from any sales of options or capacity reservations and/or proceeds from loans related to capacity reservations to these costs. In connection with the closing, we issued warrants to Smith entities to purchase 1,400,000 shares of our common stock at a price of $1.25 per share, exercisable for a period of 10 years.
We accounted for the transfer of the site and planned LNG receiving terminal to Freeport LNG in accordance with Emerging Issues Task Force, or EITF, Issue No. 01-2, Interpretations of APB Opinion No. 29. Accordingly, in 2003 we recorded a $4,760,000 gain on sale of LNG assets to the extent of the 60% interest not retained.
Effective March 1, 2003, we sold a 10% limited partner interest in Freeport LNG to an affiliate of Contango Oil & Gas Company, or Contango, for $2,333,000 payable over time, including the cancellation of our $750,000 short-term note payable. We also issued warrants to Contango to purchase 600,000 shares of our common stock at a price of $1.25 per share, exercisable for a period of 10 years. As a result of the sale, we now hold a 30% limited partner interest in Freeport LNG. In December 2004, a subsidiary of The Dow Chemical Company, or Dow, acquired a 15% limited partner interest in Freeport LNG from one of the Smith entities, thereby reducing its limited partner interest from 60% to 45%.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
We account for our 30% limited partnership investment in Freeport LNG using the equity method of accounting. During 2003, we received installment payments totaling $2,500,000 from Freeport LNG, which amounts were recorded as a reduction to the basis of our investment in the partnership. In addition, we recorded $4,471,000 related to our 30% equity share of the 2003 net loss of Freeport LNG. This non-cash loss reduced the basis of our investment in Freeport LNG to zero, and as a result, we did not record $278,000, or the 2003 Suspended Loss, of our equity share of the loss of the partnership as of December 31, 2003 because we did not guarantee any obligations of Freeport LNG and had not committed to provide additional financial support to Freeport LNG at that time.
In January 2004, we received the final $2,500,000 payment from Freeport LNG. As our investment basis in Freeport LNG had been reduced to zero as of December 31, 2003, the payment was recorded as a reimbursement from limited partnership investment in our consolidated statement of operations.
During 2004, we recorded $1,346,000 related to our 30% equity share of the 2004 net loss of Freeport LNG, including the 2003 Suspended Loss. This $1,346,000 non-cash loss reduced our investment basis to zero and resulted in our recording accrued losses on investment in limited partnership of $1,071,000 as of December 31, 2004. We accrued this liability, as we intended to provide additional financial support through the payment of outstanding capital call notices as of December 31, 2004. This additional financial support was provided in 2005 as a portion of the capital call payments discussed below.
During 2005, we paid $2,102,000 of capital call contributions to Freeport LNG. In addition, we recognized an equity loss in the amount of $1,031,000 relating to the net loss of Freeport LNG. Our total 30% equity share of the 2005 net loss of Freeport LNG was $4,999,000 of which $3,968,000 was suspended, or the 2005 Suspended Loss. In December 2005, Freeport LNG announced that it had closed a $383,000,000 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. Accordingly, we do not currently have the obligation or intent to fund our suspended losses in the foreseeable future. As a result, as of December 31, 2005, the basis of our equity investment in Freeport LNG was zero, and we did not have any accrued losses.
The financial position of Freeport LNG at December 31, 2005 and 2004 and the results of Freeport LNG’s operations for the years ended December 31, 2005, 2004 and 2003 are summarized as follows (in thousands):
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
NOTE 9-GOODWILL
In February 2005, we acquired the minority interest of Corpus Christi LNG, L.P., or Corpus Christi LNG, through the acquisition of BPU LNG, Inc., or BPU, in exchange for 2,000,000 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 now own 100% of the limited partner interest 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 $77,246,000, including direct transaction costs. Of this amount, $76,844,000 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 generally accepted accounting principles plus direct transaction costs. For the calculation of federal income taxes, none of this goodwill amount will be deductible.
We performed an annual goodwill impairment review in the fourth quarter of 2005. A goodwill impairment review consists of comparing the carrying value, including goodwill, of the reporting unit under review, to the estimated fair value of the reporting unit. To the extent that the carrying value exceeds the estimated fair value of the reporting unit, an impairment of the reporting unit would occur 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 review, we have designated our LNG receiving terminal business as the reporting unit under review due to similar economic characteristics. Our review indicated that no impairment of goodwill was necessary.
Because BPU’s sole asset was the 33.3% limited partner interest in Corpus Christi LNG, which was consolidated in our financial statements, we do not believe that pro forma financial statements would provide any additional benefit to an investor in our common stock. As a result, we have not prepared pro forma financial statements related to the transaction.
NOTE 10-DERIVATIVE INSTRUMENTS
Interest Rate Derivative Instruments
In connection with the closing of the Sabine Pass Credit Facility in February 2005, Sabine Pass LNG entered into swap agreements, or the Sabine Swaps, with HSBC and Société Générale. Under the terms of the Sabine Swaps, Sabine Pass LNG will be able to hedge against rising interest rates, to a certain extent, with respect to its drawings under the Sabine Pass Credit Facility, up to a maximum amount of $700,000,000. The Sabine Swaps have 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 $700,000,000 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 will be March 25, 2012.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
In connection with the closing of the Term Loan on August 31, 2005, Cheniere LNG Holdings entered into interest rate swap agreements with Credit Suisse, or the Term Loan Swaps, to hedge against rising interest rates. Under the terms of the Term Loan Swaps, Cheniere LNG Holdings hedged an initial notional amount of $600,000,000. The notional amount declines in accordance with anticipated principal payments under the Term Loan. The Term Loan Swaps have 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 will be September 30, 2010.
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 have determined that the Sabine Swaps and the Term Loan Swaps, or collectively, the Swaps, qualify as cash flow hedges within the meaning of SFAS No. 133 and have designated them as such. At their inception, we determined the hedging relationship of the Swaps and the underlying debt to be highly effective. We will continue to assess the hedge effectiveness of the Swaps on a quarterly basis in accordance with the provisions of SFAS No. 133.
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 other comprehensive income, or OCI, and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. In our case, the impact on earnings is reflected in interest expense. The ineffective portion of the gain or loss on the derivative instrument, if any, must be recognized currently in earnings. For the year ended December 31, 2005, we have recognized net derivative gains of $837,000 into earnings. If the forecasted transaction is no longer probable of occurring, the associated gain or loss recorded in OCI is recognized currently in earnings.
Summary of Derivative Values
The following table reflects the amounts that are recorded as assets and liabilities at December 31, 2005 for our derivative instruments (in thousands):
(1) Included in Accounts Receivable on the Consolidated Balance Sheet.
(2) Included in Accrued Liabilities on the Consolidated Balance Sheet.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Below is a reconciliation of our net derivative assets to our accumulated other comprehensive income at December 31, 2005 (in thousands):
For the year ended December 31, 2005, we settled derivative contracts that resulted in $391,000 of net realized derivative gains. The maximum length of time over which we have hedged our exposure to the variability in future cash flows for forecasted transactions is seven years under the Swaps. As of December 31, 2005, $6,259,000 of accumulated net deferred gains on the Swaps, currently included in other comprehensive income, are expected to be reclassified to earnings during the next twelve months, assuming no change in the LIBOR forward curves at December 31, 2005. The actual amounts that will be reclassified will likely vary based on the probability that interest rates will, in fact, change. Therefore, management is unable to predict what the actual reclassification from OCI to earnings (positive or negative) will be for the next twelve months.
NOTE 11-ACCRUED LIABILITIES
Accrued liabilities consist of the following (in thousands):
NOTE 12-DEFERRED REVENUE
In December 2003, we entered into a shareholders agreement whereby we became a minority owner of J & S Cheniere S.A., a Switzerland joint-stock company, or J & S Cheniere. The majority owner is J & S Energy Holding B.V., or J & S Holding, a Netherlands corporation affiliated with J & S Trading Company, Ltd., an international petroleum trading and marketing company. J & S Cheniere was formed for the purpose of buying, selling, transporting and trading LNG. Pursuant to the shareholders agreement, we identify and assist with LNG-related business opportunities that we determine are appropriate for J & S Cheniere. We are not required to offer any particular business opportunities or funding to J & S Cheniere. We have no board of director
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
representation nor do we participate in the day-to-day management of J & S Cheniere. All financing of the business opportunities will be provided by J & S Holding should it determine that a business opportunity is appropriate for J & S Cheniere. However, J & S Holding is not required to fund any particular business opportunity. We account for this investment using the cost method of accounting. At December 31, 2005, Cheniere’s investment basis was $16,000.
