ITEM 1A.
RISK FACTORS
The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates or expectations contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.
The risk factors in this report are grouped into the following categories:
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Risks Relating to Our Financial Matters;
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Risks Relating to Our LNG Terminal Business;
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Risks Relating to Our LNG and Natural Gas Marketing Business;
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Risks Relating to Our LNG Businesses in General; and
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Risks Relating to Our Business in General.
Risks Relating to Our Financial Matters
Our significant debt could materially and adversely affect our business, financial condition and prospects.
As of December 31, 2014, we had $10.0 billion of total debt outstanding on a consolidated basis (before debt discounts and debt premiums). We incur, and will incur, significant interest expense relating to the assets at the Sabine Pass LNG terminal, and we anticipate needing to incur substantial additional debt and issue equity to finance the construction of the Corpus Christi Liquefaction Project and to finance the construction of Trains 5 and 6 of the Sabine Pass Liquefaction Project. Our ability to fund our capital expenditures and refinance our indebtedness will depend on our ability to access additional project financing as well as the debt and equity capital markets. Furthermore, our financing costs could increase or future borrowings or equity offerings may be unavailable to us or unsuccessful, which could cause us to be unable to pay or refinance our indebtedness or to fund our other liquidity needs.
We have not been profitable historically, and we have not had positive operating cash flow. We may not achieve profitability or generate positive operating cash flow in the future.
We had net losses of $547.9 million, $507.9 million and $332.8 million for the years ended December 31, 2014, 2013 and 2012, respectively. In addition, our net cash flow used in operating activities was $124.1 million, $52.4 million and $107.8 million for the years ended December 31, 2014, 2013 and 2012, respectively. We will continue to incur significant capital and operating expenditures while we develop and construct the Sabine Pass Liquefaction Project and the Corpus Christi Liquefaction Project. We currently expect that we will not begin to receive any significant cash flows from the Sabine Pass Liquefaction Project until late 2015, at the earliest. Any delays beyond the expected development period for Train 1 of the Sabine Pass Liquefaction Project could cause, and could increase the level of, operating losses and negative operating cash flows. Our future liquidity may also be affected by the timing of construction financing availability in relation to the incurrence of construction costs and other outflows and by the timing of receipt of cash flows under SPAs in relation to the incurrence of project and operating expenses. Moreover, 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 any significant positive operating cash flow and achieve profitability in the future is dependent on our ability to successfully and timely complete the applicable Train.
We may sell equity or equity-related securities or assets, including equity interests in Cheniere Partners. Such sales could dilute our stockholders’ proportionate indirect interests in our assets, business operations and proposed liquefaction and other projects of Cheniere Partners or other subsidiaries, and could adversely affect the market price of our common stock.
We have pursued and are pursuing a number of alternatives in order to finance the construction of Trains 5 and 6 of the Sabine Pass Liquefaction Project and the Corpus Christi Liquefaction Project, including potential issuances and sales of additional equity or equity-related securities by us, Cheniere Partners, or both. Such sales, in one or more transactions, could dilute our stockholders’ proportionate indirect interests in our assets, business operations and proposed projects of Cheniere Partners, including the Sabine Pass Liquefaction Project, or in other subsidiaries or projects, including the Corpus Christi Liquefaction Project. In addition, such sales, or the anticipation of such sales, could adversely affect the market price of our common stock.
Our stockholders may experience dilution upon the conversion of our convertible notes.
On November 26, 2014, we issued an aggregate principal amount of $1.0 billion of the 2021 Convertible Unsecured Notes to RRJ Capital II Ltd, Baytree Investments (Mauritius) Pte Ltd, and Seatown Lionfish Pte. Ltd. (the “2021 Convertible Unsecured Notes”). In January 2015, we entered into a note purchase agreement with EIG Management Company, LLC (“EIG”) to purchase $1.5 billion of convertible notes scheduled to fund once we reach a positive final investment decision on the Corpus Christi Liquefaction Project (the “EIG Convertible Notes” and together with the 2021 Convertible Unsecured Notes, collectively the “Convertible Notes”). We have the option to satisfy the Convertible Notes conversion obligations with cash, common stock or a combination thereof. The 2021 Convertible Unsecured Notes will be convertible beginning on November 28, 2015 at an initial conversion price of $93.64. The EIG Convertible Notes will be convertible (i) at our option, at any time on or after the substantial completion of Train 3 of the Corpus Christi Liquefaction Project at a conversion price equal to the lower of (x) a 10% discount to the average of the daily volume-weighted average price (“VWAP”) of our common stock, for the 90 trading-day period preceding the date on which notice of conversion is provided and (y) a 10% discount to the closing price of our common stock on the trading day prior to the date on which notice of conversion is provided or (ii) at the option of the holders of the EIG Convertible Notes, at any time on or after the six-month anniversary of the substantial completion of Train 3 of the Corpus Christi Liquefaction Project, at a conversion price equal to the average of the daily VWAP of our common stock for the 90 trading-day period preceding the date on which notice of conversion is provided. The conversion of some or all of the Convertible Notes into shares of our common stock will dilute the ownership percentages and voting power of our existing stockholders. Based on the initial conversion price, if we elect to satisfy the entire conversion obligation with common stock an aggregate of approximately 14.6 million shares of our common stock would be issued upon the conversion of all of the 2021 Convertible Notes, assuming the notes are converted at maturity and all interest on the notes is paid in kind. Because the conversion rate for the EIG Convertible Notes will depend on the price of our common stock at the time of conversion, we cannot meaningfully estimate the number of shares of our common stock, if any, that would be issued upon the conversion of such notes; however, under the note purchase agreement with EIG, a maximum of 47,108,466 shares of our common stock (subject to adjustment in the event of a stock split) may be issued in the aggregate upon the conversion of all of the EIG Convertible Notes. Any sales in the public market of the shares issuable upon conversion of the Convertible Notes could adversely affect the prevailing market prices of our common stock. In addition, the existence of the Convertible Notes may encourage short selling by market participants because the conversion of the Convertible Notes could be used to satisfy short positions, or the anticipated conversion of the Convertible Notes into shares of our common stock could depress the price of our common stock.
Our ability to generate cash is substantially dependent upon the performance by customers under long-term contracts that we have entered into, and we could be materially and adversely affected if any customer fails to perform its contractual obligations for any reason.
Our future results and liquidity are substantially dependent upon performance by Chevron and Total, each of which has entered into a TUA with Sabine Pass LNG and agreed to pay us approximately $125 million annually; upon satisfaction of the conditions precedent to payment thereunder, by six third-party customers that have entered into SPAs with Sabine Pass Liquefaction and agreed to pay an aggregate of $2.9 billion annually in fixed fees; and upon satisfaction of the conditions precedent to payment thereunder, by seven third-party customers that have entered into SPAs with Corpus Christi Liquefaction and agreed to pay an aggregate of $1.5 billion annually in fixed fees. We are dependent on each customer’s continued willingness and ability to perform its obligations under its SPA. We are also exposed to the credit risk of any guarantor of these customers’ obligations under their respective TUA or SPA in the event that we must seek recourse under a guaranty. If any customer fails to perform its obligations under its TUA or SPA, our business, contracts, financial condition, operating results, cash flow, liquidity and prospects could be materially and adversely affected, even if we were ultimately successful in seeking damages from that customer or its guarantor for a breach of the TUA or SPA.
Each of our customer contracts is subject to termination under certain circumstances.
Each of Sabine Pass LNG’s long-term TUAs contains various termination rights. For example, each customer may terminate its TUA if the Sabine Pass LNG terminal experiences a force majeure delay for longer than 18 months, fails to redeliver a specified amount of natural gas in accordance with the customer’s redelivery nominations or fails to accept and unload a specified number of the customer’s proposed LNG cargoes. Sabine Pass LNG may not be able to replace these TUAs on desirable terms, or at all, if they are terminated.
Each of the SPAs contain various termination rights allowing our customers to terminate their SPAs, including, without limitation: (i) upon the occurrence of certain events of force majeure; (ii) if we fail to make available specified scheduled cargo
quantities; (iii) delays in the commencement of commercial operations; and (iv) if the conditions precedent contained in the Total and Centrica SPAs and the SPAs with Corpus Christi Liquefaction are not met or waived by specified dates. Sabine Pass Liquefaction or Corpus Christi Liquefaction, as applicable, may not be able to replace these SPAs on desirable terms, or at all, if they are terminated.
Our subsidiaries may be restricted under the terms of their indebtedness from making distributions under certain circumstances, which may limit Cheniere Partners’ ability to pay or increase distributions to us and could materially and adversely affect us.
The agreements governing our subsidiaries’ indebtedness restrict payments that our subsidiaries can make to Cheniere Partners in certain events and limit the indebtedness that our subsidiaries can incur. For example, Sabine Pass LNG may not make distributions until, among other requirements, a deposit has been made in an interest payment account for one-sixth of the semi-annual interest payment multiplied by the number of elapsed months since the last semi-annual interest payment, a deposit has been made to a permanent debt service reserve fund for one semi-annual interest payment and a fixed charge coverage ratio test of 2:1 is satisfied. Sabine Pass LNG is not permitted to make cash distributions if its consolidated cash flow is not at least twice its fixed charges, calculated as required in the indentures governing the Sabine Pass LNG Notes (the “Sabine Pass Indentures”). In order to satisfy this fixed charge coverage ratio test, we estimate that Sabine Pass LNG’s consolidated cash flow, as defined in such indentures, must be greater than approximately $340 million. Thus, TUA payments from Sabine Pass Liquefaction and either Chevron or Total are needed to satisfy the test. If the fixed charge coverage ratio test is not satisfied, Sabine Pass LNG will not be permitted by the Sabine Pass Indentures to make distributions to Cheniere Partners, which may prevent Cheniere Partners from making distributions to us and its other unitholders, which could have a material adverse effect on our business, financial condition, operating results, liquidity and prospects.
Sabine Pass Liquefaction is likewise restricted from making distributions under agreements governing its indebtedness generally until, among other requirements, substantial completion of Trains 1 through 4 has occurred, deposits are made into debt service reserve accounts and a debt service coverage ratio of 1.25:1.00 is satisfied.
Our subsidiaries’ inability to pay distributions to Cheniere Partners or to incur additional indebtedness as a result of the foregoing restrictions in the agreements governing their indebtedness may inhibit Cheniere Partners’ ability to pay or increase distributions to us and its other unitholders.
Restrictions in agreements governing our subsidiaries’ indebtedness may prevent our subsidiaries from engaging in certain beneficial transactions.
In addition to restrictions on the ability of Sabine Pass LNG and Sabine Pass Liquefaction to make distributions or incur additional indebtedness, the agreements governing their indebtedness also contain various other covenants that may prevent them from engaging in beneficial transactions, including limitations on their ability to:
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make certain investments;
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purchase, redeem or retire equity interests;
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issue preferred stock;
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sell or transfer assets;
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incur liens;
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enter into transactions with affiliates;
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consolidate, merge, sell or lease all or substantially all of its assets; and
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enter into sale and leaseback transactions.
Our use of hedging arrangements may adversely affect our future results of operations or liquidity.
To reduce our exposure to fluctuations in the price, volume and timing risk associated with the purchase of natural gas, we use futures, swaps and option contracts traded or cleared on the Intercontinental Exchange and the New York Mercantile Exchange (“NYMEX”), or over-the-counter options and swaps with other natural gas merchants and financial institutions. Hedging arrangements would expose us to risk of financial loss in some circumstances, including when:
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expected supply is less than the amount hedged;
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the counterparty to the hedging contract defaults on its contractual obligations; or
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there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.
The use of derivatives also may require the posting of cash collateral with counterparties, which can impact working capital when commodity prices change.
The swaps regulatory provisions of the Dodd-Frank Act and the rules adopted thereunder and other regulations, including EMIR and REMIT, that may have an effect on our derivatives could have an adverse impact on our ability to hedge risks associated with our business and on our results of operations and cash flows.
The swaps regulatory provisions of the Dodd-Frank Act and the rules adopted thereunder by the CFTC and SEC may adversely affect our ability to manage certain of our risks on a cost effective basis. Such laws and regulations may also adversely affect our ability to execute our strategies with respect to hedging our exposure to variability in expected future cash flows attributable to the future sale of our LNG inventory and to price risk attributable to future purchases of natural gas to be utilized as fuel to operate our LNG terminals and to secure natural gas feedstock for our liquefaction facilities. As mandated by the Dodd-Frank Act, the CFTC has proposed rules setting limits on the positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, including Henry Hub natural gas, held by market participants, with exceptions for certain bona fide hedging transactions. If the position limits in the proposed rules or other similar position limits were imposed, our ability to execute our hedging strategies described above could be compromised.
Under the swaps regulatory provisions of the Dodd-Frank Act, and the rules adopted thereunder, we could have to clear on a designated clearing organization any swaps into which we enter that fall within a class of swaps designated by the CFTC for mandatory clearing and we could have to execute trades in such swaps on certain markets. The CFTC has designated six classes of interest rate swaps and credit default swaps for mandatory clearing, but has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing. Although we expect to qualify for the end-user exception from the mandatory clearing and trade execution requirements for our swaps entered into to hedge our commercial risks, if we failed to qualify for that exception as to any swap we enter into and had to clear that swap over a designated clearing organization, we may have to post margin with respect to such swap, our cost of entering into and maintaining such swap could increase and the flexibility we enjoy with respect to entering into uncleared OTC swaps could be diminished. In addition, our counterparties that are subject to the regulations imposing the Basel III capital requirements on them may increase the cost to us of entering into swaps with them or require us to post collateral with them in connection with such swaps in order to offset their increased capital costs or to reduce their capital costs to maintain those swaps on their balance sheets. Moreover, the application of the mandatory clearing and trade execution requirements to other market participants, such as Swap Dealers, may change the cost and availability of the swaps that we use for hedging. Although we expect to qualify for the end-user exception to any margin regulations for uncleared swaps promulgated by the CFTC and federal banking regulators, if we did not qualify as a non-financial end user as to any of our swaps, our cost of entering into and maintaining swaps would be increased.
The Dodd-Frank Act’s swaps regulatory provisions, the related rules described above and the record keeping, reporting and business conduct rules imposed by the Dodd-Frank Act on other swaps market participants, as well as the regulations imposing the Basel III capital requirements on certain swaps market participants, could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against certain risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts and to execute our hedging strategies, and increase our exposure to less creditworthy counterparties. If, as a result of the swaps regulatory regime discussed above, we were to reduce our use of swaps to hedge our risks, such as commodity price risks that we encounter in our operations, our results of operations and cash flows may become more volatile and could be otherwise adversely affected.
EMIR may result in increased costs for OTC derivative counterparties and also lead to an increase in the costs of, and demand for, the liquid collateral that EMIR requires central counterparties to accept. Although we expect to qualify as a non-financial counterparty under EMIR, our subsidiaries and affiliates operating in the EU may still be subject to increased regulatory requirements, including recordkeeping, marking to market, timely confirmations, derivatives reporting, portfolio reconciliation and dispute resolution procedures. Regulation under EMIR could significantly increase the cost of derivatives contracts, materially alter the terms of derivatives contracts and reduce the availability of derivatives to protect against risks that we encounter. These increased trading costs and collateral costs may have an adverse impact on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Our subsidiaries and affiliates operating in the EU may be subject to REMIT as wholesale energy market participants. This classification imposes increased regulatory obligations on our subsidiaries and affiliates, including a prohibition to use or disclose insider information or to engage in market manipulation in wholesale energy markets, and an obligation to report certain data. The increased regulatory obligations may increase the cost of compliance for our business and if we violate these laws and regulations, we could be subject to investigation and penalties.
Risks Relating to Our LNG Terminal Business
Operation of the Sabine Pass LNG terminal, the Sabine Pass Liquefaction Project and the Corpus Christi Liquefaction Project and other facilities that we may construct involves significant risks.
As more fully discussed in these Risk Factors, the Sabine Pass LNG terminal, the Sabine Pass Liquefaction Project and the Corpus Christi Liquefaction Project and our other existing and proposed LNG facilities face operational risks, including the following:
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the facilities’ performing below expected levels of efficiency;
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breakdown or failures of equipment;
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operational errors by vessel or tug operators;
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operational errors by us or any contracted facility operator;
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labor disputes; and
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weather-related interruptions of operations.
We may not be successful in implementing our proposed business strategy to provide liquefaction capabilities at the Sabine Pass LNG terminal adjacent to the existing regasification facilities or the Corpus Christi Liquefaction Project.
The Sabine Pass Liquefaction Project and the Corpus Christi Liquefaction Project will require very significant financial resources, which may not be available on terms reasonably acceptable to us or at all. The Total and Centrica SPAs and the Corpus Christi Liquefaction SPAs contain certain conditions precedent, including, but not limited to, receiving regulatory approvals, securing necessary financing arrangements and making a final investment decision to construct the applicable Train. If these conditions are not met by June 30, 2015, each party may terminate its respective SPA.
It will take several years to construct our proposed liquefaction facilities, and we do not expect Train 1 of the Sabine Pass Liquefaction Project to produce LNG until late 2015, at the earliest. Even if successfully constructed, our proposed liquefaction facilities would be subject to the operating risks described herein. Accordingly, there are many risks associated with the Sabine Pass Liquefaction Project and the Corpus Christi Liquefaction Project, and if we are not successful in implementing our business strategy, we may not be able to generate cash flows, which could have a material adverse impact on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Cost overruns and delays in the completion of one or more Trains, as well as difficulties in obtaining sufficient financing to pay for such costs and delays, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
The actual construction costs of the Trains may be significantly higher than our current estimates as a result of many factors, including change orders under existing or future engineering, procurement and construction contracts resulting from the occurrence of certain specified events that may give Bechtel the right to cause us to enter into change orders or resulting from changes with which we otherwise agree. We do not have any prior experience in constructing liquefaction facilities, and no liquefaction facilities have been constructed and placed in service in the United States in over 40 years. As construction progresses, we may decide or be forced to submit change orders to our contractor that could result in longer construction periods, higher construction costs or both.
Delays in the construction of one or more Trains beyond the estimated development periods, as well as change orders to the EPC contracts with Bechtel or any future engineering, procurement and construction contract related to additional Trains, could increase the cost of completion beyond the amounts that we estimate, which could require us to obtain additional sources of
financing to fund our operations until the applicable liquefaction project is constructed (which could cause further delays). Our ability to obtain financing that may be needed to provide additional funding to cover increased costs will depend, in part, on factors beyond our control. Accordingly, we may not be able to obtain financing on terms that are acceptable to us, or at all. Even if we are able to obtain financing, we may have to accept terms that are disadvantageous to us or that may have a material adverse effect on our current or future business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Delays in the completion of one or more Trains could lead to reduced revenues or termination of one or more of the SPAs by our counterparties.
Any delay in completion of a Train could cause a delay in the receipt of revenues projected therefrom or cause a loss of one or more customers in the event of significant delays. As a result, any significant construction delay, whatever the cause, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Our ability to complete development of additional Trains will be contingent on our ability to obtain additional funding. If we are unable to obtain sufficient funding, we may be unable to complete our business plan and our business may ultimately be unsuccessful.
We will require significant additional funding to be able to commence construction of the Corpus Christi Liquefaction Project and Trains 5 and 6 of the Sabine Pass Liquefaction Project, which we may not be able to obtain at a cost that results in positive economics, or at all. The inability to achieve acceptable funding may cause a delay in the development of additional Trains, and we may not be able to complete our business plan. Even if we are able to obtain funding, the funding may be inadequate to cover any increases in costs or delays in completion of the applicable Train, which may cause a delay in the receipt of revenues projected therefrom or cause a loss of one or more customers in the event of significant delays. As a result, any significant construction delay, whatever the cause, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
To maintain the cryogenic readiness of the Sabine Pass LNG terminal, Sabine Pass LNG may need to purchase and process LNG. Sabine Pass LNG’s TUA customers, including Sabine Pass Liquefaction, have the obligation to procure LNG if necessary for the Sabine Pass LNG terminal to maintain its cryogenic state. If they fail to do so, Sabine Pass LNG may need to procure such LNG.
Sabine Pass LNG needs to maintain the cryogenic readiness of the Sabine Pass LNG terminal. Together with Sabine Pass Liquefaction, the two third-party TUA customers have the obligation to maintain minimum inventory levels, and, under certain circumstances, to procure LNG to maintain the cryogenic readiness of the terminal. In the event that aggregate minimum inventory levels are not maintained, Sabine Pass LNG has the right to procure a cryogenic readiness cargo to cure a minimum inventory condition, and to be reimbursed by each TUA customer for their allocable share of the LNG acquisition costs. If Sabine Pass LNG is not able to obtain financing on acceptable terms, it will need to maintain sufficient working capital for such a purchase until it receives reimbursement for the allocable costs of the LNG from its TUA customers or sells the regasified LNG.
Sabine Pass LNG may be required to purchase natural gas to provide fuel at the Sabine Pass LNG terminal, which would increase operating costs and could have a material adverse effect on our results of operations.
Sabine Pass LNG’s TUAs provide for an in-kind deduction of 2% of the LNG delivered to the Sabine Pass LNG terminal, which it uses primarily as fuel for revaporization and self-generated power and to cover natural gas unavoidably lost at the facility. There is a risk that this 2% in-kind deduction will be insufficient for these needs and that Sabine Pass LNG will have to purchase additional natural gas from third parties. Sabine Pass LNG will bear the cost and risk of changing prices for any such fuel.
Hurricanes or other disasters could result in an interruption of our operations, a delay in the completion of our liquefaction projects, higher construction costs, and the deferral of the dates on which payments are due under the SPAs, all of which could adversely affect us.
In August and September of 2005, Hurricanes Katrina and Rita damaged coastal and inland areas located in Texas, Louisiana, Mississippi and Alabama, resulting in the temporary suspension of construction of the Sabine Pass LNG terminal. In September 2008, Hurricane Ike struck the Texas and Louisiana coast, and the Sabine Pass LNG terminal experienced minor damage.
Future storms and related storm activity and collateral effects, or other disasters such as explosions, fires, floods or accidents, could result in damage to, or interruption of operations at, the Sabine Pass LNG terminal or related infrastructure, as well as delays or cost increases in the construction and the development of the Sabine Pass Liquefaction Project, the Corpus Christi Liquefaction Project or our other facilities. Changes in the global climate may have significant physical effects, such as increased frequency and severity of storms, floods, and rising sea levels; if any such effects were to occur, they could have an adverse effect on our coastal operations.
Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the design, construction and operation of our facilities could impede operations and construction and could have a material adverse effect on us.
The design, construction and operation of interstate natural gas pipelines, LNG terminals, including the Sabine Pass Liquefaction Project and the Corpus Christi Liquefaction Project, and other facilities, and the import and export of LNG and the transportation of natural gas, are highly regulated activities. Approvals of the FERC and DOE under Section 3 and Section 7 of the NGA, as well as several other material governmental and regulatory approvals and permits, including several under the CAA and the CWA, are required in order to construct and operate an LNG facility and an interstate natural gas pipeline and export LNG. Although the FERC has issued an order under Section 3 of the NGA authorizing the siting, construction and operation of four Trains at the Sabine Pass Liquefaction Project and an order authorizing the siting, construction and operation of three trains at the Corpus Christi Liquefaction Project, pending a rehearing request from the Sierra Club, the FERC orders require us to obtain certain additional approvals in conjunction with ongoing construction and operations of our proposed liquefaction facilities. In addition, our application to the FERC under Section 3 of the NGA for authorization to site, construct and operate two additional Trains at the Sabine Pass Liquefaction Project is currently pending. The environmental assessment by the FERC was issued in December 2014 and the public comment period has closed with comments from the Sierra Club (as an intervenor) and the EPA (as a cooperating agency). We also have pending applications with the DOE for authorization to export LNG to FTA and non-FTA countries in addition to the orders previously granted to us by the DOE. Authorizations obtained from other federal and state regulatory agencies also contain ongoing conditions, and additional approval and permit requirements may be imposed. We cannot control 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 our projects. There is no assurance that we will obtain and maintain these governmental permits, approvals and authorizations, or that we will be able to obtain them on a timely basis, and failure to obtain and maintain any of these permits, approvals or authorizations could have a material adverse effect on our business, financial condition, operating results, liquidity and prospects.
We are dependent on Bechtel and other contractors for the successful completion of the Sabine Pass Liquefaction Project and the Corpus Christi Liquefaction Project.
Timely and cost-effective completion of the Sabine Pass Liquefaction Project and the Corpus Christi Liquefaction Project in compliance with agreed specifications is central to our business strategy and is highly dependent on the performance of Bechtel and our other contractors under their agreements. The ability of Bechtel and our other contractors to perform successfully under their agreements is dependent on a number of factors, including their ability to:
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design and engineer each Train to operate in accordance with specifications;
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engage and retain third-party subcontractors and procure equipment and supplies;
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respond to difficulties such as equipment failure, delivery delays, schedule changes and failure to perform by subcontractors, some of which are beyond their control;
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attract, develop and retain skilled personnel, including engineers;
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post required construction bonds and comply with the terms thereof;
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manage the construction process generally, including coordinating with other contractors and regulatory agencies; and
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maintain their own financial condition, including adequate working capital.
Although some agreements may provide for liquidated damages if the contractor fails to perform in the manner required with respect to certain of its obligations, the events that trigger a requirement to pay liquidated damages may delay or impair the operation of the applicable liquefaction facility, and any liquidated damages that we receive may not be sufficient to cover the
damages that we suffer as a result of any such delay or impairment. The obligations of Bechtel and our other contractors to pay liquidated damages under their agreements are subject to caps on liability, as set forth therein. Furthermore, we may have disagreements with our contractors about different elements of the construction process, which could lead to the assertion of rights and remedies under their contracts and increase the cost of the applicable liquefaction facility or result in a contractor’s unwillingness to perform further work. If any contractor is unable or unwilling to perform according to the negotiated terms and timetable of its respective agreement for any reason or terminates its agreement, we would be required to engage a substitute contractor. This would likely result in significant project delays and increased costs, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We are relying on third-party engineers to estimate the future capacity ratings and performance capabilities of our proposed liquefaction facilities, and these estimates may prove to be inaccurate.
We are relying on third parties, principally Bechtel, for the design and engineering services underlying our estimates of the future capacity ratings and performance capabilities of our proposed liquefaction facilities. If any Train, when actually constructed, fails to have the capacity ratings and performance capabilities that we intend, our estimates may not be accurate. Failure of any of our Trains to achieve our intended capacity ratings and performance capabilities could prevent us from achieving the commercial start dates under our SPAs and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
If third-party pipelines and other facilities interconnected to our pipelines and facilities are or become unavailable to transport natural gas, this could have a material adverse effect on our business, financial condition, operating results, liquidity and prospects.
We will depend upon third-party pipelines and other facilities that will provide gas delivery options to our proposed liquefaction facilities and pipelines. If the construction of new or modified pipeline connections is not completed on schedule or any pipeline connection were to become unavailable for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity or any other reason, our ability to meet our SPA obligations and continue shipping natural gas from producing regions or to end markets could be restricted, thereby reducing our revenues which could have a material adverse effect on our business, financial condition, operating results, liquidity and prospects.
We may not be able to purchase or receive physical delivery of sufficient natural gas to satisfy our delivery obligations under the SPAs, which could have a material adverse effect on us.
Under the SPAs with our liquefaction customers, we are required to deliver to them a specified amount of LNG at specified times. However, we may not be able to purchase or receive physical delivery of sufficient quantities of natural gas to satisfy those delivery obligations, which may provide affected SPA customers with the right to terminate their SPAs. Our failure to purchase or receive physical delivery of sufficient quantities of natural gas could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Our interstate natural gas pipelines and their FERC gas tariffs are subject to FERC regulation.
Our interstate natural gas pipelines are subject to regulation by the FERC under the NGA and under the Natural Gas Policy Act of 1978. The FERC regulates the transportation of natural gas in interstate commerce, including the construction and operation of our pipelines, the rates and terms of conditions of service and abandonment of facilities. Under the NGA, the rates charged by our interstate natural gas pipelines must be just and reasonable, and we are prohibited from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service. If we fail to comply with all applicable statutes, rules, regulations and orders, our interstate pipelines could be subject to substantial penalties and fines.
Our FERC gas tariffs, including our pro forma transportation agreements, must be filed and approved by the FERC. Before we enter into a transportation agreement with a shipper that contains a term that materially deviates from our tariff, we must seek FERC approval. The FERC may approve the material deviation in the transportation agreement; however, in that case, the materially deviating terms must be made available to our other similarly-situated customers. If we fail to seek FERC approval of a transportation agreement that materially deviates from our tariff, or if the FERC audits our contracts and finds deviations that appear to be unduly discriminatory, the FERC could conduct a formal enforcement investigation, resulting in serious penalties and/or onerous ongoing compliance obligations.
Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the EPAct, the FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1.0 million per day for each violation.
Pipeline safety integrity programs and repairs may impose significant costs and liabilities on us.
The federal Office of Pipeline Safety requires pipeline operators to develop integrity management programs to comprehensively evaluate certain areas along their pipelines and to take additional measures to protect pipeline segments located in “high consequence areas” where a leak or rupture could potentially do the most harm. As an operator, we are required to:
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perform ongoing assessments of pipeline integrity;
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identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
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improve data collection, integration and analysis;
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repair and remediate the pipeline as necessary; and
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implement preventative and mitigating actions.
We are required to maintain pipeline integrity testing programs that are intended to assess pipeline integrity. Any repair, remediation, preventative or mitigating actions may require significant capital and operating expenditures. Should we fail to comply with the Office of Pipeline Safety’s rules and related regulations and orders, we could be subject to significant penalties and fines.
Any reduction in the capacity of, or the allocations to, interconnecting, third-party pipelines could cause a reduction of volumes transported in our pipelines, which would adversely affect our revenues and cash flow.
We will be dependent upon third-party pipelines and other facilities to provide delivery options to and from our pipelines. If any pipeline connection were to become unavailable for volumes of natural gas due to repairs, damage to the facility, lack of capacity or any other reason, our ability to continue shipping natural gas to end markets could be restricted, thereby reducing our revenues. Any permanent interruption at any key pipeline interconnect which caused a material reduction in volumes transported on our pipelines could have a material adverse effect on our business, financial condition, operating results, cash flow, liquidity and prospects.
Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the development and operation of our interstate natural gas pipelines would have a detrimental effect on us and our pipeline projects.
The design, construction and operation of interstate natural gas pipelines and the transportation of natural gas are all highly regulated activities. The FERC’s approval under Section 7 of the NGA, as well as several other material governmental and regulatory approvals and permits, including several under the CAA and the CWA from the USACE and state environmental agencies, are required in order to construct and operate an interstate natural gas pipeline. 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 our pipeline projects. There is no assurance that we will obtain and maintain these governmental permits, approvals and authorizations, or that we will be able to obtain them on a timely basis, and failure to obtain and maintain any of these permits, approvals or authorizations could have a material adverse effect on our business, financial condition, operating results, liquidity and prospects.
Our business could be materially and adversely affected if we lose the right to situate our pipelines on property owned by third parties.
We do not own the land on which our pipelines are situated, and we are subject to the possibility of increased costs to retain necessary land use rights. If we were to lose these rights or be required to relocate our pipelines, our business could be materially and adversely affected.
Risks Relating to Our LNG and Natural Gas Marketing Business
The limited capital resources and credit available to our LNG and natural gas marketing business may limit our ability to develop that business.
We have limited capital available to our LNG and natural gas marketing business. The business also currently has limited access to third-party sources of financing. Other investment-grade marketing companies have greater financial resources than we do. Our LNG and natural gas marketing business continues to develop and implement its business strategy and may not generate sufficient revenues and cash flows to cover the significant fixed costs of the business.
Our exposure to the performance and credit risks of counterparties under agreements may adversely affect our results of operations, liquidity and access to financing.
Our LNG and natural gas marketing business involves our entering into various purchase and sale, hedging and other transactions with numerous third parties (commonly referred to as “counterparties”). In such arrangements, we are exposed to the performance and credit risks of our counterparties, including the risk that one or more counterparties fails to perform its obligation to make deliveries of commodities and/or to make payments. These risks may increase during periods of commodity price volatility. Defaults by suppliers and other counterparties may adversely affect our results of operations, liquidity and access to financing.
Cheniere Marketing may not be able to contract with customers to facilitate the export of LNG on its chartered LNG vessels.
Cheniere Marketing has entered into SPAs with Sabine Pass Liquefaction and Corpus Christi Liquefaction pursuant to which Cheniere Marketing has the option to purchase LNG at the Sabine Pass Liquefaction Project and the Corpus Christi Liquefaction Project, respectively. Cheniere Marketing has also entered into LNG vessel charters in order to secure shipping capacity for the export of LNG to purchasers. Under the charters, each having an initial term of 5 years, Cheniere Marketing is obligated to make payments for these vessels regardless of use in the aggregate amount of approximately $92 million per year with a portion of such payments beginning in 2015. However, Cheniere Marketing may not be able to enter into contracts with purchasers of LNG in quantities equivalent to the vessel capacities for which Cheniere Marketing is required to make payments. Failure to secure buyers for a sufficient amount of LNG could materially and adversely affect Cheniere Marketing’s business, results of operations, cash flows and liquidity.
Risks Relating to Our LNG Businesses in General
We may not construct or operate all of our proposed LNG facilities or Trains or any additional LNG facilities or Trains beyond those currently planned, which could limit our growth prospects.
We may not construct some of our proposed LNG facilities or Trains, including the proposed Corpus Christi Liquefaction Project or natural gas pipelines, whether due to lack of commercial interest or inability to obtain financing or otherwise. Our ability to develop additional liquefaction facilities will also depend on the availability and pricing of LNG and natural gas in North America and other places around the world. Competitors may have longer operating histories, more development experience, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources and access to sources of natural gas and LNG than we do. If we are unable or unwilling to construct and operate additional LNG facilities, our prospects for growth will be limited.
Our cost estimates for Trains are subject to change as a result of cost overruns, change orders under existing or future construction contracts, changes in commodity prices (particularly nickel and steel), escalating labor costs and the potential need for additional funds to be expended to maintain construction schedules. In the event we experience cost overruns, delays or both, the amount of funding needed to complete a Train could exceed our available funds and result in our failure to complete such Train and thereby negatively impact our business and limit our growth prospects.
Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our LNG business and the performance of our customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.
Our LNG business and the development of domestic LNG facilities and projects generally is based on assumptions about the future availability and price of natural gas and LNG, and the prospects for international natural gas and LNG markets. Natural gas and LNG prices have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to one or more of the following factors:
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additions to competitive regasification capacity in North America, Europe, Asia and other markets, which could divert LNG from the Sabine Pass LNG terminal;
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competitive liquefaction capacity in North America, which could divert natural gas from our proposed liquefaction facilities;
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insufficient or oversupply of natural gas liquefaction or receiving capacity worldwide;
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insufficient LNG tanker capacity;
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weather conditions;
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reduced demand and lower prices for natural gas;
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increased natural gas production deliverable by pipelines, which could suppress demand for LNG;
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decreased oil and natural gas exploration activities, which may decrease the production of natural gas;
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cost improvements that allow competitors to offer LNG regasification services or provide liquefaction capabilities at reduced prices;
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changes in supplies of, and prices for, alternative energy sources such as coal, oil, nuclear, hydroelectric, wind and solar energy, which may reduce the demand for natural gas;
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changes in regulatory, tax or other governmental policies regarding imported or exported LNG, natural gas or alternative energy sources, which may reduce the demand for imported or exported LNG and/or natural gas;
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political conditions in natural gas producing regions;
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adverse relative demand for LNG compared to other markets, which may decrease LNG imports into or exports from North America; and
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cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.
Adverse trends or developments affecting any of these factors could result in decreases in the price of LNG and natural gas, which could materially and adversely affect the performance of our customers, and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.
Failure of imported or exported LNG to be a competitive source of energy could adversely affect our customers and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Current operations at the Sabine Pass LNG terminal are dependent upon the ability of our TUA customers to import LNG supplies into the United States, which is primarily dependent upon LNG being a competitive source of energy in North America. In North America, due mainly to a historically abundant supply of natural gas and recent discoveries of substantial quantities of unconventional, or shale, natural gas, imported LNG has not developed into a significant energy source. The success of the regasification services component of our business plan is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be produced internationally and delivered to North America 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 have recently been and may continue to be discovered in North America, which could further increase the available supply of natural gas and could result in natural gas being available at a lower cost than imported LNG.
Operations at our proposed liquefaction facilities will be dependent upon the ability of our SPA customers to deliver LNG supplies from the United States, which is primarily dependent upon LNG being a competitive source of energy internationally. The success of our business plan is dependent, in part, on the extent to which LNG can, for significant periods and in significant
volumes, be supplied from North America and delivered to international markets at a lower cost than the cost of other alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas have recently been and may continue to be discovered outside North America, which could further increase the available supply of natural gas and could result in natural gas being available at a lower cost than LNG exported to these markets.
Political instability in foreign countries that import or export natural gas, or strained relations between such countries and the United States, may also impede the willingness or ability of LNG suppliers and merchants in such countries to import or export LNG from or to the United States. Furthermore, some foreign suppliers of LNG may have economic or other reasons to obtain their LNG from, or direct their LNG to, non-United States markets or from or to competitors’ LNG facilities in the United States. In addition to natural gas, LNG also competes with other sources of energy, including coal, oil, nuclear, hydroelectric, wind and solar energy, which can be or become available at a lower cost in certain markets.
As a result of these and other factors, LNG may not be a competitive source of energy in the United States or internationally. The failure of LNG to be a competitive supply alternative to local natural gas, oil and other alternative energy sources could adversely affect the ability of our customers to deliver LNG from the United States or to the United States on a commercial basis. Any significant impediment to the ability to deliver LNG to or from the United States generally, or to the Sabine Pass LNG terminal or from our proposed liquefaction facilities specifically, could have a material adverse effect on our customers and on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Various economic and political factors could negatively affect the development of LNG facilities, including the Sabine Pass Liquefaction Project and the Corpus Christi Liquefaction Project, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Commercial development of an LNG facility takes a number of years, requires a substantial capital investment and may be delayed by factors such as:
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increased construction costs;
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economic downturns, increases in interest rates or other events that may affect the availability of sufficient financing for LNG projects on commercially reasonable terms;
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decreases in the price of LNG, which might decrease the expected returns relating to investments in LNG projects;
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the inability of project owners or operators to obtain governmental approvals to construct or operate LNG facilities;
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political unrest or local community resistance to the siting of LNG facilities due to safety, environmental or security concerns; and
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any significant explosion, spill or similar incident involving an LNG facility or LNG vessel.
There may be shortages of LNG vessels worldwide, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
The construction and delivery of LNG vessels require significant capital and long construction lead times, and the availability of the vessels could be delayed to the detriment of our LNG business and our customers because of:
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an inadequate number of shipyards constructing LNG vessels and a backlog of orders at these shipyards;
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political or economic disturbances in the countries where the vessels are being constructed;
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changes in governmental regulations or maritime self-regulatory organizations;
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work stoppages or other labor disturbances at the shipyards;
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bankruptcy or other financial crisis of shipbuilders;
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quality or engineering problems;
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weather interference or a catastrophic event, such as a major earthquake, tsunami or fire; and
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shortages of or delays in the receipt of necessary construction materials.
We may not be able to secure firm pipeline transportation capacity on economic terms that is sufficient to meet our feed gas transportation requirements, which could have a material adverse effect on us.
We have contracted for firm capacity for our natural gas feedstock transportation requirements for the Sabine Pass Liquefaction Project and partially for the Corpus Christi Liquefaction Project. We cannot control the regulatory and permitting approvals or third parties’ construction times, which could impair our ability to fulfill our obligations under certain of our SPAs and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We face competition based upon the international market price for LNG.
Our liquefaction projects are subject to the risk of LNG price competition at times when we need to replace any existing SPA, whether due to natural expiration, default or otherwise, or enter into new SPAs. Factors relating to competition may prevent us from entering into a new or replacement SPA on economically comparable terms as existing SPAs, or at all. Such an event could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Factors which may negatively affect potential demand for LNG from our liquefaction projects are diverse and include, among others:
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increases in worldwide LNG production capacity and availability of LNG for market supply;
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increases in demand for LNG but at levels below those required to maintain current price equilibrium with respect to supply;
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increases in the cost to supply natural gas feedstock to our liquefaction projects;
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decreases in the cost of competing sources of natural gas or alternate fuels such as coal, heavy fuel oil and diesel;
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decreases in the price of non-U.S. LNG, including decreases in price as a result of contracts indexed to lower oil prices;
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increases in capacity and utilization of nuclear power and related facilities; and
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displacement of LNG by pipeline natural gas or alternate fuels in locations where access to these energy sources is not currently available.
Terrorist attacks, including cyberterrorism, or military campaigns may adversely impact our business.
A terrorist, including cyberterrorist, or military incident involving an LNG facility, our infrastructure or an LNG vessel may result in delays in, or cancellation of, construction of new LNG facilities, including one or more of the Trains, which would increase our costs and decrease our cash flows. A terrorist incident may also result in temporary or permanent closure of existing LNG facilities, including the Sabine Pass LNG terminal or the Creole Trail Pipeline, which could increase our costs and decrease our cash flows, depending on the duration and timing of the closure. Our operations could also become subject to increased governmental scrutiny that may result in additional security measures at a significant incremental cost to us. In addition, the threat of terrorism and the impact of military campaigns may lead to continued volatility in prices for natural gas that could adversely affect our business and our customers, including their ability to satisfy their obligations to us under our commercial agreements. Instability in the financial markets as a result of terrorism, including cyberterrorism, or war could also materially adversely affect our ability to raise capital. The continuation of these developments may subject our construction and 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, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Risks Relating to Our Business in General
We are subject to significant operating hazards and uninsured risks, one or more of which may create significant liabilities and losses for us.
The operation of our LNG terminals and construction of liquefaction facilities are subject to the inherent risks associated with these types of operations, including explosions, pollution, release of toxic substances, fires, hurricanes and adverse weather conditions, and other hazards, each of which could result in significant delays in commencement or interruptions of operations and/or in damage to or destruction of our facilities or damage to persons and property. In addition, our operations and the facilities and vessels of third parties on which our operations are dependent face possible risks associated with acts of aggression or terrorism.
We do not, nor do we intend to, maintain insurance against all of these risks and losses. We may not be able to maintain desired or required insurance in the future at rates that we consider reasonable. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Existing and future environmental and similar laws and governmental regulations could result in increased compliance costs or additional operating costs or construction costs and restrictions.
Our business is and will be subject to extensive federal, state and local laws and regulations that regulate and restrict, among other things, discharges to air, land and water, with particular respect to the protection of the environment and natural resources; the handling, storage and disposal of hazardous materials, hazardous waste, and petroleum products; and remediation associated with the release of hazardous substances. Many of these laws and regulations, such as the CAA, the Oil Pollution Act, the CWA and the RCRA, and analogous state laws and regulations, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with the construction and operation of our facilities, and require us to maintain permits and provide governmental authorities with access to our facilities for inspection and reports related to our compliance. Violation of these laws and regulations could lead to substantial liabilities, fines and penalties or to capital expenditures related to pollution control equipment that could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Federal and state laws impose liability, without regard to fault or the lawfulness of the original conduct, for the release of certain types or quantities of hazardous substances into the environment. As the owner and operator of our facilities, we could be liable for the costs of cleaning up hazardous substances released into the environment at or from our facilities and for resulting damage to natural resources.
There are numerous regulatory approaches currently in effect or being considered to address GHG emissions, including possible future United States treaty commitments, new federal or state legislation that may impose a carbon emissions tax or establish a cap-and-trade program, and regulation by the EPA. In addition, as we consume natural gas at the Sabine Pass LNG terminal, a future carbon tax or other regulation may be imposed on us directly.