Also in December 2003, we entered into an option agreement with J & S Cheniere under which J & S Cheniere has an option to enter into a TUA reserving up to 200 MMcf/d of capacity at each of our Sabine Pass and Corpus Christi LNG facilities. We were paid $1,000,000 in January 2004 following execution of the option agreement by J & S Cheniere in January 2004. The terms of the TUA contemplated by the J & S Cheniere option agreement have not been negotiated or finalized. We anticipate that definitive arrangements with J & S Cheniere may involve different terms and transaction structures than were contemplated when the option agreement was entered into in December 2003. Although non-refundable, we have recorded the option fee as deferred revenue.
In November 2004, Total LNG USA, Inc., or Total, paid Sabine Pass LNG a nonrefundable advance capacity reservation fee of $10,000,000 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 $10,000,000 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 record the advance capacity reservation payments that we receive, although non-refundable, as deferred revenue to be amortized to income over the corresponding 10-year period.
Also in November 2004, we entered into a TUA to provide Chevron USA, Inc., or Chevron USA, with approximately 700 MMcf/d of LNG regasification capacity at our Sabine Pass LNG receiving terminal. In December 2005, Chevron USA exercised its option to increase its reserved capacity by approximately 300 MMcf/d to approximately 1.0 Bcf/d and paid Sabine Pass LNG an additional $3,000,000 advance capacity reservation fee. As of December 31, 2005, Chevron USA has made advance capacity reservation fee payments to Sabine Pass LNG totaling $20,000,000, with $12,000,000 paid in 2004 and $8,000,000 paid in 2005. These capacity reservation fee payments will be amortized over a 10-year period as a reduction of Chevron USA’s regasification capacity fee under the TUA. As a result, we record the advance capacity reservation payments that we receive, although non-refundable, as deferred revenue to be amortized to income over the corresponding 10-year period.
As of December 31, 2005 and 2004, we had recorded $41,000,000 and $23,000,000, respectively, as deferred revenue related to option and advance capacity reservation fee payments.
NOTE 13-MINORITY INTEREST IN LIMITED PARTNERSHIP
In May 2003, we formed a limited partnership, Corpus Christi LNG, L.P., or Corpus Christi LNG, to develop an LNG receiving terminal near Corpus Christi, Texas. Under the terms of the limited partnership agreement, we contributed our technical expertise and know-how, and all of the work in progress related to the Corpus Christi project, in exchange for a 66.7% limited partner interest in Corpus Christi LNG.
Substantially all Corpus Christi LNG expenditures incurred through March 31, 2004 were the obligation of the minority owner, since the minority owner was required to fund 100% of the first $4,500,000 of partnership expenditures. Because partnership expenditures had reached $4,500,000 as of March 31, 2004, the minority owner began sharing all subsequent expenditures based on its 33.3% limited partner interest.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
In February 2005, we acquired the minority interest of Corpus Christi LNG through the acquisition of BPU. As a result of this transaction, we now own 100% of the limited partner interest of Corpus Christi LNG and are required to fund 100% of expenditures incurred after such date. We also manage the project as the general partner through one of our wholly-owned subsidiaries.
For the years ended December 31, 2005, 2004 and 2003, our consolidated statement of operations includes $97,000, $2,862,000 and $3,015,000, respectively, related to the minority interest of Corpus Christi LNG.
NOTE 14-LONG-TERM DEBT
As of December 31, 2005 and 2004, our long-term debt is comprised of the following (in thousands):
Below is a schedule of future principal payments that we are obligated to make based on our outstanding long-term debt at December 31, 2005 (in thousands):
Sabine Pass Credit Facility
In February 2005, Sabine Pass LNG entered into the $822,000,000 Sabine Pass Credit Facility with an initial syndicate of 47 financial institutions. Société Générale serves as the administrative agent and HSBC serves as collateral agent. The Sabine Pass Credit Facility will be used to fund a substantial majority of the costs of constructing and placing into operation Phase 1 of our Sabine Pass LNG receiving terminal. Unless Sabine Pass LNG decides to terminate availability earlier, the Sabine Pass Credit Facility will be available until no later than April 1, 2009, after which time any unutilized portion of the Sabine Pass Credit Facility will be permanently canceled. Before Sabine Pass LNG could make an initial borrowing under the Sabine Pass Credit Facility, it was required to provide evidence that it had received equity contributions in an amount sufficient to fund $233,715,000 of the project costs. As of December 31, 2005, the $233,715,000 in equity contributions had been funded. At December 31, 2005, there were no borrowings outstanding; however, as of February 28, 2006, $58,500,000 had been drawn under the Sabine Pass Credit Facility.
Borrowings under the Sabine Pass Credit Facility bear interest at a variable rate equal to LIBOR plus the applicable margin. The applicable margin varies from 1.25% to 1.625% during the term of the Sabine Pass Credit Facility. The Sabine Pass Credit Facility provides for a commitment fee of 0.50% per annum on the daily
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
committed, undrawn portion of the facility. Annual administrative fees must also be paid to the administrative and collateral agents. The principal of loans made under the Sabine Pass Credit Facility must be repaid in semi-annual installments commencing six months after the later of (i) the date that substantial completion of the project occurs under the EPC agreement and (ii) the commercial start date under the Total TUA. Sabine Pass LNG may specify an earlier date to commence repayment upon satisfaction of certain conditions. In any event, payments under the Sabine Pass Credit Facility must commence no later than October 1, 2009, and all obligations under the Sabine Pass Credit Facility mature and must be fully repaid by February 25, 2015.
The Sabine Pass Credit Facility contains customary conditions precedent to the initial borrowing and any subsequent borrowings, as well as customary affirmative and negative covenants. We were in compliance, in all material respects, with these covenants at December 31, 2005. Sabine Pass LNG has obtained, and may in the future seek, consents, waivers and amendments to the Sabine Pass Credit Facility documents. The obligations of Sabine Pass LNG under the Sabine Pass Credit Facility are secured by all of Sabine Pass LNG’s personal property, including the Total and Chevron USA TUAs and the partnership interests in Sabine Pass LNG.
In connection with the closing of the Sabine Pass Credit Facility, Sabine Pass LNG entered into the Sabine Swaps with HSBC and Société Générale. Under the terms of the Sabine Swaps, Sabine Pass LNG will be able to hedge against rising interest rates, to a certain extent, with respect to its drawings under the Sabine Pass Credit Facility, up to a maximum amount of $700,000,000. The Sabine Swaps have 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 $700,000,000 at 4.49% from July 25, 2005 to March 25, 2009, and at 4.98% from March 26, 2009 through March 25, 2012. The final termination date of the Sabine Swaps will be March 25, 2012.
During the construction period, all interest costs, including amortization of related debt issuance costs and commitment fees, will be capitalized as part of the total cost of Phase 1 of our Sabine Pass LNG receiving terminal. As of December 31, 2005, $5,323,000 in commitment fees and amortization of debt issuance costs have been capitalized and included in LNG terminal construction-in-progress.
Convertible Senior Unsecured Notes
In July 2005, we consummated a private offering of $325,000,000 aggregate principal amount of Convertible Senior Unsecured Notes due August 1, 2012 to qualified institutional buyers pursuant to Rule 144A under the Securities Act. The notes bear interest at a rate of 2.25% per year. The notes are convertible into our common stock pursuant to the terms of the indenture governing the notes 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. 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 rate plus 50 basis points. The indenture governing the notes contains customary reporting requirements.
Concurrent with the issuance of the Convertible Senior Unsecured Notes, we also entered into hedge transactions in the form of an issuer call spread (consisting of a purchase and a sale of call options on our common stock) with an affiliate of the initial purchaser of the notes, having a term of two years, and a net cost to us of $75,703,000. These hedge transactions are expected to offset potential dilution from conversion of the notes up to a market price of $70.00 per share. The net cost of the hedge transactions is recorded as a reduction to Additional Paid-in-Capital in accordance with the guidance of the Emerging Issues Task Force, or EITF, Issue
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
00-19, Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company’s Own Stock. Net proceeds from the offering were $239,786,000, after deducting the cost of the hedge transactions, the underwriting discount and related fees. As of December 31, 2005, no holders had elected to convert their notes. Total interest expense recognized for the year ended December 31, 2005 was $3,741,000 before interest capitalization of $170,000.