Other future legislation and regulations, such as those relating to the transportation and security of LNG imported to or exported from the Sabine Pass LNG terminal through the Sabine Pass deepwater shipping channel less than four miles from the Gulf Coast and LNG exported from the Corpus Christi LNG terminal near Corpus Christi, Texas on over 1,000 acres of land that we own or control, could cause additional expenditures, restrictions and delays in our business and to our proposed construction, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances. Revised, reinterpreted or additional laws and regulations that result in increased compliance costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
A major health and safety incident relating to our business could be costly in terms of potential liabilities and reputational damage.
Health and safety performance is critical to the success of all areas of our business. Any failure in health and safety performance may result in personal harm or injury, penalties for non-compliance with relevant regulatory requirements or litigation, and a failure that results in a significant health and safety incident is likely to be costly in terms of potential liabilities. Such a failure could generate public concern and have a corresponding impact on our reputation and our relationships with relevant regulatory agencies and local communities, which in turn could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We may experience increased labor costs, and the unavailability of skilled workers or our failure to attract and retain key personnel could adversely affect us.
We are dependent upon the available labor pool of skilled employees. We compete with other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to construct and operate our facilities and pipelines and to provide our customers with the highest quality service. Our affiliates who hire personnel on our behalf are also subject to the Fair Labor Standards Act, which governs such matters as minimum wage, overtime and other working conditions. A shortage in the labor pool of skilled workers or other general inflationary pressures or changes in applicable laws and regulations could make it more difficult for us to attract and retain personnel and could require an increase in the wage and
benefits packages that we offer, thereby increasing our operating costs. Any increase in our operating costs could materially and adversely affect our business, financial condition, operating results, liquidity and prospects.
We depend on our executive officers for various activities. We do not maintain key person life insurance policies on any of our personnel. Although we have arrangements relating to compensation and benefits with certain of our executive officers, we do not have any employment contracts or other agreements with key personnel binding them to provide services for any particular term. The loss of the services of any of these individuals could seriously harm us.
Our lack of diversification could have an adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Substantially all of our anticipated revenue in 2015 will be dependent upon one facility, the Sabine Pass LNG regasification facilities and related pipeline located in southern Louisiana. Due to our lack of asset and geographic diversification, an adverse development at the Sabine Pass LNG terminal or the proposed Corpus Christi LNG terminal including the related pipelines, or in the LNG industry, would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets and operating areas.
We may incur impairments to goodwill or long-lived assets.
We test our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of these assets may not be recoverable. We test goodwill for impairment annually during the fourth quarter, or more frequently as circumstances dictate. Significant negative industry or economic trends, including a significant decline in the market price of our common stock, reduced estimates of future cash flows for our business segments or disruptions to our business could lead to an impairment charge of our long-lived assets, including goodwill. Our valuation methodology for assessing impairment requires management to make judgments and assumptions based on historical experience and to rely heavily on projections of future operating performance. Projections of future operating results and cash flows may vary significantly from results. In addition, if our analysis results in an impairment to our goodwill or long-lived assets, we may be required to record a charge to earnings in our Consolidated Financial Statements during a period in which such impairment is determined to exist, which may negatively impact our results of operations.
The market price of our common stock may fluctuate significantly, and our stockholders could lose all or part of their investment.
The market price of our common stock may fluctuate significantly as a result of a variety of factors, some of which are beyond our control, including:
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fluctuations in our quarterly or annual financial results or those of other companies in our industry;
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issuance of additional equity securities which causes further dilution to stockholders;
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operating and stock price performance of companies that investors deem comparable to us;
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changes in government regulation or proposals applicable to us;
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actual or potential non-performance by any customer or a counterparty under any agreement;
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announcements made by us or our competitors of significant contracts;
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changes in accounting standards, policies, guidance, interpretations or principles;
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general economic conditions;
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the failure of securities analysts to cover our common stock or changes in financial or other estimates by analysts; and
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other factors described in these “Risk Factors.”
In addition, the United States securities markets have experienced significant price and volume fluctuations. These fluctuations have often been unrelated to the operating performance of companies in these markets. Market fluctuations and broad market, economic and industry factors may negatively affect the price of our common stock, regardless of our operating performance. If we were to be the object of securities class litigation as a result of volatility in our common stock price or for other reasons, it could result in substantial diversion of our management’s attention and resources, which could negatively affect our financial results.
If there is a determination that any of the restructuring transactions entered into prior to and in connection with Cheniere Holdings’ initial public offering are taxable for U.S. federal income tax purposes and Cheniere Holdings ceases to be a member of our consolidated group for U.S. federal income tax purposes, then we could incur significant income tax liabilities.
Prior to and in connection with Cheniere Holdings’ initial public offering, we, Cheniere Holdings and other members of our consolidated group for U.S. federal income tax purposes participated in a series of restructuring transactions intended to qualify as tax-free for U.S. federal income tax purposes. No ruling from the U.S. Internal Revenue Service was requested in connection with such restructuring transactions. Under the Internal Revenue Code, Cheniere Holdings will cease to be a member of our consolidated group for U.S. federal income tax purposes (a deconsolidation) if at any time we own less than 80% of the vote or 80% of the value of Cheniere Holdings’ outstanding shares, whether by issuance of additional shares by Cheniere Holdings or by our sale or other disposition of Cheniere Holdings’ shares. If any of the restructuring transactions is determined to be taxable for U.S. federal income tax purposes for any reason, following a deconsolidation, we could incur significant income tax liabilities.
We are subject to litigation which may impact the amount of operating costs and expenses that we have recognized in our financial statements.
During the second quarter of 2014, four lawsuits were filed in the Court of Chancery of the State of Delaware (the “Court”) against us and/or certain of our present and former officers and directors that challenge the manner in which abstentions were treated in connection with the stockholder vote on Amendment No. 1 to the Cheniere Energy, Inc. 2011 Incentive Plan (“Amendment No. 1”), pursuant to which, among other things, the number of shares of common stock available for issuance under the Cheniere Energy, Inc. 2011 Incentive Plan (the “2011 Plan”) was increased from 10 million to 35 million shares. The lawsuits contend that abstentions should have been counted as “no” votes in tabulating the outcome of the vote and that the stockholders did not approve Amendment No. 1 when abstentions are counted as such. The lawsuits further contend that portions of the Amended and Restated Bylaws of Cheniere Energy, Inc. adopted on April 3, 2014 are invalid and that certain disclosures relating to these matters made by us are misleading. The lawsuits assert claims for breach of contract and breach of fiduciary duty (both on a class and a derivative basis) and claims for unjust enrichment (on a derivative basis). The lawsuits seek, among other things, a declaration that the February 1, 2013 stockholder vote on Amendment No. 1 is void, disgorgement of all compensation distributed as a result of Amendment No. 1, voiding the awards made from the shares reserved pursuant to Amendment No. 1 and monetary damages. On June 16, 2014, we filed a verified application with the Court pursuant to 8 Del. C. § 205 (the “Section 205 Action”) in which we ask the Court to declare valid the issuance, pursuant to the 2011 Plan, of the 25 million additional shares of our common stock covered by Amendment No. 1, whether occurring in the past or the future.
The parties to the above-referenced lawsuits and the Section 205 Action have entered into a Stipulation and Agreement of Compromise, Settlement and Release dated December 12, 2014 (the “Stipulation”), subject to its terms and conditions, including receipt, among other things, of Court approval, to resolve the litigation.
We have also agreed that plaintiffs’ counsel is entitled to a fee in connection with the resolution of the stockholder lawsuits, which will be paid by us, our successors in interest and/or our insurers. On February 10, 2015, plaintiffs filed an application with the Court, accompanied by a memorandum of law and expert reports, requesting an award of fees and expenses in the amount of approximately $43 million. If no agreement is reached between us and plaintiffs, we are entitled to contest the amount of fees sought by plaintiffs. The amount of the fee has not yet been determined. We have notified our insurance carriers of the claim. No assurance can be made as to whether any amounts ultimately will be recovered from the insurance carriers.
We have accrued our best estimate of probable loss in accrued liabilities on our Consolidated Balance Sheets. We estimate that the ultimate resolution of the matter could result in a total loss of up to approximately $43 million. As the approval process for the Stipulation and plaintiffs' fee award progresses, additional information could become known and we may be required to recognize additional operating costs and expenses, and that amount could be material to our consolidated financial position, results of operations or cash flows, and could cause our investors to lose confidence in our reported financial information and have a negative effect on the price of our common stock.
ITEM 1B.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
None.
ITEM 3.
ITEM 3.
LEGAL PROCEEDINGS
We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters.
On May 29, 2014, an alleged stockholder of Cheniere commenced a putative class and derivative action in the Court of Chancery of the State of Delaware (the “Court”) against Cheniere, certain members of the Board and certain of Cheniere’s present and former officers captioned Jones v. Souki, et al., C.A. No. 9710-VCL. Since May 29, 2014, additional litigations have been filed captioned Macguire v. Souki, et al., C.A. No. 9746-VCL, Shenker v. Souki, et al., C.A. No. 9763-VCL and Davidoff v. Souki, et al., C.A. No. 9825-VCL. These lawsuits have been consolidated into In re Cheniere Energy, Inc. Stockholders Litigation, Consolidated C.A. No. 9710-VCL (Del. Ch.) (the “Stockholder Action”). In general terms, these litigations challenge the manner in which abstentions were treated in connection with the stockholder vote on Amendment No. 1 to the Cheniere Energy, Inc. 2011 Incentive Plan (“Amendment No. 1”), pursuant to which, among other things, the number of shares of common stock available for issuance under the Cheniere Energy, Inc. 2011 Incentive Plan (the “2011 Plan”) was increased from 10 million to 35 million shares. The lawsuits contend that abstentions should have been counted as “no” votes in tabulating the outcome of the vote and that the stockholders did not approve Amendment No. 1 when abstentions are counted as such. The lawsuits further contend that portions of the Amended and Restated Bylaws of Cheniere Energy, Inc. adopted on April 3, 2014 are invalid and that certain disclosures relating to these matters made by Cheniere are misleading. The lawsuits assert claims for breach of contract and breach of fiduciary duty (both on a class and a derivative basis) and claims for unjust enrichment (on a derivative basis). The lawsuits seek, among other things, a declaration that the February 1, 2013 stockholder vote on Amendment No. 1 is void, disgorgement of all compensation distributed as a result of Amendment No. 1, voiding the awards made from the shares reserved pursuant to Amendment No. 1 and monetary damages.
On June 16, 2014, the defendants filed with the Court a joint motion to stay or dismiss the consolidated action with prejudice and Cheniere filed a verified application pursuant to 8 Del. C. § 205 (the “Section 205 Action”) in which Cheniere asks the Court to declare valid the issuance, pursuant to the 2011 Plan, whether occurring in the past or future, of the 25 million additional shares of common stock of Cheniere covered by Amendment No. 1. On June 27, 2014, the Court entered an order staying the stockholder litigation pending resolution of the Section 205 Action. On July 11, 2014, Cheniere filed a memorandum of law in support of its motion for judgment on Application I asserted in the Section 205 Action (that it correctly tabulated votes in connection with the stockholder vote on Amendment No. 1). On July 25, 2014, certain of the plaintiffs in the lawsuits (who have been given permission to intervene in the Section 205 Action) filed a brief in opposition to Cheniere’s motion for judgment on Application I in the Section 205 Action. Briefing on these issues was completed on August 20, 2014, and the Court held a hearing on the motion on August 26, 2014.
The parties to the above-referenced lawsuits and the Section 205 Action have entered into a Stipulation and Agreement of Compromise, Settlement and Release dated December 12, 2014 (the “Stipulation”), subject to its terms and conditions, including receipt, among other things, of Court approval, to resolve the litigation. If approved, the Stipulation will result in the dismissal with prejudice of the Stockholder Action and the Section 205 Action and a release being granted to the defendants by the plaintiffs and a class of Cheniere’s stockholders. As part of the settlement: (i) the parties will request that the Court validate, pursuant to 8 Del. C. § 205, all awards made pursuant to the 2011 Plan (whether vested or unvested) and declare that recipients of such awards are entitled to keep their awarded shares, subject to the terms and conditions of the award agreements, including any outstanding requirements for vesting; (ii) except with respect to the unawarded shares discussed below, Cheniere will not seek stockholder approval for any share-based compensation prior to January 1, 2017, such that no share-based compensation will be awarded to company executives, directors or consultants other than to the extent stockholders have already approved such compensation or such compensation was approved pursuant to 8 Del. C. § 205 (notwithstanding the foregoing, authorized stock (unissued or treasury) may be used to compensate new employees and a cash pay award (bonus, incentive, etc.) tied to the performance of Cheniere’s stock shall not constitute share-based compensation); (iii) all compensation-related votes through September 17, 2022 will be subject to a majority of the shares present and entitled to vote standard (pursuant to which abstentions will be counted as the functional equivalent of “no” votes and broker non-votes will not be considered in determining the outcome of the resolution, but will be counted for purposes of establishing a quorum); and (iv) the Compensation Committee will be comprised exclusively of independent directors as defined by the NYSE MKT (or the rules of the primary exchange on which Cheniere’s common stock is listed in the future). With respect to the shares authorized pursuant to Amendment No. 1, but not awarded: (i) Cheniere will not award any of these shares unless the issuance of the shares is approved by a new stockholder vote; (ii) no earlier than 90-days after Court approval of the settlement, Cheniere may submit the issue of the unawarded shares to a stockholder vote; and (iii) if stockholders approve issuance of the unawarded shares, no more than 1 million of those shares may be awarded to Mr. Souki.
Consummation of the settlement is subject to Court approval of all aspects of the settlement. Cheniere has also agreed that plaintiffs’ counsel is entitled to a fee in connection with the resolution of the stockholder lawsuits, which will be paid by Cheniere, its successors in interest and/or its insurers. On February 10, 2015, plaintiffs filed an application with the Court, accompanied by a memorandum of law and expert reports, requesting an award of fees and expenses in the amount of approximately $43 million. If no agreement is reached between Cheniere and plaintiffs, Cheniere is entitled to contest the amount of fees sought by plaintiffs. The amount of the fee has not yet been determined. Cheniere has notified its insurance carriers of the claim. No assurance can be made as to whether any amounts ultimately will be recovered from the insurance carriers.
ITEM 4.
ITEM 4.
MINE SAFETY DISCLOSURE
None.
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER
Market Information, Holders and Dividends
Our common stock has traded on the NYSE MKT under the symbol “LNG” since March 24, 2003. The table below presents the high and low sales prices of our common stock, as reported by the NYSE MKT, for each quarter during 2013 and 2014.
As of January 29, 2015, we had 236.7 million shares of common stock outstanding held by approximately 692 record owners.
We have never paid a cash dividend on our common stock. We currently intend to retain earnings to finance the growth and development of our business and do not anticipate paying any cash dividends on the common stock in the foreseeable future. Any future change in our dividend policy will be made at the discretion of our board of directors in light of our financial condition, capital requirements, earnings, prospects and any restrictions under any financing agreements, as well as other factors the board of directors deems relevant.
Purchase of Equity Securities by the Issuer and Affiliated Purchasers
The following table summarizes stock repurchases for the three months ended December 31, 2014:
(1)
Represents shares surrendered to us by participants in our share-based compensation plans to settle the participants’ personal tax liabilities that resulted from the lapsing of restrictions on shares awarded to the participants under these plans.
(2)
The price paid per share was based on the closing trading price of our common stock on the dates on which we repurchased shares from the participants under our share-based compensation plans.
For additional information, see Note 11-Share-Based Compensation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.
Total Stockholder Return
The following graph compares the cumulative total stockholder return on our common stock against the S&P Oil & Gas Exploration & Production Index, and the Russell 2000 Index for the five years ended December 31, 2014. The graph was constructed on the assumption that $100 was invested in our common stock, the S&P Oil & Gas Exploration & Production Index and the Russell 2000 Index on December 31, 2009 and that any dividends were fully reinvested.
Sale of Unregistered Securities
On November 26, 2014, we issued the 2021 Convertible Unsecured Notes. The 2021 Convertible Unsecured Notes were issued on a private placement basis in reliance on the exemption from registration provided for under Section 4(a)(2) of the Securities Act and Regulation S promulgated thereunder. Beginning one year after the closing date of the offering, provided that the closing price of our common stock is greater than or equal to the conversion price on the date of conversion, the 2021 Convertible Unsecured Notes will be convertible at the option of the holder into our common stock at an initial conversion price of $93.64. The conversion rate is subject to adjustment upon the occurrence of certain specified events.
ITEM 6.
ITEM 6.
SELECTED FINANCIAL DATA
Selected financial data set forth below are derived from our audited consolidated financial statements for the periods indicated. The financial data should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and our Consolidated Financial Statements and the accompanying notes thereto included elsewhere in this report.
(1)
General and administrative expense includes $96.7 million, $252.1 million, $53.2 million, $24.4 million and $16.1 million share-based compensation expense recognized in the years ended December 31, 2014, 2013, 2012, 2011 and 2010, respectively.
ITEM 7.
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Introduction
The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our Consolidated Financial Statements and the accompanying notes in “Financial Statements and Supplementary Data.” This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future. Our discussion and analysis include the following subjects:
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Overview of Business
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Overview of Significant Events
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Liquidity and Capital Resources
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Contractual Obligations
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Results of Operations
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Off-Balance Sheet Arrangements
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Summary of Critical Accounting Estimates
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Recent Accounting Standards
Overview of Business
Cheniere Energy, Inc. (NYSE MKT: LNG), a Delaware corporation, is a Houston-based energy company primarily engaged in LNG-related businesses. We own and operate the Sabine Pass LNG terminal in Louisiana through our ownership interest in and management agreements with Cheniere Energy Partners, L.P. (“Cheniere Partners”) (NYSE MKT: CQP), which is a publicly traded limited partnership that we created in 2007. We own 100% of the general partner interest in Cheniere Partners and 80.1% of Cheniere Energy Partners LP Holdings, LLC (“Cheniere Holdings”) (NYSE MKT: CQH), which is a publicly traded limited liability company formed in 2013 that owns a 55.9% limited partner interest in Cheniere Partners.
The Sabine Pass LNG terminal is located on the Sabine Pass deepwater shipping channel less than four miles from the Gulf Coast. The Sabine Pass LNG terminal has operational regasification facilities owned by Cheniere Partners’ wholly owned subsidiary, Sabine Pass LNG, L.P. (“Sabine Pass LNG”), that includes existing infrastructure of five LNG storage tanks with capacity of approximately 16.9 Bcfe, two docks that can accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. Cheniere Partners is developing and constructing natural gas liquefaction facilities at the Sabine Pass LNG terminal adjacent to the existing regasification facilities through a wholly owned subsidiary, Sabine Pass Liquefaction, LLC (“Sabine Pass Liquefaction”). Cheniere Partners plans to construct up to six Trains, which are in various stages of development. Each Train is expected to have a nominal production capacity of approximately 4.5 mtpa of LNG. Cheniere Partners also owns the 94-mile Creole Trail Pipeline through a wholly owned subsidiary, Cheniere Creole Trail Pipeline, L.P. (“CTPL”), which interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines.
We are developing a second natural gas liquefaction and export facility and pipeline facility near Corpus Christi, Texas (the “Corpus Christi Liquefaction Project”) through wholly owned subsidiaries Corpus Christi Liquefaction, LLC (“Corpus Christi Liquefaction”) and Cheniere Corpus Christi Pipeline, L.P. (“Cheniere Corpus Christi Pipeline”), respectively. As currently contemplated, the Corpus Christi LNG terminal would be designed for up to three Trains, with expected aggregate nominal production capacity of approximately 13.5 mtpa of LNG, three LNG storage tanks with capacity of approximately 10.1 Bcfe and two docks that can accommodate vessels with nominal capacity of up to 266,000 cubic meters. The Corpus Christi Liquefaction Project also would include a 23-mile pipeline that would interconnect the Corpus Christi LNG terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline”).
One of our subsidiaries, Cheniere Marketing, LLC (“Cheniere Marketing”), is engaged in the LNG and natural gas marketing business and is seeking to develop a portfolio of long-term, short-term and spot SPAs. Cheniere Marketing has entered into SPAs with Sabine Pass Liquefaction and Corpus Christi Liquefaction to purchase LNG produced by the Sabine Pass Liquefaction Project and the Corpus Christi Liquefaction Project.
We are also in various stages of developing other projects, which, among other things, will require acceptable commercial and financing arrangements before we make a final investment decision.
Overview of Significant Events
Our significant accomplishments since January 1, 2014 and through the filing date of this Form 10-K include the following:
Cheniere
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Corpus Christi Liquefaction and Cheniere Corpus Christi Pipeline received authorization from the Federal Energy Regulatory Commission (the “FERC”) to site, construct and operate the Corpus Christi Liquefaction Facilities for the liquefaction and export of domestically produced natural gas at the Corpus Christi LNG terminal and for the transportation of natural gas bi-directionally between the Corpus Christi LNG terminal and existing interstate and intrastate natural gas pipeline systems, respectively. The FERC order authorizes the development of up to three modular Trains and a 23-mile pipeline.
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Corpus Christi Liquefaction entered into the following:
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an SPA with each of Endesa Generación, S.A. (which was subsequently assigned to Endesa S.A.) and Endesa S.A. (together, “Endesa”) under which Endesa has agreed to purchase a total of 117.3 million MMBtu of LNG per year (approximately 2.25 mtpa) upon the date of first commercial delivery of LNG from the Corpus Christi Liquefaction Project.
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an SPA with Iberdrola S.A. (“Iberdrola”) under which Iberdrola has agreed to purchase a total of 39.7 million MMBtu of LNG per year (approximately 0.76 mtpa) upon the date of first commercial delivery of LNG from Train 2 of the Corpus Christi Liquefaction Project. In addition, Corpus Christi Liquefaction will provide Iberdrola with bridging volumes of 19.8 million MMBtu per contract year, starting on the date on which Train 1 of the Corpus Christi Liquefaction Project becomes commercially operable and ending on the date of the first commercial delivery of LNG from Train 2 of the Corpus Christi Liquefaction Project.
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an SPA with Gas Natural Fenosa LNG SL (“Gas Natural Fenosa LNG”) under which Gas Natural Fenosa LNG has agreed to purchase a total of 78.2 million MMBtu of LNG per year (approximately 1.5 mtpa) upon the date of first commercial delivery of LNG from Train 2 of the Corpus Christi Liquefaction Project.
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an SPA with Woodside Energy Trading Singapore Pte Ltd (“Woodside”) under which Woodside has agreed to purchase a total of 44.1 million MMBtu of LNG per year (approximately 0.85 mtpa) upon the date of first commercial delivery of LNG from Train 2 of the Corpus Christi Liquefaction Project.
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a second SPA with PT Pertamina (Persero) (“Pertamina”) under which Pertamina has agreed to purchase an additional 39.7 million MMBtu of LNG per year (approximately 0.76 mtpa) upon the date of first commercial delivery of LNG from Train 2 of the Corpus Christi Liquefaction Project.
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an SPA with Électricité de France, S.A. (“EDF”) under which EDF has agreed to purchase 40.0 million MMBtu of LNG per year (approximately 0.77 mtpa) upon the date of first commercial delivery of LNG from Train 3 of the Corpus Christi Liquefaction Project. In addition, Corpus Christi Liquefaction will provide EDF with bridging volumes of 20.0 million MMBtu per contract year, starting on the date on which Train 2 of the Corpus Christi Liquefaction Project becomes commercially operable and ending on the date of the first commercial delivery of LNG from Train 3 of the Corpus Christi Liquefaction Project.
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an SPA with EDP Energias de Portugal S.A. (“EDP”) under which EDP has agreed to purchase a total of 40.0 million MMBtu of LNG per year (approximately 0.77 mtpa) upon the date of first commercial delivery of LNG from Train 3 of the Corpus Christi Liquefaction Project.
•
We issued an aggregate principal amount of $1.0 billion Convertible Unsecured Notes due 2021 (the “2021 Convertible Unsecured Notes”) to RRJ Capital II Ltd, Baytree Investments (Mauritius) Pte Ltd, and Seatown Lionfish Pte. Ltd., on a private placement basis. The 2021 Convertible Unsecured Notes accrue interest at a rate of 4.875% per annum, which is payable in kind (“PIK”) semi-annually in arrears by increasing the principal amount of the 2021 Convertible Unsecured Notes outstanding. The proceeds will be used for general corporate purposes and to fund a portion of the costs of developing, constructing and operating the Corpus Christi Liquefaction Project.
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We entered into the following:
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a note purchase agreement with EIG Management Company, LLC (“EIG”) to purchase $1.5 billion of convertible notes that would be issued by Cheniere CCH HoldCo II, LLC, a wholly owned direct subsidiary of Cheniere, which is scheduled to fund once we reach a positive final investment decision on the Corpus Christi Liquefaction Project. The net proceeds would be used to fund a portion of the costs of developing, constructing and placing into service the Corpus Christi Liquefaction Project.
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an agreement with 19 financial institutions to act as Joint Lead Arrangers to assist in the structuring and arranging of up to $11.5 billion of debt facilities. The proceeds will be used to pay for a portion of the costs of developing, constructing and placing into service the Corpus Christi Liquefaction Project.
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Our wholly owned subsidiary, Cheniere Marketing, entered into an amended and restated SPA with Sabine Pass Liquefaction to purchase, at Cheniere Marketing’s option, any LNG produced by Sabine Pass Liquefaction in excess of that required for other customers at a price of 115% of Henry Hub plus $3.00 per MMBtu of LNG.
Cheniere Partners
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Sabine Pass Liquefaction entered into a $325.0 million senior letter of credit and reimbursement agreement (the “Sabine Pass Liquefaction LC Agreement”) that it is using for the issuance of letters of credit on behalf of Sabine Pass Liquefaction for certain working capital requirements related to the Sabine Pass Liquefaction Project.
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Sabine Pass Liquefaction issued an aggregate principal amount of $2.0 billion of 5.75% Senior Secured Notes due 2024 (the “2024 Sabine Pass Liquefaction Senior Notes”) and $0.5 billion of 5.625% Senior Secured Notes due 2023 (the “2023 Sabine Pass Liquefaction Senior Notes”). Net proceeds from the offering of approximately $2.5 billion were used to repay its outstanding indebtedness under the 2013 Liquefaction Credit Facilities (as defined below), and the remaining proceeds are being used to pay a portion of the capital costs associated with the construction of the first four Trains of the Sabine Pass Liquefaction Project in lieu of the terminated portion of the commitments under the 2013 Liquefaction Credit Facilities.
Cheniere Holdings
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Cheniere Holdings completed a public offering of 10,100,000 common shares for net proceeds of approximately $229 million, after deducting offering expenses. The net proceeds were used to redeem from us the same number of common shares, which reduced our ownership of Cheniere Holdings’ common shares from 84.5% to 80.1%.
Liquidity and Capital Resources
Although results are consolidated for financial reporting, Cheniere, Cheniere Holdings, Cheniere Partners, Sabine Pass Liquefaction and Sabine Pass LNG operate with independent capital structures. We expect the cash needs for at least the next twelve months will be met for each of these independent capital structures as follows:
•Sabine Pass LNG through operating cash flows and existing unrestricted cash;
•Sabine Pass Liquefaction through project debt and equity financings;
•Cheniere Partners through operating cash flows from Sabine Pass LNG and existing unrestricted cash;
•Cheniere Holdings through distributions from Cheniere Partners; and
•
Cheniere through existing unrestricted cash, services fees from Cheniere Holdings, Cheniere Partners and its other subsidiaries, distributions from our investments in Cheniere Holdings and Cheniere Partners and operating cash flows from our LNG and natural gas marketing business. In addition, we expect to finance the construction costs of the Corpus Christi Liquefaction Project and other corporate activities from one or more of the following: project financing, debt and equity offerings by us or our subsidiaries, available cash and operating cash flow.
In November 2014, we issued the 2021 Convertible Unsecured Notes. Beginning one year after the closing date, the 2021 Convertible Unsecured Notes will be convertible at the option of the holder into our common stock at an initial conversion price of $93.64, provided that our closing price of common stock is greater than or equal to $93.64 on the conversion date. The conversion rate is subject to adjustment upon the occurrence of certain specified events. We have the option to satisfy the conversion obligation with cash, common stock or a combination thereof.
As of December 31, 2014, we had cash and cash equivalents of $1,747.6 million available to Cheniere. In addition, we had current and non-current restricted cash and cash equivalents of $1,032.5 million (which included current and non-current restricted cash and cash equivalents available to Cheniere Holdings, Cheniere Partners, Sabine Pass Liquefaction and Sabine Pass LNG) designated for the following purposes: $612.9 million for the Sabine Pass Liquefaction Project; $36.2 million for CTPL; $91.1 million for interest payments related to the Sabine Pass LNG Senior Notes described below; and $292.3 million for other restricted purposes.
Substantially all of our revenues from external customers and long-lived assets are attributed to or located in the United States.
Cheniere Holdings
Cheniere Holdings was formed by us to hold our Cheniere Partners limited partner interests, thereby allowing us to segregate our lower risk, stable, cash flow generating assets from our higher risk, early stage development projects and marketing activities. As of December 31, 2014, we had an 80.1% direct ownership interest in Cheniere Holdings. We receive dividends on our Cheniere Holdings shares from the distributions that Cheniere Holdings receives from Cheniere Partners, and we receive management fees for managing Cheniere Holdings. For the year ended December 31, 2014, we received $14.3 million in dividends on our Cheniere Holdings common shares and $1.1 million of management fees from Cheniere Holdings.
Cheniere Partners
Our ownership interest in the Sabine Pass LNG terminal is held through Cheniere Partners. As of December 31, 2014, we own 80.1% of Cheniere Holdings, which owns a 55.9% limited partner interest in Cheniere Partners in the form of 11,963,488 common units, 45,333,334 Class B units and 135,383,831 subordinated units. We also own 100% of the general partner interest and the incentive distribution rights in Cheniere Partners.
Prior to the initial public offering by Cheniere Holdings (the “Cheniere Holdings Offering”), we received quarterly equity distributions from Cheniere Partners related to our limited partner and 2% general partner interests. We will continue to receive quarterly equity distributions from Cheniere Partners related to our 2% general partner interest, and we receive fees for providing services to Cheniere Partners, Sabine Pass LNG, Sabine Pass Liquefaction and CTPL. During the year ended December 31, 2014, we received $2.0 million in distributions on our general partner interest and $110.5 million in total service fees from Cheniere Partners, Sabine Pass LNG, Sabine Pass Liquefaction and CTPL.
Cheniere Partners’ common unit and general partner distributions are being funded from accumulated operating surplus. We have not received distributions on our subordinated units with respect to the quarters ended on or after June 30, 2010. Cheniere Partners will not make distributions on our subordinated units until it generates additional cash flow from the Sabine Pass Liquefaction Project, Sabine Pass LNG’s excess capacity or other new business, which would be used to make quarterly distributions on our subordinated units before any increase in distributions to the common unitholders.
Cheniere Partners’ Class B units are subject to conversion, mandatorily or at the option of the Class B unitholders under specified circumstances, into a number of common units based on the then-applicable conversion value of the Class B units. The Cheniere Partners Class B units are not entitled to cash distributions except in the event of a liquidation of Cheniere Partners, a merger, consolidation or other combination of Cheniere Partners with another person or the sale of all or substantially all of the assets of Cheniere Partners. On a quarterly basis beginning on the initial purchase of the Class B units and ending on the conversion date of the Class B units, the conversion value of the Class B units increases at a compounded rate of 3.5% per quarter, subject to an additional upward adjustment for certain equity and debt financings. The accreted conversion ratio of the Class B units owned by Cheniere Holdings and Blackstone CQP Holdco LP (“Blackstone”) was 1.41 and 1.39, respectively, as of December 31, 2014. We expect the Class B units to mandatorily convert into common units within 90 days of the substantial completion date of Train 3 of the Sabine Pass Liquefaction Project, which Cheniere Partners currently expects to occur before March 31, 2017. If the Class B units are not mandatorily converted by July 2019, the holders of the Class B units have the option to convert the Class B units into common units at that time.
LNG Terminal Business
Sabine Pass LNG Terminal
Regasification Facilities
The Sabine Pass LNG terminal has operational regasification capacity of approximately 4.0 Bcf/d and aggregate LNG storage capacity of approximately 16.9 Bcfe. Approximately 2.0 Bcf/d of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term third-party TUAs, under which Sabine Pass LNG’s customers are required to pay fixed monthly fees, whether or not they use the LNG terminal. Each of Total Gas & Power North America, Inc. (“Total”) and Chevron U.S.A. Inc. (“Chevron”) has reserved approximately 1.0 Bcf/d of regasification capacity and is obligated to make monthly capacity payments to Sabine Pass LNG aggregating approximately $125 million annually for 20 years that commenced in 2009. Total S.A. has guaranteed Total’s obligations under its TUA up to $2.5 billion, subject to certain exceptions, and Chevron Corporation has guaranteed Chevron’s obligations under its TUA up to 80% of the fees payable by Chevron.
The remaining approximately 2.0 Bcf/d of capacity has been reserved under a TUA by Sabine Pass Liquefaction. Sabine Pass Liquefaction is obligated to make monthly capacity payments to Sabine Pass LNG aggregating approximately $250 million annually, continuing until at least 20 years after Sabine Pass Liquefaction delivers its first commercial cargo at the Sabine Pass Liquefaction Project.
Under each of these TUAs, Sabine Pass LNG is entitled to retain 2% of the LNG delivered to the Sabine Pass LNG terminal.
Liquefaction Facilities
The Sabine Pass Liquefaction Project is being developed and constructed at the Sabine Pass LNG terminal adjacent to the existing regasification facilities. We have received authorization from the FERC to site, construct and operate Trains 1 through 4. We commenced construction of Trains 1 and 2 and the related new facilities needed to treat, liquefy, store and export natural gas in August 2012. Construction of Trains 3 and 4 and the related facilities commenced in May 2013. On September 30, 2013, we filed an application with the FERC for the approval to site, construct and operate Trains 5 and 6.
The U.S. Department of Energy (the “DOE”) has authorized the export of up to a combined total of the equivalent of 16 mtpa (approximately 803 Bcf/yr) of domestically produced LNG by vessel from the Sabine Pass LNG terminal to countries with which the United States has a free trade agreement providing for national treatment for trade in natural gas (“FTA countries”) for a 30-year term, beginning on the earlier of the date of first export or September 7, 2020; and to all countries without a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted (“non-FTA countries”) for a 20-year term, beginning on the earlier of the date of first export or August 7, 2017. The DOE further issued an order authorizing Sabine Pass Liquefaction to export up to the equivalent of approximately 203 Bcf/yr of domestically produced LNG from the Sabine Pass LNG terminal to FTA countries for a 25-year period. Additionally, the DOE further issued orders authorizing Sabine Pass Liquefaction to export an additional 503.3 Bcf/yr in total of domestically produced LNG from the Sabine Pass LNG terminal to FTA countries for a 20-year term. Sabine Pass Liquefaction’s applications for authorization to export that same 503.3 Bcf/yr of domestically produced LNG from the Sabine Pass LNG terminal to non-FTA countries are currently pending at the DOE.
As of December 31, 2014, the overall project completion percentages for Trains 1 and 2 and Trains 3 and 4 of the Sabine Pass Liquefaction Project were approximately 81% and 54%, respectively, which are ahead of the contractual schedule. Based on our current construction schedule, we anticipate that Train 1 will produce LNG as early as late 2015, and Trains 2, 3 and 4 are expected to commence operations on a staggered basis thereafter.
Customers
Sabine Pass Liquefaction has entered into four fixed price, 20-year SPAs with third parties that in the aggregate equate to 16 mtpa (approximately 803 Bcf/yr) of LNG that commence with the date of first commercial delivery for Trains 1 through 4, which are fully permitted. In addition, Sabine Pass Liquefaction has entered into two fixed price, 20-year SPAs with third parties for another 3.75 mtpa of LNG that commence with the date of first commercial delivery for Train 5. However, Sabine Pass Liquefaction has not yet received regulatory approval for construction of Train 5. These two SPAs contain certain conditions precedent, including, but not limited to, receiving regulatory approvals, securing necessary financing arrangements and making a final investment decision with respect to Train 5, which must be satisfied by June 30, 2015 or either party to the respective SPA
may terminate its SPA. Under the SPAs, the customers will purchase LNG from Sabine Pass Liquefaction for a price consisting of a fixed fee plus 115% of Henry Hub per MMBtu of LNG. In certain circumstances, the customers may elect to cancel or suspend deliveries of LNG cargoes, in which case the customers would still be required to pay the fixed fee with respect to cargoes that are not delivered. A portion of the fixed fee will be subject to annual adjustment for inflation. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA commences upon the start of operations of a specified Train.
In aggregate, the fixed fee portion to be paid by these customers is approximately $2.3 billion annually for Trains 1 through 4, and $2.9 billion annually if we make a positive final investment decision with respect to Train 5, with the applicable fixed fees starting from the commencement of commercial operations of the applicable Train. These fixed fees equal approximately $411 million, $564 million, $650 million, $648 million and $588 million for each of Trains 1 through 5, respectively.
In addition, Cheniere Marketing has entered into an amended and restated SPA with Sabine Pass Liquefaction to purchase, at Cheniere Marketing’s option, any LNG produced by Sabine Pass Liquefaction in excess of that required for other customers at a price of 115% of Henry Hub plus $3.00 per MMBtu of LNG.
Natural Gas Transportation and Supply
For Sabine Pass Liquefaction’s natural gas feedstock transportation requirements, it has entered into transportation precedent agreements to secure firm pipeline transportation capacity with CTPL and third-party pipeline companies. Sabine Pass Liquefaction has also entered into enabling agreements and long-term natural gas purchase agreements with third parties in order to secure natural gas feedstock for the Sabine Pass Liquefaction Project. As of December 31, 2014, we have secured up to approximately 2,162,000,000 MMBtu of natural gas feedstock through long-term natural gas purchase agreements.
Construction
Trains 1 through 4 are being designed, constructed and commissioned by Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”). Sabine Pass Liquefaction entered into lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of Train 1 and Train 2 (the “EPC Contract (Trains 1 and 2)”) and Train 3 and Train 4 (the “EPC Contract (Trains 3 and 4)”) under which Bechtel charges a lump sum for all work performed and generally bears project cost risk unless certain specified events occur, in which case Bechtel may cause Sabine Pass Liquefaction to enter into a change order, or Sabine Pass Liquefaction agrees with Bechtel to a change order.
The total contract price of the EPC Contract (Trains 1 and 2) and the total contract price of the EPC Contract (Trains 3 and 4) are approximately $4.1 billion and $3.8 billion, respectively, reflecting amounts incurred under change orders through December 31, 2014. Total expected capital costs for Trains 1 through 4 are estimated to be between $9.0 billion and $10.0 billion before financing costs and between $12.0 billion and $13.0 billion after financing costs, including, in each case, estimated owner’s costs and contingencies.
Pipeline Facilities
CTPL owns the Creole Trail Pipeline, a 94-mile pipeline interconnecting the Sabine Pass LNG terminal with a number of large interstate pipelines. In December 2013, CTPL began construction of certain modifications to allow the Creole Trail Pipeline to be able to transport natural gas to the Sabine Pass LNG terminal. Cheniere Partners estimates that the capital costs to modify the Creole Trail Pipeline will be approximately $105 million. The modifications are expected to be in service in time for the commissioning and testing of Trains 1 and 2.
Final Investment Decision on Train 5 and Train 6
We will contemplate making a final investment decision to commence construction of Train 5 and Train 6 of the Sabine Pass Liquefaction Project based upon, among other things, entering into an EPC contract, entering into acceptable commercial arrangements, receiving regulatory authorizations and obtaining adequate financing to construct the Trains.
Capital Resources
We currently expect that Sabine Pass Liquefaction’s capital resources requirements with respect to Trains 1 through 4 of the Sabine Pass Liquefaction Project will be financed through one or more of the following: borrowings, equity contributions from Cheniere Partners and cash flows under the SPAs. We believe that with the net proceeds of borrowings, unfunded commitments under the 2013 Liquefaction Credit Facilities and cash flows from operations, we will have adequate financial resources available to complete Trains 1 through 4 of the Sabine Pass Liquefaction Project and to meet its currently anticipated capital, operating and debt service requirements. We currently project that Sabine Pass Liquefaction will generate cash flow from the Sabine Pass Liquefaction Project by late 2015, when Train 1 of the Sabine Pass Liquefaction Project is anticipated to achieve initial LNG production.
Senior Secured Notes
As of December 31, 2014, Cheniere Partners’ subsidiaries had six series of senior secured notes outstanding (collectively, the “Senior Notes”):
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$1.7 billion of 7.50% Senior Secured Notes due 2016 issued by Sabine Pass LNG (the “2016 Sabine Pass LNG Senior Notes”);
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$0.4 billion of 6.50% Senior Secured Notes due 2020 issued by Sabine Pass LNG (the “2020 Sabine Pass LNG Senior Notes” and collectively with the 2016 Sabine Pass LNG Senior Notes, the “Sabine Pass LNG Senior Notes”);
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$2.0 billion of 5.625% Senior Secured Notes due 2021 issued by Sabine Pass Liquefaction (the “2021 Sabine Pass Liquefaction Senior Notes”);
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$1.0 billion of 6.25% Senior Secured Notes due 2022 issued by Sabine Pass Liquefaction (the “2022 Sabine Pass Liquefaction Senior Notes” and collectively with the 2021 Sabine Pass Liquefaction Senior Notes, the 2023 Sabine Pass Liquefaction Senior Notes and the 2024 Sabine Pass Liquefaction Senior Notes, the “Sabine Pass Liquefaction Senior Notes”);
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$1.5 billion of 2023 Sabine Pass Liquefaction Senior Notes; and
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$2.0 billion of 2024 Sabine Pass Liquefaction Senior Notes.
Interest on the Senior Notes is payable semi-annually in arrears. Subject to permitted liens, the Sabine Pass LNG Senior Notes are secured on a pari passu first-priority basis by a security interest in all of Sabine Pass LNG’s equity interests and substantially all of Sabine Pass LNG’s operating assets. The Sabine Pass Liquefaction Senior Notes are secured on a first-priority basis by a security interest in all of the membership interests in Sabine Pass Liquefaction and substantially all of Sabine Pass Liquefaction’s assets.
Sabine Pass LNG may redeem all or part of its 2016 Sabine Pass LNG Senior Notes at any time at a redemption price equal to 100% of the principal plus any accrued and unpaid interest plus the greater of:
•1.0% of the principal amount of the 2016 Sabine Pass LNG Senior Notes; or
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the excess of: a) the present value at such redemption date of (i) the redemption price of the 2016 Sabine Pass LNG Senior Notes plus (ii) all required interest payments due on the 2016 Sabine Pass LNG Senior Notes (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50 basis points; over b) the principal amount of the 2016 Sabine Pass LNG Senior Notes, if greater.
Sabine Pass LNG may redeem all or part of the 2020 Sabine Pass LNG Senior Notes at any time on or after November 1, 2016 at fixed redemption prices specified in the indenture governing the 2020 Sabine Pass LNG Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. Sabine Pass LNG may also, at its option, redeem all or part of the 2020 Sabine Pass LNG Senior Notes at any time prior to November 1, 2016, at a “make-whole” price set forth in the indenture governing the 2020 Sabine Pass LNG Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. At any time before November 1, 2015, Sabine Pass LNG may redeem up to 35% of the aggregate principal amount of the 2020 Sabine Pass LNG Senior Notes at a redemption price of 106.5% of the principal amount of the 2020 Sabine Pass LNG Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the redemption date, in an amount not to exceed the net proceeds of one or more completed equity offerings as long as Sabine Pass LNG redeems the 2020 Sabine Pass LNG Senior Notes within 180 days of the closing date for such equity offering and at least 65% of the aggregate principal amount of the 2020 Sabine Pass LNG Senior Notes originally issued remains outstanding after the redemption.