Term Loan
In August 2005, Cheniere LNG Holdings entered into the $600,000,000 Term Loan with Credit Suisse. The Term Loan interest rate equals LIBOR plus a 2.75% margin and terminates on August 30, 2012. In connection with the closing, Cheniere LNG Holdings entered into the Term Loan Swaps with Credit Suisse to hedge the LIBOR interest rate component of the Term Loan. The blended rate of the Term Loan Swaps on the Term Loan results in an annual fixed interest rate of 7.25% (including the 2.75% margin) for the first five years (See Note 10-“Derivative Instruments”). On December 30, 2005, Cheniere LNG Holdings made the first required quarterly principal payment of $1,500,000. Quarterly principal payments of $1,500,000 are required through June 30, 2012, and a final principal payment of $559,500,000 is required on August 30, 2012. As discussed in Note 3-“Restricted Cash and Cash Equivalents”, a portion of the loan proceeds is controlled by Credit Suisse and is restricted to its use.
At December 31, 2005, principal repayments on the Term Loan of $6,000,000 are due within the next 12 months and are classified on the balance sheet as a current liability on the Term Loan. Interest expense for the year ended December 31, 2005 was $14,405,000 before interest capitalization of $603,000. The Term Loan contains customary affirmative and negative covenants. We were in compliance, in all material respects, with these covenants at December 31, 2005. The obligations of Cheniere LNG Holdings are secured by its 100% equity interest in Sabine Pass LNG and its 30% limited partner equity interest in Freeport LNG.
Note Payable
In January 2004, we repaid the $1,000,000 outstanding balance under a line of credit with a commercial bank. The line of credit was terminated in June 2004.
NOTE 15-FINANCIAL INSTRUMENTS
The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the consolidated balance sheet for cash and cash equivalents, restricted cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to their short-term nature. We use available marketing data and valuation methodologies to estimate the fair value of debt. This disclosure is presented in accordance with SFAS No. 107, Disclosures about Fair Value of Financial Instruments and does not impact our financial position, results of operations or cash flows.
Long-Term Debt (in thousands):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
(1) The Term Loan bears interest based on a floating rate; therefore, the estimated fair value is deemed to equal the carrying amount of these notes.
(2) The fair value of our Convertible Senior Unsecured Notes is based on a closing trading price as of December 30, 2005.
(3) The Sabine Pass Credit Facility will bear interest based on a floating rate. No debt was outstanding under this facility at December 31, 2005.
NOTE 16-INCOME TAXES
From our inception, we have reported net operating losses for both financial reporting purposes and for federal and state income tax reporting purposes. Accordingly, we are not presently a taxpayer and have not recorded a net liability for federal or state income taxes in any of the years included in the accompanying financial statements. Our consolidated statement of operations for the years ended December 31, 2005, 2004 and 2003 includes deferred income tax benefits of $2,045,000, $-0- and $-0-, respectively. The deferred income tax benefit recorded for the year ended December 31, 2005 has been provided for in accordance with the guidance in paragraph 140 of SFAS No. 109 and EITF Abstracts, Topic D-32 which, in certain circumstances, requires items reported in OCI to be considered in the determination of the amount of tax benefit when a net operating loss occurs. In our situation, the specific circumstance relates to OCI of $5,843,000 recorded as of December 31, 2005 related to our interest rate swaps (See Note 10-“Derivative Instruments” and Note 19-“Other Comprehensive Loss” for additional discussions). The deferred tax benefit included in our 2005 consolidated statement of operations represents the portion of the change in our tax asset valuation account that is allocable to the deferred income tax on items reported in other comprehensive income in our 2005 consolidated statement of stockholders’ equity.
Income tax expense (benefit) included in our reported net loss consists of the following (in thousands):
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, 2005 and 2004 are as follows (in thousands):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The change in the deferred tax asset valuation allowance was $11,277,000 and $17,475,000 during the years ended December 31, 2005 and 2004, respectively.
At December 31, 2005, we had net operating loss, or NOL, carryforwards for federal income tax reporting purposes of approximately $55,172,000. 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 NOL carryforwards and other deferred tax assets.
NOL carryforwards expire starting in 2012 extending through 2025. Certain of our NOLs which were previously subject to annual utilization limitations under the Internal Revenue Code Section 382 change of ownership regulations are now available for utilization due to annual increases in the allowed NOL utilization amounts provided for in Section 382. The NOL carryforward amounts presented in the table above include approximately $11,664,000 and $8,323,000 for the years ended December 31, 2005 and 2004, respectively, of excess tax benefits related to the exercise of non-qualified employee stock options and vested stock awards. The full amount of the related tax benefit is included in our deferred tax asset valuation allowance.
The reconciliation of the federal statutory income tax rate to our effective income tax rate follows:
(1) As of December 31, 2005, we have elected to account for stock-based compensation in accordance with APB Opinion No. 25 (see Note 2-“Summary of Significant Accounting Policies-Stock-Based Compensation”). For federal income tax reporting purposes, we are generally allowed to claim federal income tax deductions based on the fair market value of the underlying securities on the vest date for vested stock awards and on the date of exercise for stock options. Because the stock-based compensation expense that is required to be included in our reported annual operating losses is significantly less than the amounts
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
that have been included in our employees’ taxable incomes, the associated excess tax benefits reduce our reported effective tax rates. As discussed above, to date, approximately $11,664,000 of deferred excess tax benefits related to the exercise of non-qualified employee stock options and vested stock awards are included in our NOL carryforward amount.
(2) As discussed above, 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 federal and state deferred tax benefits related to our NOL carryforwards and other deferred tax assets.
(3) SFAS No. 109 requires us to measure our deferred income tax assets and liabilities separately for each tax jurisdiction that imposes an income tax on our operations (principally federal and state income taxes). In prior reporting periods, our reported effective tax rate included an additional 2% for certain deferred state income tax benefits related to our Texas and Louisiana exploration and development operations. We are not expecting to realize such state income tax benefits; therefore, our 2005 reported effective tax rate includes an adjustment to eliminate the related deferred state income tax benefits.
NOTE 17-WARRANTS
As of December 31, 2005, there were no outstanding warrants for the purchase of our common stock. Warrants we issued did not confer upon the holders thereof any voting or other rights of a stockholder of Cheniere. Warrants were granted in connection with certain of our debt or equity financings and as compensation for services. In instances where warrants were granted in connection with financings, such warrants were valued based on the estimated fair market value of the stock at the date of issuance. Where warrants were issued for services, fair value was calculated using the Black-Scholes pricing model. Information related to our warrants is summarized in the following table:
In September 2005, we issued 96,900 shares of common stock in exchange for the surrender of warrants to purchase 100,000 shares of common stock in a cashless transaction based on the then-current market price of $40.33. The warrants were exercisable at $1.25 per share.
In separate cashless transactions, in October 2004, we issued 57,724 and 57,366 shares of common stock in exchange for the surrender of warrants to purchase 62,500 and 62,500 shares of common stock based on the then-current price of $11.45 and $10.65 per share, respectively. The warrants were exercisable at $0.875 per share.
In August 2004, we issued 112,922 shares of common stock in exchange for the surrender of warrants to purchase 125,000 shares in a cashless transaction based on the then-current market price of $9.055 per share. The warrants were exercisable at $0.875 per share.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
In August 2003, we issued 756,616 shares of common stock in exchange for the surrender of warrants to purchase 1,400,000 shares in a cashless transaction based on the then-current market price of $2.72 per share. The warrants were exercisable at $1.25 per share.
In April 2003, we issued warrants to purchase 500,000 shares of common stock at $1.25 per share to our Chief Executive Officer as a signing bonus. At the time of issue, the current market price was $0.90 per share. The warrants vested one year from the date of issue and were exercised in September 2004.
In February 2003, in connection with the sale of a 60% interest in our Freeport LNG project, we issued warrants valued at $540,000 to purchase 1,400,000 shares of our common stock. We also issued warrants to purchase 482,500 shares of common stock to a former employee of Cheniere and the current President and Chief Operating Officer of Freeport LNG, in replacement of his options to purchase 482,500 shares of common stock. The number and exercise prices of the warrants were the same as the options replaced and ranged from $0.53 to $6.00 per share. Warrants to purchase 450,000 shares of common stock and valued at $174,000 were issued to LNG consultants for services previously performed. In connection with the sale of a 10% interest in the limited partnership, we issued warrants valued at $242,000 to purchase 600,000 shares of common stock to the purchaser.
NOTE 18-EMPLOYEE BENEFITS
Stock-Based Compensation
In 1997, we established the Cheniere Energy, Inc. 1997 Stock Option Plan, as amended, or the Option Plan, which allowed for the issuance of options to purchase up to 5,000,000 shares of our common stock. Options on 5,000,000 shares of our common stock had been granted and were outstanding or had been exercised as of December 31, 2005. The term of options granted under the Option Plan is generally five years. Vesting varies, but generally occurs over three or four years, in increments of 33% or 25%, respectively, on each anniversary of the grant date. All options granted under the Option Plan have exercise prices equal to or greater than fair market value at the date of grant.