At any time prior to November 1, 2020, with respect to the 2021 Sabine Pass Liquefaction Senior Notes; December 15, 2021, with respect to the 2022 Sabine Pass Liquefaction Senior Notes; January 15, 2023, with respect to the 2023 Sabine Pass Liquefaction Senior Notes; or February 15, 2024, with respect to the 2024 Sabine Pass Liquefaction Senior Notes, Sabine Pass Liquefaction may redeem all or part of such series of the Sabine Pass Liquefaction Senior Notes at a redemption price equal to the “make-whole” price set forth in the common indenture governing the Sabine Pass Liquefaction Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. Sabine Pass Liquefaction may also at any time on or after November 1, 2020, with respect to the 2021 Sabine Pass Liquefaction Senior Notes; December 15, 2021, with respect to the 2022 Sabine Pass Liquefaction Senior Notes; January 15, 2023, with respect to the 2023 Sabine Pass Liquefaction Senior Notes; or February 15, 2024, with respect to the 2024 Sabine Pass Liquefaction Senior Notes, redeem all or part of such series of the Sabine Pass Liquefaction Senior Notes at a redemption price equal to 100% of the principal amount of such series of the Sabine Pass Liquefaction Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.
Under the indentures governing the Sabine Pass LNG Senior Notes, except for permitted tax distributions, Sabine Pass LNG may not make distributions until, among other requirements, deposits are made into debt service reserve accounts and a fixed charge coverage ratio test of 2:1 is satisfied. Under the common indenture governing the Sabine Pass Liquefaction Senior Notes, Sabine Pass Liquefaction may not make any distributions until, among other requirements, substantial completion of Trains 1 and 2 has occurred, deposits are made into debt service reserve accounts and a debt service coverage ratio test of 1.25:1.00 is satisfied.
The Sabine Pass Liquefaction Senior Notes are governed by a common indenture with restrictive covenants. Sabine Pass Liquefaction may incur additional indebtedness in the future, including by issuing additional notes, and such indebtedness could be at higher interest rates and have different maturity dates and more restrictive covenants than the current outstanding indebtedness of Sabine Pass Liquefaction, including the Sabine Pass Liquefaction Senior Notes, the 2013 Liquefaction Credit Facilities and the Sabine Pass Liquefaction LC Agreement described below.
2013 Liquefaction Credit Facilities
In May 2013, Sabine Pass Liquefaction entered into four credit facilities aggregating $5.9 billion (collectively, the “2013 Liquefaction Credit Facilities”). In conjunction with Sabine Pass Liquefaction’s issuance in May 2014 of the 2024 Sabine Pass Liquefaction Senior Notes and the additional issuance of the 2023 Sabine Pass Liquefaction Senior Notes (the “Additional 2023 Sabine Pass Liquefaction Senior Notes”), in an aggregate principal amount of $2.5 billion before premium, Sabine Pass Liquefaction terminated approximately $2.1 billion of commitments under the 2013 Liquefaction Credit Facilities. As a result, as of December 31, 2014, Sabine Pass Liquefaction has available commitments aggregating $2.7 billion under the 2013 Liquefaction Credit Facilities, which will be used to fund a portion of the costs of developing, constructing and placing into operation Trains 1 through 4 of the Sabine Pass Liquefaction Project. The principal of the loans made under the 2013 Liquefaction Credit Facilities must be repaid in quarterly installments, commencing with the earlier of the last day of the first full calendar quarter after the Train 4 completion date, as defined in the 2013 Liquefaction Credit Facilities, or September 30, 2018. Loans under the 2013 Liquefaction Credit Facilities bear interest at a variable rate per annum equal to, at Sabine Pass Liquefaction’s election, the London Interbank Offered Rate (“LIBOR”) or the base rate plus the applicable margin. The applicable margins for LIBOR loans range from 2.3% to 3.0% prior to the completion of Train 4 and from 2.3% to 3.25% after such completion, depending on the applicable 2013 Liquefaction Credit Facility. The 2013 Liquefaction Credit Facilities also require Sabine Pass Liquefaction to pay a commitment fee calculated at a rate per annum equal to 40% of the applicable margin for LIBOR loans, multiplied by the average daily amount of undrawn commitments. Interest on LIBOR loans and the commitment fees are due and payable at the end of each LIBOR period and quarterly, respectively. Under the terms of the 2013 Liquefaction Credit Facilities, Sabine Pass Liquefaction is required to hedge not less than 75% of the variable interest rate exposure of its projected outstanding borrowings, calculated on a weighted average basis in comparison to its anticipated draw of principal.
2012 Liquefaction Credit Facility
In July 2012, Sabine Pass Liquefaction entered into a construction/term loan facility in an amount up to $3.6 billion (the “2012 Liquefaction Credit Facility”), which was available to Sabine Pass Liquefaction in four tranches solely to fund the Sabine Pass Liquefaction Project costs for Trains 1 and 2, the related debt service reserve account up to an amount equal to six months of scheduled debt service and the return of equity and affiliate subordinated debt funding to Cheniere or its affiliates up to an amount that would result in senior debt being no more than 65% of Cheniere Partners’ total capitalization. Borrowings under the 2012 Liquefaction Credit Facility were based on LIBOR plus 3.50% during construction and 3.75% during operations. Sabine Pass Liquefaction was also required to pay commitment fees on the undrawn amount. The 2012 Liquefaction Credit Facility was
amended and restated with the 2013 Liquefaction Credit Facilities and $100.0 million of outstanding borrowings under the 2012 Liquefaction Credit Facility were repaid in full.
2017 CTPL Term Loan
CTPL has a $400.0 million term loan facility (“2017 CTPL Term Loan”), which is being used to fund modifications to the Creole Trail Pipeline and for general business purposes. The 2017 CTPL Term Loan matures in 2017 when the full amount of the outstanding principal obligations must be repaid. CTPL’s loan may be repaid, in whole or in part, at any time without premium or penalty. As of December 31, 2014, CTPL had borrowed the full amount of $400.0 million available under the 2017 CTPL Term Loan. Borrowings under the 2017 CTPL Term Loan bear interest at a variable rate per annum equal to, at CTPL’s election, LIBOR or the base rate, plus the applicable margin. The applicable margin for LIBOR loans is 3.25%. Interest on LIBOR loans is due and payable at the end of each LIBOR period.
Sabine Pass Liquefaction LC Agreement
In April 2014, Sabine Pass Liquefaction entered into the Sabine Pass Liquefaction LC Agreement that it uses for the issuance of letters of credit for certain working capital requirements related to the Sabine Pass Liquefaction Project. Sabine Pass Liquefaction pays (a) a commitment fee in an amount equal to an annual rate of 0.75% of an amount equal to the unissued portion of letters of credit available pursuant to the Sabine Pass Liquefaction LC Agreement and (b) a letter of credit fee equal to an annual rate of 2.5% of the undrawn portion of all letters of credit issued under the Sabine Pass Liquefaction LC Agreement. If draws are made upon any letters of credit issued under the Sabine Pass Liquefaction LC Agreement, the amount of the draw will be deemed a loan issued to Sabine Pass Liquefaction. Sabine Pass Liquefaction is required to pay the full amount of this loan on or prior to the business day immediately succeeding the deemed issuance of the loan. These loans bear interest at a rate of 2.0% plus the base rate as defined in the Sabine Pass Liquefaction LC Agreement. As of December 31, 2014, Sabine Pass Liquefaction had issued letters of credit in an aggregate amount of $9.5 million and no draws had been made upon any letters of credit issued under the Sabine Pass Liquefaction LC Agreement.
Corpus Christi LNG Terminal
Liquefaction Facilities
In September 2011, we formed Corpus Christi Liquefaction to develop a natural gas liquefaction facility near Corpus Christi, Texas on over 1,000 acres of land that we own or control. As currently contemplated, the Corpus Christi Liquefaction Facilities would be designed for up to three Trains, with expected aggregate nominal production capacity of approximately 13.5 mtpa of LNG, three LNG storage tanks with capacity of approximately 10.1 Bcfe and two docks that can accommodate vessels with nominal capacity of up to 266,000 cubic meters.
On December 30, 2014, the FERC issued an order granting Corpus Christi Liquefaction authorization under Section 3 of the NGA to site, construct and operate Trains 1 through 3. The Sierra Club has requested a rehearing and the FERC has not ruled on this request. In August 2012, Cheniere Marketing filed an application with the DOE to export up to the equivalent of 15 mtpa (approximately 767 Bcf/yr) of domestically produced LNG to FTA and non-FTA countries from the Corpus Christi Liquefaction Project. In October 2012, the DOE granted Cheniere Marketing authority to export up to the equivalent of 15 mtpa (approximately 767 Bcf/yr) of domestically produced LNG to FTA countries from the Corpus Christi Liquefaction Project. Corpus Christi Liquefaction was added as an additional authorization holder to the FTA permit and an additional applicant to the non-FTA application. In addition, the FERC approval requires us to obtain certain additional FERC approvals as construction progresses.
Customers
Corpus Christi Liquefaction has entered into nine fixed price, 20-year SPAs with seven third parties with aggregate annual contract quantities of approximately 8.4 mtpa of LNG. However, the Corpus Christi Liquefaction Project is not yet fully permitted. Under these nine SPAs, the customers will purchase LNG from Corpus Christi Liquefaction for a price consisting of a fixed fee of $3.50 plus 115% of Henry Hub per MMBtu of LNG. In certain circumstances, the customers may elect to cancel or suspend deliveries of LNG cargoes, in which case the customers would still be required to pay the fixed fee with respect to cargoes that are not delivered. A portion of the fixed fee will be subject to annual adjustment for inflation. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA commences upon the start of operations of the specified Train. Each of the SPAs contain certain conditions precedent, including, but not limited to, receiving regulatory approvals, securing necessary financing arrangements and making a final investment decision, which must be satisfied by June 30, 2015 or either party to each SPA may terminate its SPA.
In aggregate, the fixed fee portion to be paid by these customers is approximately $1.5 billion if we make a positive final investment decision with respect to Trains 1 through 3, with the applicable fixed fees starting from the commencement of commercial operations of the applicable Train. These fixed fees equal approximately $550 million, $706 million and $280 million for each of Trains 1 through 3, respectively.
Natural Gas Transportation and Supply
For Corpus Christi Liquefaction’s natural gas feedstock transportation requirements, it has entered into transportation precedent agreements to secure firm pipeline transportation capacity with third-party pipeline companies and Cheniere Corpus Christi Pipeline. Corpus Christi Liquefaction has also entered into enabling agreements with third parties and will continue to enter into such agreements in order to secure natural gas feedstock for the Corpus Christi Liquefaction Project.
Construction
In December 2013, Corpus Christi Liquefaction entered into contracts with Bechtel for the engineering, procurement and construction of Trains and related facilities for the Corpus Christi Liquefaction Project under which Bechtel charges a lump sum for all work performed and generally bears project cost risk unless certain specified events occur, in which case Bechtel may cause Corpus Christi Liquefaction to enter into a change order, or Corpus Christi Liquefaction agrees with Bechtel to a change order. Total expected costs for the three Trains and the related facilities, excluding pipeline facilities, are estimated to be between $11.5 billion and $12.0 billion, before financing costs, including an estimate for owner’s costs and contingencies.
Pipeline Facilities
On December 30, 2014, the FERC issued a certificate of public convenience and necessity under Section 7(c) of the NGA authorizing Cheniere Corpus Christi Pipeline to construct and operate the Corpus Christi Pipeline. The Corpus Christi Pipeline is designed to transport 2.25 Bcf/d of feed and fuel gas required by the Corpus Christi Liquefaction Project from the existing natural gas pipeline grid.
Final Investment Decision
We will contemplate making a final investment decision to commence construction of the Corpus Christi Liquefaction Project based upon, among other things, entering into acceptable commercial arrangements, receiving regulatory authorizations and obtaining adequate financing to construct the facility.
Capital Resources
We expect to finance the construction costs of the Corpus Christi Liquefaction Project and other corporate activities from one or more of the following: project financing, offerings by us or our subsidiaries of debt or equity and operating cash flow.
Convertible Notes
In January 2015, we entered into a note purchase agreement with EIG, under which EIG will purchase $1.5 billion of convertible notes to be issued by a wholly owned direct subsidiary of Cheniere. The investment is scheduled to close once we
reach a positive final investment decision on the Corpus Christi Liquefaction Project. The net proceeds would be used to fund a portion of the costs of developing, constructing and placing into service the Corpus Christi Liquefaction Project.
Credit Facilities
In December 2014, we entered into an agreement with 19 financial institutions to act as Joint Lead Arrangers to assist in the structuring and arranging of up to $11.5 billion of debt facilities. The proceeds will be used to pay for a portion of the costs of developing, constructing and placing into service the Corpus Christi Liquefaction Project. We have entered into contingent interest rate derivatives to hedge approximately 46% of the variable interest rate exposure of these projected outstanding borrowings, calculated on a weighted average basis in comparison to its anticipated draw of principal. We anticipate that we will be required to hedge not less than 65% of this variable interest rate exposure.
LNG and Natural Gas Marketing Business
Our wholly owned subsidiary, Cheniere Marketing, is engaged in the LNG and natural gas marketing business and is seeking to develop a portfolio of long-term, short-term and spot LNG purchase and sale agreements. Cheniere Marketing has purchased, transported and unloaded commercial LNG cargoes into the Sabine Pass LNG terminal and has used trading strategies intended to maximize margins on these cargoes. Cheniere Marketing, or one of its wholly owned subsidiaries, has secured the following rights and obligations to support its business:
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the right to deliver cargoes to the Sabine Pass LNG terminal during the construction of the Sabine Pass Liquefaction Project in exchange for payment of 80% of the expected gross margin from each cargo to Cheniere Investments;
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pursuant to an amended and restated SPA with Sabine Pass Liquefaction, the right to purchase, at Cheniere Marketing’s option, any LNG produced by Sabine Pass Liquefaction in excess of that required for other customers at a price of 115% of Henry Hub plus $3.00 per MMBtu of LNG;
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pursuant to SPAs with Corpus Christi Liquefaction, the right to purchase, at Cheniere Marketing’s option, any LNG produced by Corpus Christi Liquefaction not required for other customers; and
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three LNG vessel time charters with subsidiaries of two ship owners, Dynagas and Teekay. The annual payments for the vessel charters will be approximately $92 million. The charters have an initial term of 5 years with the option to renew with Dynagas for a 2-year extension with similar terms as the initial term. Cheniere Marketing expects to receive delivery of the vessel from Dynagas in June 2015 and the vessels from Teekay in January 2016 and June 2016.
In addition, Cheniere Marketing has sold LNG cargoes to be delivered to multiple counterparties between 2016 and 2018, with delivery obligations conditioned on the performance of the Sabine Pass Liquefaction Project. The cargoes have been sold with a portfolio of delivery points, either on an FOB basis, delivered to the counterparty at the Sabine Pass LNG terminal, or a DAT basis, delivered to the counterparty’s LNG receiving terminal. Cheniere Marketing has chartered LNG vessels, as described above, to be utilized in DAT transactions. In addition, a wholly owned subsidiary of Cheniere Marketing has entered into a long-term agreement to sell LNG cargoes on a DAT basis, with delivery obligations conditioned on Corpus Christi Liquefaction achieving certain milestones, including a final investment decision. The agreement is also conditioned upon the buyer achieving its own milestones, including reaching a final investment decision related to certain projects and obtaining related financing.
Corporate and Other Activities
We are required to maintain corporate general and administrative functions to serve our business activities described above. We are also in various stages of developing other projects, which, among other things, will require acceptable commercial and financing arrangements before we make a final investment decision.
Sources and Uses of Cash
The following table summarizes (in thousands) the sources and uses of our cash and cash equivalents for the years ended December 31, 2014, 2013 and 2012. The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussion of these items follows the table.
Proceeds from Issuances of Long-Term Debt, Debt Issuance and Deferred Financing Costs and Repayment of Long-Term Debt
In May 2014, Sabine Pass Liquefaction issued the 2024 Sabine Pass Liquefaction Senior Notes and the Additional 2023 Sabine Pass Liquefaction Senior Notes for total net proceeds of approximately $2.5 billion. Additionally, in November 2014, we issued $1.0 billion of the 2021 Convertible Unsecured Notes. Debt issuance and deferred financing costs in the year ended December 31, 2014, primarily relate to up-front fees paid upon the closing of these offerings.
In February 2013 and April 2013, Sabine Pass Liquefaction issued an aggregate principal amount of $2.0 billion, before premium, of the 2021 Sabine Pass Liquefaction Senior Notes. In April 2013, Sabine Pass Liquefaction also issued $1.0 billion of the 2023 Sabine Pass Liquefaction Senior Notes. In November 2013, Sabine Pass Liquefaction also issued $1.0 billion of the 2022 Sabine Pass Liquefaction Senior Notes. Net proceeds from those offerings were used to pay a portion of the capital costs incurred in connection with the construction of the Sabine Pass Liquefaction Project. In May 2013, CTPL entered into the $400.0 million 2017 CTPL Term Loan, which is being used to fund modifications to the Creole Trail Pipeline and for general business purposes. In June 2013, Sabine Pass Liquefaction borrowed $100.0 million under the 2013 Liquefaction Credit Facilities. Debt issuance and deferred financing costs in the year ended December 31, 2013 primarily relate to up-front fees paid by Sabine Pass Liquefaction upon the closing of the 2013 Liquefaction Credit Facilities and the notes issued by Sabine Pass Liquefaction during the year.
In October 2012, Sabine Pass LNG issued $420.0 million of the 2020 Notes. In July 2012, Sabine Pass Liquefaction entered into the 2012 Liquefaction Credit Facility with a syndicate of lenders. Sabine Pass Liquefaction borrowed $100.0 million under
the 2012 Liquefaction Credit Facility in August 2012 after meeting the required conditions precedent to the initial advance. Debt issuance costs primarily relate to $212.8 million paid by Sabine Pass Liquefaction upon the closing of the 2012 Liquefaction Credit Facility.
During the year ended December 31, 2014, Sabine Pass Liquefaction repaid its $177.0 million of borrowings under the 2013 Liquefaction Credit Facilities upon the issuance of the Additional 2023 Sabine Pass Liquefaction Senior Notes and the 2024 Sabine Pass Liquefaction Senior Notes. During the year ended December 31, 2013, the 2012 Liquefaction Credit Facility was amended and restated with the 2013 Liquefaction Credit Facilities and the $100.0 million of outstanding borrowings under the 2012 Liquefaction Credit Facility were repaid in full.
In the year ended December 31, 2012, we repaid $1,326.5 million of debt. In January 2012, we used a portion of the net proceeds from the public offering of Cheniere common stock in December 2011 to repay in full the loans outstanding under a $400.0 million credit agreement entered into in 2007. In June 2012, we used a portion of the net proceeds from the public offering of Cheniere common stock in March 2012 to repay in full the $250.0 million credit agreement entered into in August 2008 (the “2008 Loans”). In August 2012, we used a portion of the net proceeds from the public offering of Cheniere common stock in July 2012 to repay in full our $325.0 million convertible senior unsecured notes due August 2012. During the fourth quarter of 2012, Sabine Pass LNG repurchased its $550.0 million 7.25% Senior Secured Notes due 2013. Funds used for the repurchase included proceeds received from the 2020 Sabine Pass LNG Senior Notes that were issued in October 2012 and from an equity contribution from Cheniere Partners.
Use of Restricted Cash and Cash Equivalents for the Acquisition of Property, Plant and Equipment and Property, Plant and Equipment, net
During the years ended December 31, 2014, 2013 and 2012, we used $2,684.4 million, $3,129.7 million and $1,587.5 million, respectively, of restricted cash and cash equivalents for investing activities to primarily fund $2,829.6 million, $3,114.3 million and $1,118.0 million, respectively, of construction costs for Trains 1 through 4 of the Sabine Pass Liquefaction Project. Trains 1 and 2 and Trains 3 and 4 of the Sabine Pass Liquefaction Project satisfied the criteria for capitalization in June 2012 and May 2013, respectively. Accordingly, costs associated with the construction of Trains 1 through 4 of the Sabine Pass Liquefaction Project have been recorded as construction-in-process since those dates.
Proceeds from Sale of Common Units by Cheniere Partners
The proceeds from the sale of common units of Cheniere Partners in the year ended December 31, 2013 primarily related to a February 2013 common unit purchase agreement with institutional investors to sell 17.6 million common units for net proceeds, after deducting expenses, of approximately $365 million. Cheniere Partners used the proceeds from this offering to purchase 100% of the equity interests in Cheniere Pipeline GP Interests, LLC held by Cheniere Pipeline Company, and the limited partner interest in CTPL held by Grand Cheniere Pipeline, LLC.
In September 2012, Cheniere Partners sold 8.0 million common units in an underwritten public offering at a price of $25.07 per common unit for net cash proceeds of $194.0 million. In addition, during the year ended December 31, 2012, Cheniere Partners sold 0.5 million common units for net cash proceeds of $11.1 million under its at-the-market program initiated in January 2011.
Proceeds from Sale of Common Shares by Cheniere Holdings
The proceeds from the sale of Cheniere Holdings’ common shares in the year ended December 31, 2014 related to the public offering of 10.1 million of Cheniere Holdings’ common shares for net proceeds of approximately $229 million, after deducting offering expenses. The net proceeds were used to redeem from us the same number of Cheniere Holdings’ common shares, which reduced our ownership of Cheniere Holdings’ common shares from 84.5% to 80.1%.
In December 2013, Cheniere Holdings completed its initial public offering of 36.0 million common shares at $20.00 per common share. Cheniere Holdings was formed by us to hold our Cheniere Partners limited partner interests. We ultimately received all of the $665.0 million of net proceeds from the Cheniere Holdings Offering from the repayment of Cheniere Holdings’ intercompany indebtedness and payables owed to us and through a distribution by Cheniere Holdings to us.
Proceeds from Sale of Common Stock, Net
In March 2012, we sold 24.2 million shares of Cheniere common stock in an underwritten public offering for net cash proceeds of $351.9 million. In June 2012, we used a portion of the net proceeds from this offering to repay in full the 2008 Loans. In May 2012, we sold 31.0 million shares of Cheniere common stock pursuant to a stock purchase agreement for net proceeds of $468.1 million, which was used, along with cash on hand, to purchase $500 million of Class B units from Cheniere Partners. In July 2012, we sold 28.0 million shares of Cheniere common stock in an underwritten public offering for net cash proceeds of $380.3 million. We used a portion of the net proceeds from the offering to repay our $325.0 million convertible senior unsecured notes due August 2012, and the remaining amount was used for capital expenditures on the Creole Trail Pipeline and general corporate purposes.
Proceeds from Sale of Class B Units by Cheniere Partners
During the year ended December 31, 2012, Cheniere Partners issued and sold an aggregate of 100 million Class B units to Blackstone at a price of $15.00 per Class B unit, resulting in total net proceeds of $1,387.3 million.
Investment in Restricted Cash and Cash Equivalents
In the year ended December 31, 2014, we invested $2,224.2 million in restricted cash and cash equivalents primarily related to the net proceeds from the notes issued by Sabine Pass Liquefaction during the year. In the year ended December 31, 2013, we invested $4,083.7 million in restricted cash and cash equivalents related to the net proceeds from the 2017 CTPL Term Loan, 2013 Liquefaction Credit Facilities and the notes issued by Sabine Pass Liquefaction during the year.
Distributions and Dividends to Non-controlling Interest
During the years ended December 31, 2014, 2013 and 2012, Cheniere Partners and Cheniere Holdings, collectively, made distributions and dividends of $79.5 million, $69.2 million and $36.3 million, respectively, to non-affiliated common unitholders and common shareholders.
Payments Related to Tax Withholdings for Share-based Compensation
During the years ended December 31, 2014, 2013 and 2012, we used $112.3 million, $136.4 million and $20.4 million, respectively, of cash and cash equivalents to purchase restricted stock that was returned to us by employees to cover taxes related to their restricted stock that vested during such periods. The increased amounts in 2014 and 2013 primarily resulted from the vesting of awards under the long-term commercial bonus pools related to Trains 1 through 4 of the Sabine Pass Liquefaction Project.
Operating Cash Flow
During the years ended December 31, 2014, 2013 and 2012, we used $124.1 million, $52.4 million and $107.8 million, respectively, of cash in operating activities. The increase in operating cash outflows in 2014 compared to 2013 primarily related to increased cash outflows related to the settlement of interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the 2013 Liquefaction Credit Facilities and increased general and administrative costs resulting from an increased number of employees and professional fees. The decrease in operating cash outflows in 2013 compared to 2012 primarily resulted from decreased interest expense in the year ended December 31, 2013 as a result of the capitalization of interest on Sabine Pass Liquefaction’s debt, the reduction of our indebtedness outstanding in 2012 and the purchase of a royalty from Crest Energy in March 2012.
Investment in Cheniere Partners
In the year ended December 31, 2013, we invested $11.1 million in Cheniere Partners related to the purchase of general partner units. In the year ended December 31, 2012, we invested $545.1 million in Cheniere Partners related to the purchase of Class B units and general partner units.
Issuance of Common Stock
During the years ended December 31, 2014, 2013 and 2012, we issued 0.5 million, 18.9 million and 10.3 million shares, respectively, of restricted stock to new and existing employees.
Contractual Obligations
We are committed to make cash payments in the future pursuant to certain of our contracts. The following table summarizes certain contractual obligations in place as of December 31, 2014 (in thousands):
(1)
Construction and purchase obligations primarily relate to the EPC Contract (Trains 1 and 2) and the EPC Contract (Trains 3 and 4). A discussion of these obligations can be found at Note 14-Commitments and Contingencies of our Notes to Consolidated Financial Statements.
(2)
Based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2014. See Note 9-Long-Term Debt of our Notes to Consolidated Financial Statements.
(3)
Operating lease obligations primarily relate to LNG vessel time charters, land site and tug leases related to the Sabine Pass LNG terminal and corporate office leases. Minimum lease payments have not been reduced by a minimum sublease rental of $16.3 million due in the future under non-cancelable subleases. A discussion of these obligations and sublease rental payments can be found in Note 13-Leases of our Notes to Consolidated Financial Statements.
In addition, in the ordinary course of business, we maintain letters of credit and have certain cash and cash equivalents restricted in support of certain performance obligations of our subsidiaries. Restricted cash and cash equivalents totaled $1,032.5 million at December 31, 2014. For more information, see Note 3-Restricted Cash and Cash Equivalents of our Notes to Consolidated Financial Statements.
Results of Operations
2014 vs. 2013
Our consolidated net loss attributable to common stockholders was $547.9 million, or $2.44 per share (basic and diluted), in the year ended December 31, 2014 compared to a net loss attributable to common stockholders of $507.9 million, or $2.32 per share (basic and diluted), in the year ended December 31, 2013. This $40.0 million increase in net loss was primarily a result of decreased derivative gain, net, which was partially offset by increased net loss attributable to non-controlling interest, decreased general and administrative expense (“G&A Expense”) and decreased loss on early extinguishment of debt.
Derivative gain (loss), net decreased $201.5 million in the year ended December 31, 2014, as compared to the year ended December 31, 2013, primarily as a result of a decrease in long-term LIBOR during the year ended December 31, 2014, as compared to an increase in long-term LIBOR during the year ended December 31, 2013, and the early settlement of interest rate swaps in connection with the early extinguishment of a portion of the 2013 Liquefaction Credit Facilities in May 2014. Net loss attributable to non-controlling interest increased $93.1 million in the year ended December 31, 2014, as compared to the year ended December 31, 2013, primarily as a result of increased net loss recorded by Cheniere Partners and the increased portion of equity ownership in Cheniere Partners not attributable to us resulting from the Cheniere Partners’ common unit offering in the first quarter of 2013 and Cheniere Holdings’ initial public offering of 36.0 million common shares completed in December 2013. G&A Expense decreased $60.8 million in the year ended December 31, 2014, as compared to the year ended December 31, 2013, primarily as a result of accelerated expense recognition in the year ended December 31, 2013 for bonus plan awards relating to the Sabine Pass Liquefaction Project. Loss on early extinguishment of debt decreased $17.2 million in the year ended December 31, 2014, as compared to the year ended December 31, 2013, due to the write-off of debt issuance costs in connection with the early extinguishment of $2.1 billion of commitments under the 2013 Liquefaction Credit Facilities in May 2014, as compared to the write-off of debt issuance costs and deferred commitment fees in connection with the early extinguishment of a portion of the commitments under the 2012 Liquefaction Credit Facility in April 2013 and the 2013 Liquefaction Credit Facilities in November 2013.
There was no significant change to interest expense, net in the year ended December 31, 2014, as compared to the year ended December 31, 2013, primarily as a result of our capitalization of interest costs incurred which were directly related to the construction of the first four Trains of the Sabine Pass Liquefaction Project. For the years ended December 31, 2014 and 2013, we incurred $587.0 million and $414.0 million of total interest cost, respectively, of which we capitalized and deferred $405.8 million and $235.6 million, respectively.
2013 vs. 2012
Our consolidated net loss was $507.9 million, or $2.32 per share (basic and diluted), in 2013 compared to a net loss of $332.8 million, or $1.83 per share (basic and diluted), in 2012. This $175.1 million increase in net loss was primarily a result of increased G&A Expense, loss on early extinguishment of debt and increased LNG terminal operating expense, which was partially offset by increased derivative gain and decreased interest expense, net.
G&A Expense increased $232.4 million in 2013 as compared to 2012 primarily as a result of the timing of awards under bonus plans relating to Trains 1 through 4 of the Sabine Pass Liquefaction Project. Loss on early extinguishment of debt increased $73.9 million in 2013 as compared to 2012 primarily as a result of issuances of the Sabine Pass Liquefaction Senior Notes that resulted in the termination of a portion of the commitments under the 2012 Liquefaction Credit Facility and the 2013 Liquefaction Credit Facilities. LNG terminal operating expense increased $32.1 million in 2013 as compared to 2012 primarily as a result of the loss incurred to purchase LNG to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal, increased LNG terminal maintenance and repair costs and increased fuel costs at the Sabine Pass LNG terminal. We anticipate continuing to incur a similar amount of terminal use agreement maintenance expense until minimum inventory quantities are maintained, which we expect to occur in 2015. Derivative gain increased $83.4 million in 2013 as compared to 2012 primarily as a result of the change in fair value of Sabine Pass Liquefaction’s interest rate derivatives to hedge the exposure to volatility in a portion of the floating-rate interest payments under the 2013 Liquefaction Credit Facilities. Interest expense, net decreased $22.4 million in 2013 as compared to 2012 primarily as a result of reduction of our indebtedness outstanding in 2012 and the capitalization of interest on Sabine Pass Liquefaction’s debt. Development expense in 2013 primarily related to the development of Trains 5 and 6 of the Sabine Pass Liquefaction Project and the Corpus Christi Liquefaction Project, while development expense in 2012 primarily related to Trains 1 through 6 of the Sabine Pass Liquefaction Project.
Off-Balance Sheet Arrangements
As of December 31, 2014, we had no “off-balance sheet arrangements” that may have a current or future material effect on our consolidated financial position or results of operations.
Summary of Critical Accounting Estimates
The preparation of Consolidated Financial Statements in conformity with generally accepted accounting principles in the United States (“GAAP”) requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to the value of properties, plant and equipment, goodwill, asset retirement obligations (“AROs”), income taxes, share-based compensation and fair values. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve significant judgment.
Fair Value
When necessary or required by GAAP, we estimate fair value for derivatives, long-lived assets for impairment testing, reporting units for goodwill impairment testing, initial measurements of AROs, and financial instruments that require fair-value disclosure, including cash and cash equivalents, restricted cash and cash equivalents, accounts receivable, accounts payable and debt. When we are required to measure fair value and there is not a market-observable price for the asset or liability or for a similar asset or liability, we use the cost, income, or market valuation approaches depending on the quality of information available to support management’s assumptions. The cost approach is based on management’s best estimate of the current asset replacement cost. The income approach is based on management’s best assumptions regarding expectations of projected cash flows, and discounts the expected cash flows using a commensurate risk-adjusted discount rate. The market approach is based on management’s best assumptions regarding prices and other relevant information from market transactions involving comparable assets. Such evaluations involve significant judgment and the results are based on expected future events or conditions, such as sales prices, estimates of future LNG production, development, construction and operating costs and the timing thereof, future net cash flows, economic and regulatory climates and other factors, most of which are often outside of management’s control. However, assumptions used reflect a market participant’s view of long-term prices, costs and other factors, and are consistent with assumptions used in our business plans and investment decisions.
Derivative Instruments
All derivative instruments, other than those that satisfy specific exceptions, are recorded at fair value. We record changes in the fair value of our derivative positions based on the value for which the derivative instrument could be exchanged between willing parties. If market quotes are not available to estimate fair value, management’s best estimate of fair value is based on the quoted market price of derivatives with similar characteristics or determined through industry-standard valuation techniques.
Our derivative instruments consist of financial natural gas derivative contracts transacted in an over-the-counter market, index-based physical natural gas contracts and interest rate swaps. Valuation of our financial natural gas derivative contracts is determined using observable commodity price curves and other relevant data. Valuation of our index-based physical natural gas contracts is developed through the use of internal models which are impacted by inputs that are unobservable in the marketplace, market transactions and other relevant data. We value our interest rate swaps using observable inputs including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data.
Gains and losses on derivative instruments are recognized currently in earnings. The ultimate fair value of our derivative instruments is uncertain, and we believe that it is reasonably possible that a change in the estimated fair value could occur in the near future as commodity prices and interest rates change.
Goodwill
At December 31, 2014, we had $76.8 million of goodwill associated with our LNG terminal reporting unit. Goodwill represents the excess of cost over fair value of the assets of businesses acquired.
We test goodwill for impairment annually during the fourth quarter, or more frequently as circumstances dictate. The first step in assessing whether an impairment of goodwill is necessary is an optional qualitative assessment to determine the likelihood of whether the fair value of the reporting unit is greater than its carrying amount. If we conclude that it is more likely than not that the fair value of the reporting unit exceeds the related carrying amount, further testing is not necessary. If the qualitative assessment is not performed or indicates that it is more likely than not that the fair value of the reporting unit is less than its carrying amount, we compare the estimated fair value of the reporting unit to which goodwill is assigned to the carrying amount of the associated net assets, including goodwill. If the carrying value of the reporting unit exceeds its fair value, we perform the second step of the goodwill impairment test to measure the amount of goodwill impairment loss to be recorded, as necessary. The second step compares the implied fair value of the reporting unit’s goodwill to the carrying value, if any, of that goodwill. We determine the implied fair value of the goodwill in the same manner as determining the amount of goodwill to be recognized in a business combination.
Because quoted market prices for our reporting units are not available, we must apply judgment in determining the estimated fair value of our reporting units for purposes of performing goodwill impairment tests, when such tests are necessary. Management uses all available information to make these fair value estimates, including the present values of expected future cash flows using discount rates commensurate with the risks associated with the assets, future LNG liquefaction, operating costs and depreciation. These estimates are based on current conditions and historical experience and we rely on projections of future operating performance. Projections of future operating results and cash flows may vary significantly from results. Management reviews its estimates of cash flows on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment.
A lower fair value estimate in the future for our LNG terminal reporting unit could result in impairment of goodwill. Factors that could trigger a lower fair value estimate include significant negative industry or economic trends, cost increases, disruptions to our business and regulatory or political environment changes or other unanticipated events.
Impairment of Long-Lived Assets
A long-lived asset, including an intangible asset, is evaluated for potential impairment whenever events or changes in circumstances indicate that its carrying value may not be recoverable. A long-lived asset is not recoverable when its carrying value exceeds the sum of its future net undiscounted cash flows. Impairment, if any, is measured as the excess of an asset’s carrying amount over its estimated fair value. We use a variety of fair value measurement techniques when market information for the same or similar assets does not exist. Projections of future operating results and cash flows may vary significantly from results. Management reviews its estimates of cash flows on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment.
Share-Based Compensation
The assumptions used in calculating the fair value of share-based payment awards represent our best estimates, but these estimates involve inherent uncertainties and the application of management’s judgment. As a result, if factors change and we use different assumptions, our share-based compensation expense could be materially different in the future.
We recognize the cost for our share-based payment awards based on market conditions using Monte Carlo simulations. To calculate the Monte Carlo simulation, we must consider certain variables including volatility factors and dividend yield. Volatility factors are based on the historical and implied volatilities of Cheniere’s common stock over the expected lives as estimated on the grant date. The dividend yield is the expected annual dividend yield over the expected life, expressed as a percentage of the stock price on the grant date.
The fair value of stock options granted to employees is determined using a Black-Scholes valuation model. The risk-free rate is based on the U.S. Treasury securities yield curve in effect at the time of grant. The expected term (estimated period of time outstanding) of stock options granted is based on the “simplified” method of estimating the expected term for “plain vanilla” stock options, and varies based on the vesting period and contractual term of the stock option. Expected volatility for stock options granted is based on an equally weighted average of the implied volatility of exchange traded stock options on our common stock expiring more than one year from the measurement date, and historical volatility of our common stock for a period equal to the stock option’s expected life.
In addition, we are required to estimate the expected forfeiture rate for all of our share-based payment awards and only recognize expense for those shares expected to vest. We consider many factors when estimating expected forfeitures, including types of awards, employee class and historical experience. If our actual forfeiture rate is materially different from our estimate, future share-based compensation expense could be significantly different from what we have recorded in the current period.
See Note 2-Summary of Significant Accounting Policies and Note 11-Share-Based Compensation of our Notes to Consolidated Financial Statements for additional information regarding our share-based compensation.
Income Taxes
Provisions for income taxes are based on taxes payable or refundable for the current year and deferred taxes on temporary differences between the tax basis of assets and liabilities and their reported amounts in the Consolidated Financial Statements. Deferred tax assets and liabilities are included in the Consolidated Financial Statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the current period’s provision for income taxes. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized. This assessment requires significant judgment and is based upon our assessment of our ability to generate future taxable income among other factors.
Recent Accounting Standards
In May 2014, the Financial Accounting Standards Board (“FASB”) amended its guidance on revenue recognition. The core principle of this amendment is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This guidance is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, with earlier adoption not permitted. This guidance can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. We are currently evaluating the impact of the provisions of this guidance on our consolidated financial position, results of operations and cash flows.
In June 2014, the FASB issued guidance that a performance target in a share-based payment that affects vesting and that could be achieved after the requisite service period should be accounted for as a performance condition. As a result, the target is not reflected in the estimation of the award’s grant date fair value and compensation cost for such an award would be recognized over the required service period, if it is probable that the performance condition will be achieved. This guidance is effective for annual reporting periods beginning after December 15, 2015, with early adoption permitted. We adopted this guidance in the quarterly period ended June 30, 2014. The adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.
In August 2014, the FASB issued authoritative guidance that requires an entity’s management to evaluate, for each reporting period, whether there are conditions and events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the financial statements are issued. Additional disclosures are required if management concludes that conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. This guidance is effective for annual reporting periods ending after December 15, 2016, and for annual periods and interim periods thereafter, with earlier adoption permitted. The adoption of this guidance is not expected to have an impact on our consolidated financial position, results of operations or cash flows.
ITEM 7A.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Cash Investments
We have cash investments that we manage based on internal investment guidelines that emphasize liquidity and preservation of capital. Such cash investments are stated at historical cost, which approximates fair market value on our Consolidated Balance Sheets.
Marketing and Trading Commodity Price Risk
We have entered into:
•
commodity derivatives to hedge the exposure to variability in expected future cash flows attributable to the future sale of our LNG inventory (“LNG Inventory Derivatives”);
•
commodity derivatives to hedge the exposure to price risk attributable to future purchases of natural gas to be utilized as fuel to operate the Sabine Pass LNG terminal (“Fuel Derivatives”); and
•
commodity derivatives consisting of natural gas purchase agreements to secure natural gas feedstock for the Sabine Pass Liquefaction Project (“Term Gas Supply Derivatives”).
We use one-day value at risk (“VaR”) with a 95% confidence interval and other methodologies for market risk measurement and control purposes of our LNG Inventory Derivatives and Fuel Derivatives. The VaR is calculated using the Monte Carlo simulation method. As of December 31, 2014, our commodity derivatives that are sensitive to changes in natural gas prices had a VaR of $48,000.
In order to test the sensitivity of the fair value of the Term Gas Supply Derivatives to changes in underlying commodity prices, management modeled a 10% change in the Henry Hub price for natural gas. As of December 31, 2014, we estimated the fair value of our Term Gas Supply Derivatives to be $0.3 million. Based on actual derivative contractual volumes, a 10% increase or decrease in underlying commodity prices would have resulted in a change in the fair value of the Term Gas Supply Derivatives of $0.4 million as of December 31, 2014.
Interest Rate Risk
We have entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the 2013 Liquefaction Credit Facilities (“Interest Rate Derivatives”). In order to test the sensitivity of the fair value of the Interest Rate Derivatives to changes in interest rates, management modeled a 10% change in the forward 1-month LIBOR curve across the full 7-year term of the Interest Rate Derivatives. This 10% change in interest rates would have resulted in a change in the fair value of the Interest Rate Derivatives of $16.5 million as of December 31, 2014.
ITEM 8.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
CHENIERE ENERGY, INC. AND SUBSIDIARIES
Management’s Reports to the Stockholders of Cheniere Energy, Inc.
Reports of Independent Registered Public Accounting Firm-KPMG LLP
Report of Independent Registered Public Accounting Firm-Ernst & Young LLP
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Loss
Consolidated Statements of Stockholders’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Supplemental Information to Consolidated Financial Statements-Quarterly Financial Data
MANAGEMENT’S REPORTS TO THE STOCKHOLDERS OF CHENIERE ENERGY, INC.
Management’s Report on Internal Control Over Financial Reporting
As management, we are responsible for establishing and maintaining adequate internal control over financial reporting for Cheniere Energy, Inc. and its subsidiaries (“Cheniere”). In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, we have conducted an assessment, including testing using the criteria in Internal Control-Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Cheniere’s system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and, even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation.
Based on our assessment, we have concluded that Cheniere maintained effective internal control over financial reporting as of December 31, 2014, based on criteria in Internal Control-Integrated Framework (1992) issued by the COSO.
Cheniere’s independent registered public accounting firm, KPMG LLP, have issued an audit report on Cheniere’s internal control over financial reporting as of December 31, 2014, which is contained in this Form 10-K.
Management’s Certifications
The certifications of Cheniere’s Chief Executive Officer and Chief Financial Officer required by the Sarbanes-Oxley Act of 2002 have been included as Exhibits 31 and 32 in Cheniere’s Form 10-K.
CHENIERE ENERGY, INC.
By:
/s/ Charif Souki
By:
/s/ Michael J. Wortley
Charif Souki
Chief Executive Officer and President
(Principal Executive Officer)
Michael J. Wortley
Senior Vice President
and Chief Financial Officer
(Principal Financial Officer)
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Cheniere Energy, Inc.:
We have audited the accompanying consolidated balance sheet of Cheniere Energy, Inc. and subsidiaries (the Company) as of December 31, 2014, and the related consolidated statements of operations, comprehensive loss, stockholders’ equity, and cash flows for the year then ended. In connection with our audit of the consolidated financial statements, we also have audited financial statement schedule (Schedule I) for the year ended December 31, 2014. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Cheniere Energy, Inc. and subsidiaries as of December 31, 2014, and the results of their operations and their cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule for the year ended December 31, 2014, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Cheniere Energy, Inc.’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 19, 2015, expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ KPMG LLP
KPMG LLP
Houston, Texas
February 19, 2015
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Cheniere Energy, Inc.:
We have audited Cheniere Energy, Inc.’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Cheniere Energy, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Cheniere Energy, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Cheniere Energy, Inc. and subsidiaries as of December 31, 2014, and the related consolidated statements of operations, comprehensive loss, stockholders’ equity, and cash flows for the year then ended, and our report dated February 19, 2015 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
KPMG LLP
Houston, Texas
February 19, 2015
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of
Cheniere Energy, Inc.