In 2004, our stockholders approved the Cheniere Energy, Inc. 2003 Stock Incentive Plan, as amended, or the 2003 Stock Incentive Plan, which allowed for the issuance of non-qualified or incentive stock options, purchased stock, stock (bonus stock), non-vested (restricted) stock, stock appreciation rights, phantom stock and other stock-based performance awards. It initially authorized the issuance of options to purchase common stock or awards of common stock up to 2,000,000 shares. On February 8, 2005, the shareholders approved an amendment to the 2003 Stock Incentive Plan increasing the number of shares of common stock authorized for issuance under the plan from 2,000,000 to 8,000,000. Through December 31, 2005, a total of 5,335,771 shares have been issued or reserved for issuance under the 2003 Stock Incentive Plan.
In 2004, stock grants of 322,000 shares, non-vested stock grants of 680,352 shares, and non-qualified stock option grants of 735,000 shares (net of forfeitures) were made to employees and directors from the 2003 Stock Incentive Plan. In February 2004, we issued stock and non-vested stock under the 2003 Stock Incentive Plan related to our performance in 2003. This included $2,415,000 of non-cash compensation expense related to the issuance of 322,000 shares, which shares were fully vested on the date of grant; and $3,330,000 of deferred compensation as a reduction to stockholders’ equity, related to the issuance of 444,000 shares of non-vested stock, which vests on each of the first and second anniversaries of the grant date. In November 2004, we recorded $4,946,000 of deferred compensation as a reduction to stockholders’ equity related to 236,352 shares of non-vested stock that were issued to employees and directors related to our performance in 2004. One-third of the shares vest on each of the first, second and third anniversaries of the grant date. The non-qualified stock option grants of 735,000 shares were made to new employees throughout the course of 2004.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
In 2005, non-vested stock and non-qualified stock option grants of 175,151 and 3,423,296 shares (net of forfeitures), respectively, were made to employees and directors from the 2003 Stock Incentive Plan. In March 2005, non-qualified stock option grants to purchase 2,200,000 shares of common stock, or Retention Grants, were made to certain executive officers and key employees to provide an incentive for them to remain employed while the company executes critical aspects of its business plan. The Retention Grants have exercise prices at or significantly above the market price on the date of issuance and vest in one-third increments in March 2009, 2010 and 2011. In December 2005, we recorded $6,166,000 of deferred compensation as a reduction to stockholders’ equity for the issuance of 160,151 shares of non-vested stock to employees and directors related to our performance in 2005. One-third of the shares vest on each of the first, second and third anniversaries of the grant date. Also in 2005, we recorded $498,000 of deferred compensation as a reduction of stockholders’ equity in connection 15,000 shares of non-vested stock issued to employees. One-fourth of the shares vest on each of the first, second, third and fourth anniversaries of the effective dates. Non-qualified stock options for the purchase of 1,223,296 shares of common stock (net of forfeitures) were granted to new employees throughout 2005 and have exercise prices equal to fair market value at the date of grant. One-fourth of the option shares vest on each of the first, second, third and fourth anniversaries of the grant date.
Deferred compensation related to non-vested stock grants is amortized on a straight-line basis over the vesting period. During 2004, we recorded $4,148,000 (before capitalization of $529,000 as oil and gas property costs) in non-cash compensation expense, of which $2,415,000 related to stock awards and $1,733,000 related to amortization of deferred compensation associated with non-vested stock awards. During 2005, we recorded $3,522,000 (before capitalization of $145,000 as oil and gas property costs) in total non-cash compensation expense related to amortization of deferred compensation associated with non-vested stock awards. At December 31, 2005, the balance of non-cash deferred compensation remaining to be amortized was $9,684,000.
A summary of the status of our stock options is presented below:
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The following table summarizes information about fixed options outstanding at December 31, 2005:
401(k) Plan
In 2005, we established a defined contribution pension plan, or the 401(k) Plan. The 401(k) Plan allows eligible employees to contribute up to 100% of their compensation up to the Internal Revenues Service maximum. We match each employee’s salary deferrals (contributions) up to six percent of compensation and may make additional contributions at our discretion. Our contributions to the 401(k) Plan were $517,000 for the year ended December 31, 2005. No discretionary contributions were made by us to the 401(k) Plan in 2005.
NOTE 19-OTHER COMPREHENSIVE LOSS
The following table is a reconciliation of our Net Loss to our Comprehensive Loss for the periods shown (in thousands):
NOTE 20-RELATED PARTY TRANSACTIONS
From time to time, officers and employees may charter aircraft for company business travel. We entered into a letter agreement, or charter letter, with an unrelated third-party entity, Western Airways, Inc., or Western, that specifies the terms under which it would provide for charter of a Challenger 600 aircraft. One of the Challenger 600 aircraft which may be provided by Western for such services is owned by Bramblebush, LLC, or the LLC. The LLC is owned and/or controlled by our Chairman and Chief Executive Officer, Charif Souki. Our Code of Business Conduct and Ethics prohibits potential conflicts of interest. Upon the recommendation of our Audit Committee, which determined that the terms of the charter letter are fair and in our best interest, our Board
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
of Directors unanimously approved the terms of the charter letter in May 2005 and granted an exception under our Code of Business Conduct and Ethics in order to permit us to charter the Challenger 600 aircraft. For the year ended December 31, 2005, we incurred $798,000 related to the charter of the Challenger 600 aircraft owned by the LLC.
In conjunction with our private placement of equity in January 2004, placement fees were paid to T. R. Winston & Company, Inc., a company in which the son of Charif Souki, Cheniere’s Chairman and Chief Executive Officer, is employed. Placement fees to T. R. Winston for such placement totaled $965,000.
In December 2003, we entered into a shareholders agreement whereby we acquired a minority interest in J & S Cheniere. One of the directors of J & S Cheniere is the brother of Charif Souki. We also entered into an option agreement with J & S Cheniere providing for a $1,000,000 payment to us from J & S Cheniere for the option to acquire regasification capacity at our Sabine Pass and Corpus Christi LNG receiving terminals.
We have made office space available for use by Keith F. Carney, a non-management director. The pro rata amount of office lease expense related to that space was $3,000, $3,000 and $4,000 in 2005, 2004 and 2003, respectively.
NOTE 21-COMMITMENTS AND CONTINGENCIES
Lease Commitments
Future Annual Minimum Lease Payments
Future annual minimum lease payments are as follows (in thousands):
Office Leases
In October 2003, we entered into a lease agreement for new office space with a term which runs from December 2003 through April 2014. Beginning in April 2004, our monthly lease rental is $21,000 and escalates to $24,000 beginning in February 2009 through the remaining term of the lease. We have an option to renew the lease for an additional five years at the then-current market rate. In May 2004, we amended our office lease agreement to increase our rentable square footage, or the Expansion Space. The lease term for the Expansion Space runs from September 2004 through August 2009. Our monthly lease rental for the Expansion Space is $14,000 beginning in June 2005. We have the option, subject and subordinate to another tenants’ renewal option, to renew the lease for an additional five years at a rate specified in this amendment. In March 2005, we amended our office lease to increase our rentable square footage to include an additional floor on the premises. The lease term for the additional floor runs from May 2005 through January 2014. We have an option to renew the lease for an additional five years at the then-current market rate as part of the renewal of our original lease space. Under
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
the amended lease, there are no monthly lease payments for the additional floor from May 2005 through April 2007, after which time the lease payments range from approximately $30,000 to $39,000 per month through January 2014. We have prepaid $201,000 in rent related to 2013 and have included such amount in Other Assets on the consolidated balance sheet as of December 31, 2005. We are also responsible for our proportionate share of the building operating expenses. In connection with the lease, we have issued a letter of credit in favor of the landlord in the amount of $674,000. The letter of credit amount decreases by approximately $225,000 each October for the next three years. In addition, the lease creates a lien on all property that we place on the premises as a security interest for payment of amounts due under the terms of the lease.
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 our Sabine Pass LNG receiving terminal site. The leases have an initial term of 30 years, with options to renew for six 10-year extensions. 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 $1,501,000. For 2005, these payments have been capitalized as part of the construction cost of the Sabine Pass LNG receiving terminal; however, beginning in 2006, these lease payments will be expensed as required by FSP 13-1.
Our total rental expense for the years ended December 31, 2005, 2004 and 2003 was $727,000, $445,000 and $128,000, respectively.
LNG Commitments
Obligations under LNG TUAs
Sabine Pass LNG has entered into TUAs with Total and Chevron USA to provide berthing for LNG tankers and for the unloading, storage and regasification of LNG at our Sabine Pass LNG receiving terminal.