We have audited the accompanying consolidated balance sheet of Cheniere Energy, Inc. and subsidiaries as of December 31, 2013, and the related consolidated statements of operations, comprehensive loss, stockholders' equity, and cash flows for each of the two years in the period ended December 31, 2013. Our audits also included the financial statement schedule for each of the two years in the period ended December 31, 2013 listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Cheniere Energy, Inc. and subsidiaries at December 31, 2013, and the consolidated results of their operations and their cash flows for each of the two years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ ERNST & YOUNG LLP
Ernst & Young LLP
Houston, Texas
February 21, 2014
CHENIERE ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
The accompanying notes are an integral part of these consolidated financial statements.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
The accompanying notes are an integral part of these consolidated financial statements.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1-ORGANIZATION AND NATURE OF OPERATIONS
Cheniere Energy, Inc. (NYSE MKT: LNG), a Delaware corporation, is a Houston-based energy company primarily engaged in LNG-related businesses. We own and operate the Sabine Pass LNG terminal in Louisiana through our ownership interest in and management agreements with Cheniere Energy Partners, L.P. (“Cheniere Partners”) (NYSE MKT: CQP), which is a publicly traded limited partnership that we created in 2007. We own 100% of the general partner interest in Cheniere Partners and 80.1% of Cheniere Energy Partners LP Holdings, LLC (“Cheniere Holdings”) (NYSE MKT: CQH), which is a publicly traded limited liability company that we created in 2013 that owns a 55.9% limited partner interest in Cheniere Partners.
The Sabine Pass LNG terminal is located on the Sabine Pass deepwater shipping channel less than four miles from the Gulf Coast. The Sabine Pass LNG terminal has operational regasification facilities owned by Cheniere Partners’ wholly owned subsidiary, Sabine Pass LNG, L.P. (“Sabine Pass LNG”), that includes existing infrastructure of five LNG storage tanks with capacity of approximately 16.9 Bcfe, two docks that can accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. Cheniere Partners is developing and constructing natural gas liquefaction facilities (the “Sabine Pass Liquefaction Project”) at the Sabine Pass LNG terminal adjacent to the existing regasification facilities through a wholly owned subsidiary, Sabine Pass Liquefaction, LLC (“Sabine Pass Liquefaction”). Cheniere Partners plans to construct up to six Trains, which are in various stages of development. Each Train is expected to have a nominal production capacity of approximately 4.5 mtpa of LNG. Cheniere Partners also owns the 94-mile Creole Trail Pipeline through a wholly owned subsidiary, Cheniere Creole Trail Pipeline, L.P. (“CTPL”), which interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines.
We are developing a second natural gas liquefaction and export facility and pipeline facility near Corpus Christi, Texas (the “Corpus Christi Liquefaction Project”) through wholly owned subsidiaries Corpus Christi Liquefaction, LLC (“Corpus Christi Liquefaction”) and Cheniere Corpus Christi Pipeline, L.P. (“Cheniere Corpus Christi Pipeline”), respectively. As currently contemplated, the Corpus Christi LNG terminal would be designed for up to three Trains, with expected aggregate nominal production capacity of approximately 13.5 mtpa of LNG, three LNG storage tanks with capacity of approximately 10.1 Bcfe and two docks that can accommodate vessels with nominal capacity of up to 266,000 cubic meters. The Corpus Christi Liquefaction Project also would include a 23-mile pipeline that would interconnect the Corpus Christi LNG terminal with several interstate and intrastate natural gas pipelines (“Corpus Christi Pipeline”).
One of our subsidiaries, Cheniere Marketing, LLC (“Cheniere Marketing”), is engaged in LNG and natural gas marketing business activities and is seeking to develop a portfolio of long-term, short-term and spot SPAs. Cheniere Marketing has entered into SPAs with Sabine Pass Liquefaction and Corpus Christi Liquefaction to purchase LNG produced by the Sabine Pass Liquefaction Project and the Corpus Christi Liquefaction Project.
We are also in various stages of developing other projects, which, among other things, will require acceptable commercial and financing arrangements before we make a final investment decision.
Unless the context requires otherwise, references to the “Company,” “Cheniere,” “we,” “us” and “our” refer to Cheniere Energy, Inc. and its consolidated subsidiaries, including Cheniere Partners and Cheniere Holdings.
NOTE 2-SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
Our Consolidated Financial Statements were prepared in accordance with generally accepted accounting principles in the United States (“GAAP”). The Consolidated Financial Statements include the accounts of Cheniere Energy, Inc. and its majority owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. The Consolidated Financial Statements include the accounts of Cheniere and entities in which it holds a controlling interest. As a result, the Consolidated Financial Statements include the accounts of Cheniere Holdings and Cheniere Partners and its wholly owned subsidiaries. Investments in non-controlled entities, over which Cheniere has the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method. In applying the equity method of accounting, the investments are initially recognized at cost, and subsequently adjusted for the Company’s proportionate share of earnings, losses and distributions. Other investments are carried at original cost. Investments accounted for using the equity method and cost method are reported as a component of other assets.
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
Certain reclassifications have been made to conform prior period information to the current presentation. The reclassifications had no effect on our overall consolidated financial position, results of operations or cash flows.
Use of Estimates
The preparation of Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to the value of property, plant and equipment, goodwill, collectability of accounts receivable, derivative instruments, asset retirement obligations (“AROs”), income taxes including valuation allowances for net deferred tax assets, share-based compensation and fair value measurements. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.
Fair Value
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation techniques used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Hierarchy Level 3 inputs are inputs that are not observable in the market.
In determining fair value, we use observable market data when available, or models that incorporate observable market data. In addition to market information, we incorporate transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value. We maximize the use of observable inputs and minimize our use of unobservable inputs in arriving at fair value estimates.
Recurring fair-value measurements are performed for commodity derivatives and interest rate derivatives as disclosed in Note 5-Derivative Instruments. The carrying amount of cash and cash equivalents, restricted cash and cash equivalents, accounts receivable and accounts payable reported on the Consolidated Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note 9-Long-Term Debt, are based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments. Non-financial assets and liabilities initially measured at fair value include certain assets and liabilities acquired in a business combination, intangible assets, goodwill and AROs.
Revenue Recognition
LNG regasification capacity reservation fees are recognized as revenue over the term of the respective TUAs. Advance capacity reservation fees are initially deferred and amortized over a 10-year period as a reduction of a customer’s regasification capacity reservation fees payable under its TUA. Under each of these TUAs, Sabine Pass LNG is entitled to retain 2% of LNG delivered for each customer’s account at the Sabine Pass LNG terminal, which is recognized as revenues as Sabine Pass LNG performs the services set forth in each customer’s TUA.
LNG and Natural Gas Marketing
We have determined that our LNG and natural gas marketing business activities are energy trading and risk management activities for trading purposes and have elected to present these activities on a net basis on our Consolidated Statements of Operations. Marketing and trading revenues represent the margin earned on the purchase and transportation of LNG purchases and subsequent sales of natural gas to third parties. These energy trading and risk management activities include, but are not limited to: purchase of LNG and natural gas, transportation contracts and derivatives. Below is a brief description of our accounting treatment of each type of energy trading and risk management activity and how we account for each:
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Purchase of LNG and natural gas
The purchase value of LNG or natural gas inventory is recorded as an asset on our Consolidated Balance Sheets at the cost to acquire the product. Our inventory is subject to lower of cost or market adjustment each quarter. Recoveries of losses resulting from interim period lower of cost or market adjustments are made due to market price recoveries on the same inventory in the same fiscal year and are recognized as gains in later interim periods with such gains not exceeding previously recognized losses. Any adjustment to our inventory is recorded on a net basis as LNG and natural gas marketing revenue on our Consolidated Statements of Operations.
Transportation contracts
We enter into transportation contracts with respect to the transport of LNG or natural gas to a specific location for storage or sale. Transportation costs that are incurred during the purchase of LNG or natural gas are capitalized as part of the acquisition costs of the product. Transportation costs incurred to sell LNG or natural gas are recorded on a net basis as LNG and natural gas marketing revenue on our Consolidated Statements of Operations.
LNG Inventory Derivatives
We use derivative instruments to hedge cash flows attributable to the future sale of LNG inventory. Gains and losses in positions to hedge the cash flows attributable to the future sale of LNG inventory are classified as marketing and trading revenues on our Consolidated Statements of Operations.
Cash and Cash Equivalents
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Restricted Cash and Cash Equivalents
Restricted cash and cash equivalents consist of funds that are contractually restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets.
Amounts that are designated as restricted cash and cash equivalents are contractually restricted as to usage or withdrawal and will not become available to us as cash and cash equivalents. For these amounts, we have presented increases and decreases as “Investments in (uses of) restricted cash and cash equivalents” in our Consolidated Statements of Cash Flows. These amounts that represent non-cash transactions within our Consolidated Statements of Cash Flows present the effect of sources and uses of restricted cash and cash equivalents as they relate to the changes to assets and liabilities in our Consolidated Balance Sheets. Restricted cash and cash equivalents are presented on a gross basis within each of those categories so as to reconcile the change in non-cash activity that occurs on the balance sheet from period to period.
LNG Inventory
LNG inventory is recorded at cost and is subject to lower of cost or market (“LCM”) adjustments at the end of each period. LNG inventory cost is determined using the average cost method. Our LCM adjustments primarily related to LNG inventory purchased to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal that are recorded in operating and maintenance expense on our Consolidated Statements of Operations. Recoveries of losses resulting from interim period LCM adjustments are recorded when market price recoveries occur on the same inventory in the same fiscal year. These recoveries are recognized as gains in later interim periods with such gains not exceeding previously recognized losses. During the years ended December 31, 2014, 2013 and 2012, we recognized $24.5 million, $26.9 million and $20.4 million, respectively, as operating and maintenance expense as a result of LCM adjustments primarily related to LNG inventory purchased to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal.
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Accounting for LNG Activities
Generally, we begin capitalizing the costs of our LNG terminals and related pipelines once the individual project meets the following criteria: (i) regulatory approval has been received, (ii) financing for the project is available and (iii) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a project are expensed as incurred. These costs primarily include professional fees associated with front-end engineering and design work, costs of securing necessary regulatory approvals, and other preliminary investigation and development activities related to our LNG terminals and related pipelines.
Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land and lease option costs that are capitalized as property, plant and equipment and certain permits that are capitalized as intangible LNG assets. The costs of lease options are amortized over the life of the lease once obtained. If no lease is obtained, the costs are expensed.
We capitalize interest and other related debt costs during the construction period of our LNG terminal. Upon commencement of operations, capitalized interest, as a component of the total cost, will be amortized over the estimated useful life of the asset.
Property, Plant and Equipment
Property, plant and equipment are recorded at cost. Expenditures for construction activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs and general and administrative activities are charged to expense as incurred. Interest costs incurred on debt obtained for the construction of property, plant and equipment are capitalized as construction-in-process over the construction period or related debt term, whichever is shorter. We depreciate our property, plant and equipment using the straight-line depreciation method. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses are recorded in other operating costs and expenses.
Management tests property, plant and equipment for impairment whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. In performing this test, an undiscounted cash flow analysis is performed at the lowest level for which identifiable cash flows are independent of cash flows from other assets. If the sum of the undiscounted future net cash flows is less than the net book value of the property, an impairment loss is recognized for the excess, if any, of the property’s net book value over its estimated fair value. We have recorded no impairments related to property, plant and equipment for 2014, 2013 or 2012.
Regulated Natural Gas Pipelines
The Creole Trail Pipeline and Corpus Christi Pipeline are subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”) in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. The economic effects of regulation can result in a regulated company recording as assets those costs that have been or are expected to be approved for recovery from customers, or recording as liabilities those amounts that are expected to be required to be returned to customers, in a rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated rate-making process that may not be recorded under GAAP for non-regulated entities. We continually assess whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, we believe the existing regulatory assets are probable of recovery. These regulatory assets and liabilities are primarily classified in our Consolidated Balance Sheets as other assets and other liabilities. We periodically evaluate their applicability under GAAP, and consider factors such as regulatory changes and the effect of competition. If cost-based regulation ends or competition increases, we may have to reduce our asset balances to reflect a market basis less than cost and write off the associated regulatory assets and liabilities.
Items that may influence our assessment are:
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inability to recover cost increases due to rate caps and rate case moratoriums;
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inability to recover capitalized costs, including an adequate return on those costs through the rate-making process and the FERC proceedings;
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excess capacity;
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•
increased competition and discounting in the markets we serve; and
•
impacts of ongoing regulatory initiatives in the natural gas industry.
Natural gas pipeline costs include amounts capitalized as an Allowance for Funds Used During Construction (“AFUDC”). The rates used in the calculation of AFUDC are determined in accordance with guidelines established by the FERC. AFUDC represents the cost of debt and equity funds used to finance our natural gas pipeline additions during construction. AFUDC is capitalized as a part of the cost of our natural gas pipelines. Under regulatory rate practices, we generally are permitted to recover AFUDC, and a fair return thereon, through our rate base after our natural gas pipelines are placed in service.
Derivative Instruments
We use derivative instruments to hedge our exposure to cash flow variability from commodity price and interest rate risk. Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as assets or liabilities depending on the derivative position and the expected timing of settlement, unless they satisfy criteria and we elect the normal purchases and sales exception. When we have the contractual right and intend to net settle, derivative assets and liabilities are reported on a net basis.
Changes in the fair value of our derivative instruments are recorded in current earnings, unless we elect to apply hedge accounting and meet specified criteria, including completing contemporaneous hedge documentation. We did not have any derivative instruments designated as cash flow hedges as of December 31, 2014 and 2013.
From time to time, we have elected cash flow hedge accounting for derivatives that we use to hedge the exposure to volatility in floating-rate interest payments. Changes in fair value of derivative instruments designated as cash flow hedges, to the extent the hedge is effective, are recognized in accumulated other comprehensive loss on our Consolidated Balance Sheets. We reclassify gains and losses on the hedges from accumulated other comprehensive loss into interest expense in our Consolidated Statements of Operations as the hedged item is recognized. Any change in the fair value resulting from ineffectiveness is recognized immediately as derivative gain (loss) on our Consolidated Statements of Operations. We use regression analysis to determine whether we expect a derivative to be highly effective as a cash flow hedge, prior to electing hedge accounting and also to determine whether all derivatives designated as cash flow hedges have been effective. We perform these effectiveness tests prior to designation for all new hedges and on a quarterly basis for all existing hedges. We calculate the actual amount of ineffectiveness on our cash flow hedges using the “dollar offset” method, which compares changes in the expected cash flows of the hedged transaction to changes in the value of expected cash flows from the hedge. We discontinue hedge accounting when our effectiveness tests indicate that a derivative is no longer highly effective as a hedge; when the derivative expires or is sold, terminated or exercised; when the hedged item matures, is sold or repaid; or when we determine that the occurrence of the hedged forecasted transaction is not probable. When we discontinue hedge accounting but continue to hold the derivative, prospective changes in fair value of the derivative instrument are recorded in income. Once we conclude that the hedged forecasted transaction becomes probable of not occurring, the amount remaining in accumulated other comprehensive loss pertaining to the previously designated derivatives is reclassified out of accumulated other comprehensive loss and into income.
See Note 5-Derivative Instruments for additional details about our derivative instruments.
Concentration of Credit Risk
Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash and cash equivalents and restricted cash. We maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred losses related to these balances to date.
The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Our commodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. Collateral deposited for such contracts is recorded as an other current asset and not netted within the derivative fair value. Our interest rate derivative instruments are placed with investment grade financial institutions whom we believe are acceptable credit risks. We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our derivative instruments.
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Sabine Pass LNG has entered into certain long-term TUAs with unaffiliated third parties for regasification capacity at the Sabine Pass LNG terminal. Sabine Pass LNG is dependent on the respective counterparties’ creditworthiness and their willingness to perform under their respective TUAs. Sabine Pass LNG has mitigated this credit risk by securing TUAs for a significant portion of its regasification capacity with creditworthy third-party customers with a minimum Standard & Poor’s rating of AA.
Sabine Pass Liquefaction has entered into six fixed price 20-year SPAs with six unaffiliated third parties. Corpus Christi Liquefaction has entered into nine fixed price 20-year SPAs with seven unaffiliated third parties. Sabine Pass Liquefaction and Corpus Christi Liquefaction are dependent on the respective counterparties’ creditworthiness and their willingness to perform under their respective SPAs.
Goodwill
Goodwill represents the excess of cost over fair value of the assets of businesses acquired. The goodwill on our Consolidated Balance Sheets as of December 31, 2014 and 2013 is associated with our LNG terminal reporting unit. We determine our reporting units by identifying each unit that engaged in business activities from which it may earn revenues and incur expenses, had operating results regularly reviewed by the chief operating decision maker for purposes of resource allocation and performance assessment, and had discrete financial information.
Goodwill is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less often than annually. During the fourth quarters of 2014 and 2013, we performed a qualitative assessment of goodwill in accordance with FASB guidance, which permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. If we fail the qualitative test, then we must compare our estimate of the fair value of a reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, we perform the second step of the goodwill impairment test to measure the amount of goodwill impairment loss to be recorded, as necessary. The second step compares the implied fair value of the reporting unit’s goodwill to the carrying value, if any, of that goodwill. We determine the implied fair value of the goodwill in the same manner as determining the amount of goodwill to be recognized in a business combination.
We completed our annual assessment of goodwill impairment during the fourth quarters of 2014 and 2013, and the tests indicated no impairment. As discussed above regarding our use of estimates, our judgments and assumptions are inherent in our estimate of future cash flows used to determine the estimate of the reporting unit’s fair value. The use of alternate judgments and/or assumptions could result in the recognition of impairment charges in the Consolidated Financial Statements. A lower fair value estimate in the future for our LNG terminal reporting unit could result in an impairment of goodwill. Factors that could trigger a lower fair value estimate include significant negative industry or economic trends, cost increases, disruptions to our business, regulatory or political environment changes or other unanticipated events.
Long-Term Debt
Our debt consists of long-term secured debt securities, convertible debt securities, and credit facilities with banks and other lenders. Debt issuances are placed directly by us or through securities dealers or underwriters and are held by institutional and retail investors.
Debt is recorded on our balance sheet at par value adjusted for unamortized discount or premium. Discounts, premiums, and costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest expense, net using the effective interest method. Gains and losses on the extinguishment of debt are recorded in gains and losses on the extinguishment of debt on our Consolidated Statements of Operations.
Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees and printing costs. These costs are recorded as debt issuance costs on our Consolidated Balance Sheets and are being amortized to interest expense or property, plant and equipment over the term of the related debt facility. Upon early retirement of debt or amendment to a debt agreement, certain fees are written off to loss on early extinguishment of debt.
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Asset Retirement Obligations
We recognize AROs for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset. Our recognition of AROs is described below.
Currently, the Sabine Pass LNG terminal is our only constructed and operating LNG terminal. Based on the real property lease agreements at the Sabine Pass LNG terminal, at the expiration of the term of the leases we are required to surrender the LNG terminal in good working order and repair, with normal wear and tear and casualty expected. Our property lease agreements at the Sabine Pass LNG terminal have terms of up to 90 years including renewal options. We have determined that the cost to surrender the Sabine Pass LNG terminal in good order and repair, with normal wear and tear and casualty expected, is zero. Therefore, we have not recorded an ARO associated with the Sabine Pass LNG terminal.
Currently, the Creole Trail Pipeline is our only constructed and operating natural gas pipeline. We believe that it is not feasible to predict when the natural gas transportation services provided by the Creole Trail Pipeline will no longer be utilized. In addition, our right-of-way agreements associated with the Creole Trail Pipeline have no stipulated termination dates. Therefore, we have concluded that due to advanced technology associated with current natural gas pipelines and our intent to operate the Creole Trail Pipeline as long as supply and demand for natural gas exists in the United States, we have not recorded an ARO associated with the Creole Trail Pipeline.
Share-based Compensation
We have awarded share-based compensation in the form of stock, restricted stock, stock options and phantom units that are more fully described in Note 11-Share-Based Compensation. A summary of our accounting policy for share-based awards follows.
We recognize share-based compensation at fair value on the date of grant. The fair value is recognized as expense (net of any capitalization) over the requisite service period. For equity-classified share-based compensation awards (which include stock, restricted stock to employees and non-employee directors and stock options), compensation cost is recognized based on the grant-date fair value using the quoted market price of Cheniere’s common stock and not subsequently remeasured. The fair value is recognized as expense (net of any capitalization) using the straight-line basis for awards that vest based on service and market conditions and using the accelerated recognition method for awards that vest based on performance conditions. We estimate the service periods for performance awards utilizing a probability assessment based on when we expect to achieve the performance conditions. For liability-classified share-based compensation awards (which include restricted stock to non-employees and phantom units), compensation cost is initially recognized on the grant date using estimated payout levels. Compensation cost is subsequently adjusted quarterly to reflect the updated estimated payout levels based on the changes in the Company’s stock price.
Non-controlling Interests
When we consolidate a subsidiary, we include 100% of the assets, liabilities, revenues, and expenses of the subsidiary in our Consolidated Financial Statements, even if we own less than 100% of the subsidiary. Non-controlling interests represent third-party ownership in the net assets of our consolidated subsidiaries and are presented as a component of equity. Changes in our ownership interests in subsidiaries that do not result in deconsolidation are recognized within equity. See Note 7-Non-controlling Interests for additional details about our non-controlling interest.