LNG Option Agreements
We entered into an agreement with J & S Cheniere under which J & S Cheniere has an option to enter into a TUA reserving up to 200 MMcf/d of capacity at each of our Sabine Pass and Corpus Christi LNG facilities. Following execution of the option agreement, $1,000,000 was paid by J & S Cheniere to us in January 2004. The terms of the TUA contemplated by the J & S Cheniere option agreement have not been negotiated or finalized. We anticipate that definitive arrangements with J & S Cheniere may involve different terms and transaction structures than were contemplated when the option agreement was entered into in December 2003. Although non-refundable, we have recorded the option fee as deferred revenue.
In January 2004, Corpus Christi LNG, L.P. entered into an option agreement with BPU to provide 100 MMcf/d of regasification capacity at our Corpus Christi LNG receiving terminal. The option agreement was subsequently assigned by BPU to its sole stockholder, BPU Associates, LLC.
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
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
partners. We received capital calls, and made capital contributions, in the amount of approximately $2,102,000 in 2005. In December 2005, Freeport LNG announced that it had closed a $383,000,000 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. As a result of such financing being obtained, we do not anticipate that any capital calls will be made upon the limited partners of Freeport LNG in the foreseeable future. Additional 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.
In connection with the acquisition of the option to lease the Freeport LNG receiving terminal site in June 2001, we issued 1,000,000 shares of common stock valued at $1,150,000, or $1.15 per share, the closing price of our common stock on the date of the transaction, to the seller of the lease option. We also committed to issue an additional 1,500,000 shares of our common stock to the seller of the lease option in April 2003, for which we received no additional consideration. These shares were issued in April 2003 at a value of $1,312,500, or $0.875 per share, the closing price of our common stock on the date of issuance. The seller of the lease option also obtained the right to receive a royalty payment on the gross quantities of gas processed at LNG terminals that we own. The royalty is generally calculated based on $0.03 per Mcf of gas processed, subject to a minimum royalty of $2,000,000 per year and a maximum royalty of $10,950,000 per year after production begins. In 2002, a long- term lease was secured by Freeport LNG, and at the closing of the sale of our interests in the site and project, Freeport LNG assumed the obligation to pay the royalty with respect to gas processed and produced at the Freeport LNG facility.
EPC Agreement
In December 2004, we entered into a lump-sum turnkey EPC agreement with Bechtel pursuant to which Bechtel is providing services for the engineering, procurement and construction of Phase 1 of our Sabine Pass LNG receiving terminal. In December 2004, a limited notice to proceed, or LNTP, was issued and accepted by Bechtel, at which time Bechtel was required to promptly commence performance of certain off-site engineering and preparatory work under the EPC agreement. In early April 2005, a final NTP was issued, and Bechtel commenced all other aspects of work under the EPC agreement.
Sabine Pass LNG agreed to pay Bechtel a contract price of $646,936,000 plus certain reimbursable costs. This contract price is subject to adjustment for changes in certain commodity prices, contingencies, change orders and other items. Payments under the EPC agreement will be made in accordance with the payment schedule set forth in the EPC agreement. The contract price and payment schedule, including milestones, may be amended only by change order. Bechtel will be liable to Sabine Pass LNG for certain delays in achieving substantial completion, minimum acceptance criteria and performance guarantees. Bechtel will be entitled to a scheduled bonus of $12,000,000, or a lesser amount in certain cases, if on or before April 3, 2008, Bechtel completes construction sufficient to achieve, among other requirements specified in the EPC agreement, a sendout rate of at least 2.0 Bcf/d for a minimum sustained test period of 24 hours. Bechtel will be entitled to receive an additional bonus of up to $67,000 per day (up to a maximum of $6,000,000) for each day that commercial operation is achieved prior to April 1, 2008. As of February 28, 2006, change orders for $64,845,000 had been approved, increasing the total contract price to $711,781,000. We anticipate additional change orders
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
intended to mitigate ongoing effects of the 2005 hurricanes that would increase the contract price by an amount not expected to exceed $50,000,000. We expect to submit any such change orders to our lenders by May 3, 2006 for approval under the Sabine Pass Credit Facility.
In July 2005, we executed a letter of intent with a potential EPC contractor to negotiate an EPC contract for construction of our Corpus Christi LNG terminal. Subject to certain terms and conditions, in the event that we did not execute an EPC contract with this contractor on or before January 31, 2006, we were obligated to pay the contractor a fee of $1,000,000. On October 10, 2005, we entered into a Memorandum of Understanding, or MOU, with the same potential EPC contractor to negotiate the terms of an EPC contract for each of the Corpus Christi and Creole Trail LNG receiving terminals. Under the terms of the MOU, the $1,000,000 fee was cancelled and replaced by a $500,000 termination fee, payable, with certain exceptions, if we elect to terminate the MOU or if we fail to agree on the terms of an EPC contract for at least one of the terminals by April 30, 2007.
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 are, and 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, 2005, 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.
As previously disclosed, we received a letter dated December 17, 2004 advising us of a nonpublic, informal inquiry being conducted by the SEC. On August 9, 2005, the SEC informed us that it had issued a formal order and commenced a nonpublic factual investigation of actions and communications by Cheniere, its current or former directors, officers and employees and other persons in connection with our agreements and negotiations with Chevron USA, the Company’s December 2004 public offering of common stock, and trading in our securities. The scope, focus and subject matter of the SEC investigation may change from time to time, and we may be unaware of matters under consideration by the SEC. We have cooperated fully with the SEC informal inquiry and intend to continue cooperating fully with the SEC in its investigation.
NOTE 22-GAIN ON SALE OF INVESTMENT IN UNCONSOLIDATED AFFILIATE
In October 2000, Cheniere and Warburg, Pincus Energy Partners, L.P. formed Gryphon Exploration Company, or Gryphon, to fund an oil and gas exploration program in the Gulf of Mexico. Since January 1, 2003, our investment (effective 9.3% ownership) in Gryphon has been accounted for under the cost method of accounting, and our investment basis was zero. On August 31, 2005, Gryphon was sold for $283,000,000, plus assumption of $14,000,000 of net debt in a merger with Woodside Energy (USA). The transaction generated net cash proceeds of $20,206,000 to us, and since our investment balance was zero at the closing of this transaction, we recognized a gain in our consolidated statement of operations for the year ended December 31, 2005 equal to the net cash proceeds amount.
NOTE 23-BUSINESS SEGMENT INFORMATION
Our business activities are conducted within two principal operating segments: LNG receiving terminal development, and oil and gas exploration and development. These segments operate independently.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Our LNG receiving terminal development segment is in various stages of developing three, 100% owned LNG receiving terminal projects along the U.S. Gulf Coast at the following locations: Sabine Pass LNG in western Cameron Parish, Louisiana on the Sabine Pass Channel; Corpus Christi LNG near Corpus Christi, Texas; and Creole Trail LNG at the mouth of the Calcasieu Channel in central Cameron Parish, Louisiana. In addition, we own a 30% minority interest in a fourth project, Freeport LNG, located on Quintana Island near Freeport, Texas. Our related natural gas pipeline development activities and other initiatives that complement the development of our LNG receiving terminal business are also presently included in the segment.
Our oil and gas exploration and development segment explores for oil and natural gas using a regional database of approximately 7,000 square miles of regional 3D seismic data. Exploration efforts are focused on the shallow waters of the Gulf of Mexico offshore of Louisiana and Texas and consist primarily of active interpretation of our seismic data and generation of prospects, through participation in the drilling of wells, and through farm-out arrangements and back-in interests (a reversionary interest in oil and gas leases reserved by us) whereby the capital costs of such activities are borne primarily by industry partners. This segment participates in drilling and production operations with industry partners on the prospects that we generate.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
(1) Includes corporate activities and certain intercompany eliminations.
(2) Represents equity in net loss of our investment in Freeport LNG, excluding the 2005 Suspended Loss of $3,968,000. Our investment basis is zero at December 31, 2005.
(3) Represents gain on sale of our interest in Gryphon Exploration Company. See Note 22-“Gain on Sale of Investment in Unconsolidated Affiliate”.
(4) Represents equity in net loss of our investment in Freeport LNG for 2004 totaling $1,068,000 plus the 2003 Suspended Loss of $278,000.
(5) In January 2004, we received the final $2,500,000 payment due from Freeport LNG. See Note 8-“Investment in Limited Partnership”.
(6) Represents equity in net loss of our investment in Freeport LNG, excluding the 2003 Suspended Loss of $278,000. Our investment basis was reduced to zero as of December 31, 2003.
(7) In February 2003, we sold a 60% interest in our Freeport LNG terminal project to Freeport LNG. A gain of $4,760,000 was recognized on the sale. See Note 8-“Investment in Limited Partnership”.
(8) In March 2003, we sold a 10% limited partner interest in Freeport LNG to a third party and recognized a gain of $423,000. See Note 8-“Investment in Limited Partnership”.
NOTE 24-SUPPLEMENTAL CASH FLOW INFORMATION AND DISCLOSURES OF NON-CASH TRANSACTIONS
The following table provides supplemental disclosure of cash flow information (in thousands):
In 2005, non-vested stock grants of 175,151 shares were made to employees and outside directors under the 2003 Stock Incentive Plan. We recorded $6,663,000 to common stock and additional paid-in-capital, offset by a corresponding amount of deferred compensation to stockholders’ equity. During 2005, we recorded $3,583,000 (before capitalization of $145,000 as oil and gas property costs) in total non-cash compensation expense. As of December 31, 2005, the balance of non-cash deferred compensation was $9,684,000.
In 2005, 129,842 shares of our common stock were issued in satisfaction of cashless exercises of stock options and warrants to purchase 33,868 and 100,000 shares, respectively.
In February 2005, we acquired the 33.3% minority interest in Corpus Christi LNG through the acquisition of BPU in exchange for 2,000,000 restricted shares of our common stock valued at $77,090,000.
In 2004, we recorded $97,000, the present value of the expected abandonment cost of a well in which we hold a working interest, and its related equipment, as a long-term asset retirement obligation. A corresponding amount was recorded to proved oil and gas properties. Non-cash accretion expense for 2005 and 2004 was $3,000 and $2,000, respectively, and was included in depreciation, depletion and amortization expense.
In December 2003, the minority interest owner of Corpus Christi LNG contributed two tracts of land valued at $311,000 to be used for the LNG terminal site.
In August 2003, we issued 756,616 shares of common stock in exchange for the surrender of warrants to purchase 1,400,000 shares in a cashless transaction.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
In April 2003, pursuant to a contingent contractual obligation related to our 2001 acquisition of an option to lease the Freeport LNG terminal site, we issued 1,500,000 shares of our common stock, valued at $1,312,000 on the date of issuance, to satisfy a closing requirement related to the February 2003 sale of a 60% interest in our Freeport LNG project
In February 2003, in connection with the sale of a 60% interest in the Freeport LNG site and project, we issued warrants valued at $540,000 to purchase 1,400,000 shares of common stock. As a result of the closing of the Freeport transaction, we issued warrants valued at $174,000 to purchase 450,000 shares of common stock to LNG consultants for services previously performed for us. In connection with the sale of a 10% interest in Freeport LNG, we issued warrants valued at $242,000 to purchase 600,000 shares of common stock to the purchaser, and the purchaser canceled the $750,000 note previously payable by us. These transactions are described in more detail in Note 8-“Investment in Limited Partnership”.
NOTE 25-SUBSEQUENT EVENTS
At December 31, 2005, there were no borrowings outstanding under the Sabine Pass Credit Facility; however, as of February 28, 2006, $58,500,000 had been drawn under the Sabine Pass Credit Facility.
On January 3, 2006, 78,671 shares, valued at $37.71 per share, were granted to executive officers in the form of non-vested (restricted) stock awards relating to our performance in 2005.
During January and February 2006, we issued 141,003 shares of common stock pursuant to the exercise of stock options at an average price of $7.37 generating proceeds of $1,039,000.
On February 21, 2006, Cheniere Sabine Pass Pipeline Company, our wholly-owned subsidiary, entered into an EPC pipeline contract with Willbros Engineering, Inc., or Willbros. Under the EPC pipeline contract, Willbros will provide Cheniere Sabine Pass Pipeline Company with services for the management, engineering, material procurement, construction and construction management of the Sabine Pass pipeline. Sabine Pass Pipeline Company will pay to Willbros a contract price not to exceed $67,700,000 subject to additions and deductions by any change order as provided in the EPC pipeline contract, excluding certain Louisiana sales and use taxes, which Cheniere Sabine pass Pipeline Company is obligated to reimburse. Cheniere Sabine Pass Pipeline Company entered into the EPC pipeline contract sufficiently in advance of commencement of physical construction of the pipeline in order to perform detailed engineering and procure materials.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
OIL AND GAS RESERVES AND RELATED FINANCIAL DATA
(unaudited)
Costs Incurred in Oil and Gas Producing Activities
Presented below are costs incurred in oil and gas property acquisition, exploration and development activities (in thousands):
Included in the costs incurred for the years ended December 31, 2005, 2004 and 2003 was $927,000, $1,573,000 and $1,064,000, respectively, of capitalized general and administrative expenses, capitalized interest expense and capitalized debt discount directly related to property acquisition, exploration and development.
Capitalized Costs Related to Oil and Gas Producing Activities
The following table presents total capitalized costs of proved and unproved properties and accumulated depreciation, depletion and amortization related to oil and gas producing operations (in thousands):
Costs Not Being Amortized
Presented below is a summary of oil and gas property costs not being amortized at December 31, 2005, by the year in which such costs were incurred. Such costs include capitalized interest of $169,000. The majority of the evaluation activities are expected to be completed within three years.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
OIL AND GAS RESERVES AND RELATED FINANCIAL DATA-(Continued)
(unaudited)
Results of Operations from Oil and Gas Producing Activities
The results of operations from oil and gas producing activities are as follows (in thousands):
(1) Includes $3,000 and $2,000 of asset retirement accretion expense in 2005 and 2004, respectively.
Reserve Quantities
Estimates of our proved reserves and the related standardized measure of discounted future net cash flow information are based on the reports generated by our independent petroleum engineers, Sharp Petroleum Engineering, Inc., in accordance with the rules and regulations of the SEC. The independent engineers’ estimates were based upon a review of production histories and other geologic, economic, ownership and engineering data provided by us. These estimates represent our interest in the reserves associated with our properties. All of our oil and gas reserves are located within the United States or its territorial waters.
Our estimates of proved reserves and proved developed reserves of oil and gas as of December 31, 2005, 2004 and 2003 and the changes in our proved reserves are as follows:
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and future amounts and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
OIL AND GAS RESERVES AND RELATED FINANCIAL DATA-(Continued)
(unaudited)
Estimates of proved undeveloped reserves are inherently less certain than estimates of proved developed reserves. The quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures, geologic success and future oil and gas sales prices may all differ from those assumed in these estimates. In addition, our reserves may be subject to downward or upward revision based upon production history, purchases or sales of properties, results of future development, prevailing oil and gas prices and other factors.
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows was calculated by applying year-end prices (adjusted for location and quality differentials) to estimated future production, less future expenditures (based on year-end costs) to be incurred in developing and producing our proved reserves and the estimated effect of future income taxes based on the current tax law. The resulting future net cash flows were discounted using a rate of 10% per annum.
From our inception, we have recorded annual net operating losses for both financial reporting purposes and for federal and state income tax reporting purposes. Accordingly, we are not presently a taxpayer, and therefore there is no tax effect on future net cash flow amounts.
The standardized measure of discounted future net cash flow amounts contained in the following tabulation does not purport to represent the fair market value of oil and gas properties. No value has been given to unproved properties. There are significant uncertainties inherent in estimating quantities of proved reserves and in projecting rates of production and the timing and amount of future costs. Future realization of oil and gas prices over the remaining reserve lives may vary significantly from current prices. In addition, the method of valuation utilized, based on year-end prices and costs and the use of a 10% discount rate, is not necessarily appropriate for determining fair value.
The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is as follows (in thousands):
CHENIERE ENERGY, INC. AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
OIL AND GAS RESERVES AND RELATED FINANCIAL DATA-(Continued)
(unaudited)
The following table summarizes the principal sources of change in the standardized measure of discounted future net cash flows (in thousands, except for prices):
We may receive amounts different from those incorporated into the standardized measure of discounted cash flow for a number of reasons, including changes in prices. Therefore, the present value shown above should not be construed as the current market value of the estimated oil and gas reserves attributable to our properties.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
SUMMARIZED QUARTERLY FINANCIAL DATA
(unaudited)
Quarterly Financial Data-(in thousands)
(1) Revenues less production costs and oil and gas depreciation, depletion and amortization.
(2) The third quarter of 2005 includes $20,206,000 gain on sale of our investment in Gryphon Exploration Company. See Note 22-“Gain on Sale of Investment in Unconsolidated Affiliate”.
(3) The first quarter of 2004 includes a $2,500,000 gain recognized on receipt of the final $2,500,000 payment from Freeport LNG. See Note 8-“Investment in Limited Partnership”.
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, 2005, 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 Report on Internal Control Over Financial Reporting
Our Management Report on Internal Control Over Financial Reporting is included in the Financial Statements on page 73 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 involving the election of directors, which is to be filed pursuant to Regulation 14A within 120 days after the end of Cheniere’s fiscal year ended December 31, 2005.
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 Reports to the Stockholders of Cheniere Energy, Inc.
Reports of Independent Registered Public Accounting Firm
Consolidated Balance Sheet
Consolidated Statement of Operations
Consolidated Statement of Stockholders’ Equity
Consolidated Statement of Cash Flows
Notes to Consolidated Financial Statements
Supplemental Information to Consolidated Financial Statements-Oil and Gas Reserves and Related Financial Data
Supplemental Information to Consolidated Financial Statements-Summarized Quarterly Financial Data
The financial statements of Freeport LNG Development, L.P. for the period from December 1, 2002 to December 31, 2005, for which Cheniere used the equity method of accounting, have been filed as part of this report on Form 10-K. (See Item 15(c))
(2) Financial Statement Schedules
All consolidated financial statement schedules have been omitted because they are not required, are not applicable, or the required information has been included elsewhere within this Form 10-K.
(3) Exhibits
* Incorporated by reference
 Management contract or compensatory plan or arrangement
(c) Freeport LNG Development, L.P. Financial Statements, for which Cheniere used the equity method of accounting for the period from December 1, 2002 to December 31, 2005, are filed as a part of this report beginning on page 124.
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 and
Chairman of the Board
Date: March 10, 2006
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.
INDEX TO FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners of
Freeport LNG Development, L.P., a Limited Partnership
Houston, Texas
We have audited the accompanying consolidated balance sheets of Freeport LNG Development, L.P., a Delaware limited partnership (a development stage limited partnership) and subsidiaries, as of December 31, 2005 and 2004, and the related consolidated statements of operations, changes in partners’ capital (deficit) and cash flows for the years ending December 31, 2005, 2004 and 2003, and for the period from inception (December 1, 2002) through December 31, 2005. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Freeport LNG Development, L.P. and subsidiaries, as of December 31, 2005 and 2004, and the results of their operations and their cash flows for the years ending December 31, 2005, 2004 and 2003, and for the period from inception (December 1, 2002) through December 31, 2005 in conformity with accounting principles generally accepted in the United States of America.
/S/ HEIN & ASSOCIATES LLP
Hein & Associates LLP
Dallas, Texas
February 16, 2006
FREEPORT LNG DEVELOPMENT, L.P.
(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)
CONSOLIDATED BALANCE SHEETS
See accompanying notes to these consolidated financial statements.
FREEPORT LNG DEVELOPMENT, L.P.
(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)
CONSOLIDATED STATEMENTS OF OPERATIONS
See accompanying notes to these consolidated financial statements.
FREEPORT LNG DEVELOPMENT, L.P.
(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL (DEFICIT)
See accompanying notes to these consolidated financial statements.
FREEPORT LNG DEVELOPMENT, L.P.
(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)
CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying notes to these consolidated financial statements.
FREEPORT LNG DEVELOPMENT, L.P.
(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. SIGNIFICANT ACCOUNTING POLICIES:
Business Activity-Freeport LNG Development, L.P. (the “Partnership”) is in the process of developing, building and commercializing a liquefied natural gas (LNG) receiving and regasification facility on Quintana Island, near Freeport, Texas (the “Facility”). After construction is completed, the Partnership will own and operate the Facility. During 2004, FLNG Land, Inc. (Land), a wholly owned subsidiary, was formed to facilitate Phase 1 land related transactions. During 2005, Freeport LNG Expansion, L.P. and FLNG Storage, L.P., both wholly owned subsidiaries, were formed for the purpose of exploring adding additional capacity to the Facility (Phase 2) and exploring adding an underground storage facility (Storage). Also during 2005, FLNG Land II, Inc. (Land II), a wholly owned subsidiary, was formed to facilitate Phase 2 land related transactions.
Principles of Consolidation-The consolidated financial statements include the accounts of Freeport LNG Development, L.P. and its 100% owned subsidiaries. All intercompany accounts and transactions are eliminated in the consolidation.
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 estimates and assumptions that affect certain reported amounts in the financial statements and accompanying notes. Actual results could differ from these estimates and assumptions.
Cash and Cash Equivalents-The Partnership considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents.
Cash received from advances on the note payable to ConocoPhillips (COP) can only be used for construction and regular operations and cannot be used to fund any additional expansion studies or be used to pay expenses that were incurred prior to when the Partnership obtained Federal Energy Regulatory Commission (“FERC”) approval for the construction of Phase 1 of the Facility.
Cash received from the notes payable to institutional investors is restricted and can only be used for additional Phase 1 costs, expansion studies or expansion construction, storage construction, and certain other disbursements.
Property, Plant and Equipment-Property, plant and equipment are stated at cost. Depreciation is computed using the straight-line method over the estimated useful lives of the assets for financial reporting purposes. Expenditures for major renewals and betterments that extend the useful lives are capitalized. Expenditures for normal maintenance and repairs are expensed as incurred. When assets are sold or abandoned, the cost of the assets sold or abandoned and the related accumulated depreciation will be eliminated from the accounts, and any gains or losses will be charged or credited to other income (expense) of the respective period. The estimated useful lives by classification are as follows:
Construction in Progress-Construction in progress through December 31, 2005 relates to engineering, land, acquisition, title work, and other direct costs related to Phase 1 construction of the Facility, which were
FREEPORT LNG DEVELOPMENT, L.P.
(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
incurred after the Partnership obtained FERC approval and closed on the related construction loan, and physical assets added to Phase 1 during the construction that were needed in order to allow a potential Phase 2 expansion to be built at a later time.
Revenue Recognition-Revenues will be recognized for terminal use fees as they are earned from the regasification process. Revenue from capacity reservations are generally deferred.
The Partnership also recognized revenue from a transaction in 2004 when it provided engineering and design studies to ConocoPhillips. In connection with this sale, the Partnership also agreed to reserve a specific amount of capacity for ConocoPhillips.
Concentrations of Credit Risk and Other Concentrations-Although held in nationally recognized financial institutions, substantially all of the Partnership’s cash balances are in excess of the FDIC insurance limits. As discussed in Note 4, ConocoPhillips has significant involvement with the Partnership.
Income Taxes-The Partnership files its Federal income tax return as a partnership under the Internal Revenue Code. In lieu of corporate income taxes, the partners of the Partnership are taxed on their proportionate share of the Partnership’s taxable income. Accordingly, no provision or liability has been recognized for federal income tax purposes for those periods, as taxes are the responsibility of the individual partners of the Partnership.
Income taxes are provided for the Partnership’s subsidiaries that are C-Corporations in accordance with Statement of Financial Accounting Standards No. 109 “Accounting for Income Taxes”. A deferred tax asset or liability is recorded for all temporary differences between income for financial statement purposes and income for tax purposes as well as operating loss carry forwards. Deferred tax expense (or benefit) results from the net change during the year of deferred tax assets and liabilities.
The net deferred tax assets for these subsidiaries were approximately $1,020,000 and $130,000 at December 31, 2005 and 2004, respectively before the valuation allowance. The net deferred tax asset has been reduced to zero in both periods after consideration of the valuation allowance. A valuation allowance is recorded when, in the opinion of management, it is likely that some portion of the deferred tax asset will not be realized. Deferred taxes are adjusted for the effects of changes in tax laws and rates. No income taxes were paid in 2003, 2004 or 2005.
2. DEVELOPMENT STAGE OPERATIONS:
The Partnership was formed December 1, 2002. Through June 2004, operations were devoted to preconstruction costs such as obtaining approvals from FERC, obtaining the appropriate leases and permits, completing the engineering and environmental studies necessary for further development of the Facility, and obtaining financing to construct the Facility.
In June 2004, the Partnership obtained FERC approval for the Facility subject to satisfaction of certain conditions. The conditions were satisfied and FERC issued approval to begin construction in January 2005. Construction began on January 17, 2005. The construction of Phase 1 is expected to be completed in the first quarter of 2008.
The Partnership is also pursuing research and development for possible expansion of the Facility, the construction of an underground storage facility, and other opportunities.
FREEPORT LNG DEVELOPMENT, L.P.
(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
3. LIQUIDITY AND CONTINUED OPERATIONS:
The Partnership will ultimately need to complete construction of the Facility and operate it profitably. There is significant construction which needs to be completed, and start up of Phase 1 of the Facility is expected in 2008.
Notwithstanding the foregoing, the Partnership believes it will continue as a going-concern based on favorable results related to the engineering studies, having secured all permits and government approvals required for Phase 1, the strong financial backing of its partners and future customers, its success in commercializing the expected available capacity, and its current financing obtained from ConocoPhillips and institutional investors.
4. AGREEMENT WITH CONOCOPHILLIPS:
The Partnership’s general partner (“Freeport LNG GP Inc.” or “Freeport GP”), and ConocoPhillips have executed an omnibus agreement. This agreement governs several transactions among the entities. The agreement was modified in the fourth quarter of 2005. The agreement, among other things, governs the following:
•
ConocoPhillips agreed to pay the Partnership $10,000,000 for specific engineering and design studies, which occurred in January 2004. The Partnership recorded the payment as revenue in 2004.
•
ConocoPhillips agreed to loan a substantial majority of the Facility’s anticipated construction costs, including interest during the construction phase. The debt service under this loan will be fully serviced by the ConocoPhillips Terminal Use Agreement (“TUA”). The Partnership made loan draws of approximately $202,000,000 against this construction loan and expects to make additional loan draws in excess of $400,000,000 prior to completion of construction of the Facility. Additional draws were made against the loan subsequent to December 31, 2005.
•
ConocoPhillips purchased 50% of the stock of Freeport LNG GP for $9,000,000 from the principal investor of Freeport LNG GP. After the purchase of the stock, ConocoPhillips and the principal investor of Freeport LNG GP each appointed three persons to a board which manages the construction and will manage operation of the Facility.
•
ConocoPhillips agreed to a TUA which will govern the terms under which LNG is processed and will reserve a specified capacity.
5. DEFERRED REVENUE:
The Partnership received $3,500,000 from ConocoPhillips in 2004 and $1,500,000 from MC Global Gas Corporation in 2005 to reserve specific capacities that are expected to be available if the Partnership completes a potential Phase 2 expansion of the plant. This revenue will not be recognized unless a Phase 2 expansion is completed. The Partnership is still researching the feasibility of Phase 2, and at this time, it is uncertain when, or if, Phase 2 construction or operations will begin.
6. NOTES PAYABLE:
ConocoPhillips-The Partnership has entered into an agreement with ConocoPhillips to provide financing to construct the Facility. ConocoPhillips has agreed to finance the first $460,000,000 of construction cost, including $10,000,000 in support of any channel widening efforts undertaken by the Brazos River Harbor Navigation District (the “Port”), and has agreed to provide financing up to 50% of any additional supplemental
FREEPORT LNG DEVELOPMENT, L.P.
(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
costs incurred. The Partnership has drawn approximately $202,000,000 as of December 31, 2005. The interest rate on the note is 8%. Interest totaling $9,368,000 and $420,000 at December 31, 2005 and 2004, respectively, has been capitalized and all interest has been accrued and is included in notes payable as of December 31, 2005. Repayments on this loan will not begin until the Facility is constructed and operating. The loan is collateralized by all of the Phase 1 assets of the Partnership.
Institutional Investors-In December 2005 the Partnership completed a $383,000,000 private placement of notes payable. The purchasers were institutional investors. The notes bear an interest rate of 6.5%, which is subject to up to two 50 basis point upward adjustments, based on the creditworthiness of the customers. All interest on the notes was accrued at December 31, 2005. The notes begin amortizing in 2010, with final payment due in December 2015. The use of the proceeds is restricted for the remaining 50% of any additional Phase 1 supplemental costs (as described with ConocoPhillips above) and for certain other expansion, development or operational activities. In conjunction with the note placement, the Partnership capitalized approximately $6,959,000 of note offering costs, which are being amortized over the term of the notes. Amortization expense for 2005 was not material. The loan is collateralized by the Dow Terminal Use Agreement, by the underground storage assets, if constructed, of the Partnership and by a second lien on all Phase 1 assets of the Partnership.
7. COMMITMENTS:
The Partnership has entered into lease agreements with the Port for the lease of the land on which the Facility will be constructed and areas around the Facility. The leases will terminate in 2033, with six options to renew the leases for an additional 10 years for each option. The lease agreements require $2,300,000 in payments each year. The lease payments will also increase based on increases in the Consumer Price Index (“CPI”) from year to year.
Additionally, the leases provide that the Partnership will guarantee thru-put fees of $1,250,000 per year (subject to increase for the CPI index) to be received by the Dock Facilities operated by the Port from carriers shipping LNG to the Facility. This guarantee is expected to begin in 2008.
The Partnership has entered into a lease agreement in 2005 with Pinto Energy Partners, L.P. for the lease of land on which a storage facility may be constructed. The lease will terminate in 2033, with six options to renew for an additional 10 years for each option. Base rent is $250,000 until March 1, 2010. If construction of the storage facility has not begun prior to March 1, 2010, base rent will increase to $750,000 until construction begins. Based on the projected beginning of construction and the projected completion date, base rent will increase between $400,000 and $1,400,000. If the storage facility is completed (beginning no earlier than March 1, 2010), rent will increase to $2,000,000 per year. All amounts due under the lease are subject to annual adjustments based on the CPI. The Partnership also can make a one time payment of $2,500,000 between March 1, 2010 and April 30, 2010 to terminate the lease (adjusted for CPI), if construction has not started.
The Partnership office lease has a base rent of $194,000 per year with an estimated additional rent of $130,000 which will be adjusted by the landlord each calendar year. Additional rent is to reimburse taxes and expenses incurred by the landlord which the Partnership is obligated to pay based on the terms of the lease. The term of the lease is 100 months beginning on July 1, 2005.
FREEPORT LNG DEVELOPMENT, L.P.
(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The following table presents the future minimum lease payments due under the leases and ignoring any increases related to the CPI index, the thru-put guarantee, or increases based on construction of the storage facility:
Rent expense and related costs were $2,652,000, $820,000 and $573,000 for the years ended December 31, 2005, 2004 and 2003, respectively.
Employment Agreements-The Partnership has employment agreements with six key managers of the Partnership. The agreements define target annual variable compensation levels, vesting in profits participation, and define the duration of the employment obligation. The Partnership has accrued and, subsequent to December 31, 2005, paid all annual variable compensation obligations due under these agreements. The initial employment term has expired for a portion of the six employment agreements and the related employees are now “at will” employees with no Partnership obligation other than those associated with vested profits participation, if any. Because the Facility has not begun operation, the profits participation obligation, if any, cannot be determined. A maximum remaining salary obligation of not more than $300,000 remains under the portion of the agreements for which the initial term has not expired.
Related Parties-In December 2004, the Partnership entered into a consulting agreement with an affiliate of the principal investor of Freeport LNG GP to provide for chief executive officer services. The agreement requires yearly payments of $500,000 and reimbursement for travel and other expenses. In 2005 the Partnership expensed $500,000 for the consulting services and $635,000 for reimbursement of travel and other expenses.
Capacity Reservations-One of the Partnership’s limited partners, Freeport LNG Investments LLLP, has entered into an agreement whereby it borrowed $5,000,000 from The Dow Chemical Company (“Dow”). In connection with this agreement, Freeport LNG Investments LLLP invested the proceeds of the loan as a capital contribution to the Partnership and the Partnership agreed to reserve a stipulated capacity at the Facility for Dow. The Dow Capacity Reservation and the ConocoPhillips TUA are expected to fully reserve substantially all of the Facility’s anticipated Phase 1 capacity.
Turn-key Construction Contact-The Partnership has a turn-key construction contract for Phase 1 and for certain work that will facilitate expansion of the Facility with a fixed price of $577,798,000, which includes all change orders agreed to through December 31, 2005. It is reasonably possible that additional change orders will be executed, increasing the cost of the Facility.
Phase 2-The Partnership is evaluating the possibility of expanding the vaporization capacity of the Facility and evaluating the feasibility of constructing and operating an underground natural gas storage facility near Stratton Ridge, Texas. In May 2005 the Partnership filed an application with FERC to expand the permitted
FREEPORT LNG DEVELOPMENT, L.P.
(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
capacity of the plant to a total capacity of 4.0 BCFD. Approval is pending review by FERC. In conjunction with the possible expansion, the Partnership has submitted applications for permits from other governing agencies including the Texas Commission on Environmental Quality, the U.S Army Corp of Engineers, and the U.S Coast Guard. Subsequent to December 31, 2005, the Texas Railroad Commission has approved construction of the underground storage facility. The feasibility of both the expansion of the Facility and construction of an underground storage facility are ongoing.
8. OFFICE EQUIPMENT AND LEASEHOLD IMPROVEMENTS:
Property and equipment consists of:
9. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES:
Accounts payable and accrued liabilities consist of the following:
10. SUBSEQUENT EVENT:
Subsequent to December 31, 2005, the Partnership continued to construct Phase 1 and continued to borrow funds from ConocoPhillips. Additional research and development expenditures were made subsequent to December 31, 2005 for development activities on the possible Phase 2 expansion and possible storage facility.