Income Taxes
Provisions for income taxes are based on taxes payable or refundable for the current year and deferred taxes on temporary differences between the tax basis of assets and liabilities and their reported amounts in the Consolidated Financial Statements. Deferred tax assets and liabilities are included in the Consolidated Financial Statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the current period’s provision for income taxes. A valuation allowance is recorded to reduce the carrying value of our deferred tax assets when it is more likely than not that a
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
portion or all of the deferred tax assets will expire before realization of the benefit or future deductibility is not probable. A valuation allowance equal to our federal and state net deferred tax asset balance has been established due to the uncertainty of realizing the tax benefits related to our federal and state net deferred tax assets.
We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the tax position.
Net Loss Per Share
Net loss per share (“EPS”) is computed in accordance with GAAP. Basic EPS excludes dilution and is computed by dividing net income (loss) by the weighted average number of common shares outstanding during the period. Diluted EPS reflects potential dilution and is computed by dividing net income (loss) by the weighted average number of common shares outstanding during the period increased by the number of additional common shares that would have been outstanding if the potential common shares had been issued and were dilutive. Basic and diluted EPS for all periods presented are the same since the effect of our options and unvested stock is anti-dilutive to our net loss per share. Stock options 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 2014, 2013 and 2012, were 10.4 million shares, 14.1 million shares and 4.4 million shares, respectively. In addition, 14.3 million shares issuable upon conversion of the 2021 Convertible Unsecured Notes, as described in Note 9-Long-Term Debt, were not included in the computation of diluted net loss per share for 2014 because the computation of diluted net loss per share utilizing the “if-converted” method would be anti-dilutive.
NOTE 3-RESTRICTED CASH AND CASH EQUIVALENTS
Restricted cash and cash equivalents consist of funds that are contractually restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. Restricted cash and cash equivalents include the following:
Sabine Pass LNG Senior Notes Debt Service Reserve
Sabine Pass LNG has consummated private offerings of an aggregate principal amount of $1,665.5 million, before discount, of 7.50% Senior Secured Notes due 2016 (the “2016 Sabine Pass LNG Senior Notes”) and $420.0 million of 6.50% Senior Secured Notes due 2020 (the “2020 Sabine Pass LNG Senior Notes”). Collectively, the 2016 Sabine Pass LNG Senior Notes and the 2020 Sabine Pass LNG Senior Notes are referred to as the “Sabine Pass LNG Senior Notes.” Under the indentures governing the Sabine Pass LNG Senior Notes (the “Sabine Pass LNG Indentures”), except for permitted tax distributions, Sabine Pass LNG may not make distributions until certain conditions are satisfied, including: (i) there must be on deposit in an interest payment account an amount equal to one-sixth of the semi-annual interest payment multiplied by the number of elapsed months since the last semi-annual interest payment, and (ii) there must be on deposit in a permanent debt service reserve fund an amount equal to one semi-annual interest payment. Distributions are permitted only after satisfying the foregoing funding requirements, a fixed charge coverage ratio test of 2:1 and other conditions specified in the Sabine Pass LNG Indentures.
As of both December 31, 2014 and 2013, we classified $15.0 million as current restricted cash and cash equivalents for the payment of current interest due. As of both December 31, 2014 and 2013, we classified the permanent debt service reserve fund of $76.1 million as non-current restricted cash and cash equivalents. These cash accounts are controlled by a collateral trustee and, therefore, are shown as restricted cash and cash equivalents on our Consolidated Balance Sheets.
Sabine Pass Liquefaction Reserve
In July 2012, Sabine Pass Liquefaction entered into a construction/term loan facility in an amount up to $3.6 billion (the “2012 Liquefaction Credit Facility”). During 2013, Sabine Pass Liquefaction entered into four credit facilities aggregating $5.9 billion (collectively, the “2013 Liquefaction Credit Facilities”), which amended and restated the 2012 Liquefaction Credit Facility. Under the terms and conditions of the 2012 Liquefaction Credit Facility Sabine Pass Liquefaction was required, and under the 2013 Liquefaction Credit Facilities Sabine Pass Liquefaction is required, to deposit all cash received into reserve accounts controlled by a collateral trustee. Therefore, all of Sabine Pass Liquefaction’s cash and cash equivalents are shown as restricted cash and cash equivalents on our Consolidated Balance Sheets.
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During 2013, Sabine Pass Liquefaction issued an aggregate principal amount of $2.0 billion, before premium, of 5.625% Senior Secured Notes due 2021 (the “2021 Sabine Pass Liquefaction Senior Notes”), $1.0 billion of 6.25% Senior Secured Notes due 2022 (the “2022 Sabine Pass Liquefaction Senior Notes”) and $1.0 billion of 5.625% Senior Secured Notes due 2023 (the “2023 Sabine Pass Liquefaction Senior Notes”). During 2014, Sabine Pass Liquefaction issued an aggregate principal amount of $2.0 billion of 5.75% Senior Secured Notes due 2024 (the “2024 Sabine Pass Liquefaction Senior Notes” and collectively with the 2021 Sabine Pass Liquefaction Senior Notes, the 2022 Sabine Pass Liquefaction Senior Notes and the 2023 Sabine Pass Liquefaction Senior Notes, the “Sabine Pass Liquefaction Senior Notes”) and additional 2023 Sabine Pass Liquefaction Senior Notes (the “Additional 2023 Sabine Pass Liquefaction Senior Notes”) in an aggregate principal amount of $0.5 billion, before premium.
As of December 31, 2014 and 2013, we classified $155.8 million and $192.1 million, respectively, as current restricted cash and cash equivalents held by Sabine Pass Liquefaction for the payment of current liabilities related to the Sabine Pass Liquefaction Project and $457.1 million and $867.6 million, respectively, as non-current restricted cash and cash equivalents held by Sabine Pass Liquefaction for future Sabine Pass Liquefaction Project construction costs.
CTPL Reserve
In May 2013, CTPL entered into a $400.0 million term loan facility (the “2017 CTPL Term Loan”). As of December 31, 2014 and 2013, we classified $24.9 million and $20.5 million, respectively, as current restricted cash and cash equivalents held by CTPL for the payment of current liabilities and $11.3 million and $81.4 million, respectively, as non-current restricted cash and cash equivalents held by CTPL because such funds may only be used for modifications of the 94-mile Creole Trail Pipeline, which interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines, in order to enable bi-directional natural gas flow and for the payment of interest during construction of such modifications. The restricted cash reserved to pay interest during construction is controlled by a collateral agent, and can only be released by the collateral agent upon satisfaction of certain terms and conditions.
See Note 9-Long-Term Debt for additional details about our long-term debt.
Other Restricted Cash and Cash Equivalents
As of December 31, 2014 and 2013, $250.1 million and $351.0 million, respectively, of cash and cash equivalents were held by Sabine Pass LNG, Cheniere Partners, and Cheniere Holdings that were restricted from use by Cheniere. In addition, as of December 31, 2014 and 2013, $35.9 million and $19.4 million, respectively, had been classified as current restricted cash and cash equivalents, and as of both December 31, 2014 and 2013, $6.3 million had been classified as non-current restricted cash and cash equivalents on our Consolidated Balance Sheets due to various other contractual restrictions.
NOTE 4-PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consists of LNG terminal costs and fixed assets and other, as follows (in thousands):
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LNG Terminal Costs
The Sabine Pass LNG terminal is depreciated using the straight-line depreciation method applied to groups of LNG terminal assets with varying useful lives. The identifiable components of the Sabine Pass LNG terminal with similar estimated useful lives have a depreciable range between 15 and 50 years, as follows:
We are developing the Corpus Christi Liquefaction Project and have capitalized certain costs associated with our proposed Corpus Christi LNG terminal for site work that improved the associated land. As of December 31, 2014 and 2013, $66.1 million and $35.5 million, respectively, of costs associated with the initial site work for the proposed Corpus Christi LNG terminal were capitalized as LNG terminal construction-in-process.
Fixed Assets and Other
Our fixed assets and other are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets.
NOTE 5-DERIVATIVE INSTRUMENTS
We have entered into the following derivative instruments that are reported at fair value:
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commodity derivatives to hedge the exposure to variability in expected future cash flows attributable to the future sale of our LNG inventory (“LNG Inventory Derivatives”);
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commodity derivatives to hedge the exposure to price risk attributable to future purchases of natural gas to be utilized as fuel to operate the Sabine Pass LNG terminal (“Fuel Derivatives”);
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commodity derivatives consisting of natural gas purchase agreements to secure natural gas feedstock for the Sabine Pass Liquefaction Project (“Term Gas Supply Derivatives”); and
•
interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the 2013 Liquefaction Credit Facilities (“Interest Rate Derivatives”).
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The following table (in thousands) shows the fair value of our derivative assets and liabilities that are required to be measured at fair value on a recurring basis as of December 31, 2014 and 2013, which are classified as prepaid expenses and other, non-current derivative assets and other current liabilities in our Consolidated Balance Sheets.
The estimated fair values of our LNG Inventory Derivatives and Fuel Derivatives are the amounts at which the instruments could be exchanged currently between willing parties. We value these derivatives using observable commodity price curves and other relevant data. We value our Interest Rate Derivatives using valuations based on the initial trade prices. Using an income-based approach, subsequent valuations are based on observable inputs to the valuation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data.
The fair value of Sabine Pass Liquefaction’s Term Gas Supply Derivatives is developed through the use of internal models which are impacted by inputs that are unobservable in the marketplace. As a result, the fair value of Sabine Pass Liquefaction’s Term Gas Supply Derivatives is designated as Level 3 within the valuation hierarchy. The curves used to generate the fair value of the Term Gas Supply Derivatives are based on basis adjustments applied to forward curves for a liquid trading point. In addition, there may be observable liquid market basis information in the near term, but terms of a particular Term Gas Supply Derivative contract may exceed the period for which such information is available, resulting in a Level 3 classification. In these instances, fair value of the contract incorporates extrapolation assumptions made in the determination of the market basis price for future delivery periods in which applicable commodity basis prices were either not observable or lacked corroborative market data. Internal fair value models that include contractual pricing with a fixed basis include fixed basis amounts for delivery at locations for which no market currently exists. Internal fair value models also include conditions precedent to the respective long-term natural gas purchase agreements. As of December 31, 2014, the majority of Sabine Pass Liquefaction’s Term Gas Supply Derivatives existed within markets for which the pipeline infrastructure has not been developed to accommodate marketable physical gas flow and our internal fair value models were based on a market price that equated to our own contractual pricing due to the inactive and unobservable market as well as the conditions precedent and their impact on the uncertainty in the timing of our actual receipt of the physical volumes associated with each forward. The fair value of the Term Gas Supply Derivatives is predominantly driven by market commodity basis prices and our assessment of the associated conditions precedent, including evaluating whether the respective market is available as pipeline infrastructure is developed. We estimated the fair value of Sabine Pass Liquefaction’s Term Gas Supply Derivatives to be $0.3 million as of December 31, 2014.
There were no transfers into or out of Level 3 for the years ended December 31, 2014 and 2013. As all of our Term Gas Supply Derivatives are either purely index-priced or index-priced with a fixed basis, we do not believe that a significant change in market commodity prices would have a material impact on our Level 3 fair value measurements. The following table (in thousands, except natural gas basis spread) includes quantitative information for the unobservable inputs as of December 31, 2014:
Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis, as all counterparty derivative contracts provide for net settlement.
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Commodity Derivatives
We recognize all commodity derivative instruments, including our LNG Inventory Derivatives, Fuel Derivatives and Term Gas Supply Derivatives (collectively, “Commodity Derivatives”) as either assets or liabilities and measure those instruments at fair value. Changes in the fair value of our Commodity Derivatives are reported in earnings.
The following table (in thousands) shows the fair value and location of our Commodity Derivatives on our Consolidated Balance Sheets:
The following table (in thousands) shows the changes in the fair value and settlements and location of our Commodity Derivatives recorded on our Consolidated Statements of Operations during the years ended December 31, 2014, 2013 and 2012:
(1) There were no settlements during the reporting period.
LNG Inventory and Fuel Derivatives
The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances where our LNG Inventory Derivatives or Fuel Derivatives are in an asset position. Our LNG Inventory Derivatives and Fuel Derivatives are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. We are required by these financial institutions to use margin deposits as credit support for these commodity derivative activities. Collateral of $5.7 million and $5.9 million deposited for such contracts, which has not been reflected in the derivative fair value tables, is included in the other current assets balance as of December 31, 2014 and 2013, respectively.
Term Gas Supply Derivatives
Sabine Pass Liquefaction has entered into index-based physical natural gas supply contracts to secure natural gas feedstock for the Sabine Pass Liquefaction Project. The terms of these contracts range from approximately one to seven years and commence upon the occurrence of conditions precedent, including the date of first commercial operation of specified Trains of the Sabine Pass Liquefaction Project. We recognize Sabine Pass Liquefaction’s Term Gas Supply Derivatives as either assets or liabilities and measure those instruments at fair value. Changes in the fair value of Sabine Pass Liquefaction’s Term Gas Supply Derivatives are reported in earnings.
As of December 31, 2014, the majority of Sabine Pass Liquefaction’s Term Gas Supply Derivatives existed within markets for which the pipeline infrastructure has not been developed to accommodate marketable physical gas flow and our internal fair value models were based on a market price that equated to Sabine Pass Liquefaction’s own contractual pricing due to the inactive and unobservable market as well as the conditions precedent and their impact on the uncertainty in the timing of our actual receipt
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of the physical volumes associated with each forward. As of December 31, 2014, the forward notional natural gas buy position of Sabine Pass Liquefaction’s Term Gas Supply Derivatives was approximately 1,249.4 million MMBtu.
Interest Rate Derivatives
In August 2012 and June 2013, Sabine Pass Liquefaction entered into Interest Rate Derivatives to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the 2012 Liquefaction Credit Facility and the 2013 Liquefaction Credit Facilities, respectively. The Interest Rate Derivatives hedge a portion of the expected outstanding borrowings over the term of the 2013 Liquefaction Credit Facilities.
Sabine Pass Liquefaction designated the Interest Rate Derivatives entered into in August 2012 as hedging instruments which was required in order to qualify for cash flow hedge accounting. As a result of this cash flow hedge designation, we recognized the Interest Rate Derivatives entered into in August 2012 as an asset or liability at fair value and reflected changes in fair value through other comprehensive income in our Consolidated Statements of Comprehensive Loss. Any hedge ineffectiveness associated with the Interest Rate Derivatives entered into in August 2012 was recorded immediately as derivative gain (loss) in our Consolidated Statements of Operations. The realized gain (loss) on the Interest Rate Derivatives entered into in August 2012 was recorded as an (increase) decrease in interest expense on our Consolidated Statements of Operations to the extent not capitalized as part of the Sabine Pass Liquefaction Project. The effective portion of the gains or losses on our Interest Rate Derivatives entered into in August 2012 recorded in other comprehensive income would have been reclassified to earnings as interest payments on the 2012 Liquefaction Credit Facility impact earnings. In addition, amounts recorded in other comprehensive income are also reclassified into earnings if it becomes probable that the hedged forecasted transaction will not occur.
Sabine Pass Liquefaction did not elect to designate the Interest Rate Derivatives entered into in June 2013 as cash flow hedging instruments, and changes in fair value are recorded as derivative gain (loss), net within our Consolidated Statements of Operations.
During the first quarter of 2013, we determined that it was no longer probable that the forecasted variable interest payments on the 2012 Liquefaction Credit Facility would occur in the time period originally specified based on the continued development of our financing strategy for the Sabine Pass Liquefaction Project, and, in particular, the Sabine Pass Liquefaction Senior Notes described in Note 9-Long-Term Debt. As a result, all of the Interest Rate Derivatives entered into in August 2012 were no longer effective hedges, and the remaining portion of hedge relationships that were designated cash flow hedges as of December 31, 2012, were de-designated as of February 1, 2013. For de-designated cash flow hedges, changes in fair value prior to their de-designation date were recorded as other comprehensive income (loss) within our Consolidated Balance Sheets, and changes in fair value subsequent to their de-designation date were recorded as derivative gain (loss) within our Consolidated Statements of Operations.
In June 2013, Sabine Pass Liquefaction concluded that the hedged forecasted transactions associated with the Interest Rate Derivatives entered into in connection with the 2012 Liquefaction Credit Facility had become probable of not occurring based on the issuances of the Sabine Pass Liquefaction Senior Notes, the closing of the 2013 Liquefaction Credit Facilities, the additional Interest Rate Derivatives executed in June 2013, and Sabine Pass Liquefaction’s intention to continue to issue fixed rate debt to refinance the 2013 Liquefaction Credit Facilities. As a result, the amount remaining in accumulated other comprehensive income (“AOCI”) pertaining to the previously designated Interest Rate Derivatives was reclassified out of AOCI and into income. We have presented the changes in fair value and settlements subsequent to the reclassification date separate from interest expense as derivative gain (loss), net in our Consolidated Statements of Operations.
In May 2014, Sabine Pass Liquefaction settled a portion of its Interest Rate Derivatives and recognized a derivative loss of $9.3 million within our Consolidated Statements of Operations in conjunction with the termination of approximately $2.1 billion of commitments under the 2013 Liquefaction Credit Facilities as discussed in Note 9-Long-Term Debt.
At December 31, 2014, Sabine Pass Liquefaction had the following Interest Rate Derivatives outstanding:
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The following table (in thousands) shows the fair value of our Interest Rate Derivatives:
The following table (in thousands) details the effect of our Interest Rate Derivatives included in Other Comprehensive Income (“OCI”) and AOCI for the years ended December 31, 2014, 2013 and 2012:
The following table (in thousands) shows the changes in the fair value and settlements of our Interest Rate Derivatives - Not Designated recorded in derivative gain (loss), net on our Consolidated Statements of Operations during the years ended December 31, 2014, 2013 and 2012:
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Balance Sheet Presentation
Our commodity and interest rate derivatives are presented on a net basis on our Consolidated Balance Sheets as described above. The following table (in thousands) shows the fair value of our derivatives outstanding on a gross and net basis:
NOTE 6-VARIABLE INTEREST ENTITY
Cheniere Partners
Cheniere Partners is a master limited partnership formed by us in 2006 to own and operate the Sabine Pass LNG terminal and related assets. Cheniere Holdings is a limited liability company formed by us in 2013 to hold our Cheniere Partners limited partner interests. As of December 31, 2014, we owned 80.1% of Cheniere Holdings, which owns a 55.9% limited partner interest in Cheniere Partners in the form of 12.0 million common units, 45.3 million Class B units and 135.4 million subordinated units. We also own 100% of the general partner interest and the incentive distribution rights in Cheniere Partners.
Cheniere Energy Partners GP, LLC (“Cheniere Partners GP”), our wholly owned subsidiary, is the general partner of Cheniere Partners. In May 2012, Cheniere Partners, Cheniere and Blackstone CQP Holdco LP (“Blackstone”) entered into a unit purchase agreement (the “Blackstone Unit Purchase Agreement”) whereby Cheniere Partners agreed to sell to Blackstone in a private placement 100.0 million Class B units of Cheniere Partners (“Class B units”) at a price of $15.00 per Class B unit. In August 2012, all conditions to funding were met and Blackstone purchased its initial 33.3 million Class B units, and as of December 31, 2012, Blackstone had purchased the remaining 66.7 million Class B units. At initial funding, the board of directors of Cheniere Partners GP was modified to include three directors appointed by Blackstone, four directors appointed by us and four independent directors mutually agreed upon by Blackstone and us and appointed by us. In addition, we provided Blackstone with a right to maintain one board seat on our board of directors. A quorum of Cheniere Partners GP directors consists of a majority of all directors, including at least two directors appointed by Blackstone, two directors appointed by us and two independent directors. Blackstone will no longer be entitled to appoint Cheniere Partners GP directors in the event that Blackstone’s ownership in Cheniere Partners is less than: (i) 20% of outstanding common units, subordinated units and Class B units, and (ii) 50.0 million Class B units.
As a result of contractual changes in the governance of Cheniere Partners GP in connection with the Blackstone Unit Purchase Agreement, we have determined that Cheniere Partners GP is a variable interest entity and that we, as the holder of the equity at risk, do not have a controlling financial interest due to the rights held by Blackstone. However, we continue to consolidate Cheniere Partners as a result of Blackstone’s right to maintain one board seat on our board of directors which creates a de facto agency relationship between Blackstone and us. GAAP requires that when a de facto agency relationship exists, one of the members of the de facto agency relationship must consolidate the variable interest entity based on certain criteria. As a result, we consolidate Cheniere Partners in our Consolidated Financial Statements.
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NOTE 7-NON-CONTROLLING INTEREST
In December 2013, Cheniere Holdings completed its initial public offering (the “Cheniere Holdings Offering”) of 36.0 million common shares at $20.00 per common share. Cheniere Holdings was formed by us to hold our limited partner interest in Cheniere Partners. We ultimately received all of the $665.0 million of net proceeds, after deducting offering expenses, from the Cheniere Holdings Offering from the repayment of Cheniere Holdings’ intercompany indebtedness and payables owed to us and through a distribution by Cheniere Holdings to us. Additionally, in November 2014, Cheniere Holdings sold 10.1 million common shares at $22.76 per common share for net proceeds of approximately $229 million, after deducting offering expenses, which were used to redeem from us the same number of common shares. As of December 31, 2014 and 2013, our ownership interest in Cheniere Holdings was 80.1% and 84.5%, respectively, with the remaining non-controlling interest held by the public. Our ownership of Cheniere Partners interests is further discussed in Note 6-Variable Interest Entities.
NOTE 8-ACCRUED LIABILITIES
As of December 31, 2014 and 2013, accrued liabilities consisted of the following (in thousands):
NOTE 9-LONG-TERM DEBT
As of December 31, 2014 and 2013, our long-term debt consisted of the following (in thousands):
For the years ended December 31, 2014, 2013 and 2012, we incurred $587.0 million, $414.0 million and $235.9 million of total interest cost, respectively, of which we capitalized and deferred $405.8 million, $233.0 million and $35.1 million, respectively, of interest cost, including amortization of debt issuance costs, primarily related to the construction of the first four Trains of the Sabine Pass Liquefaction Project.
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Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31, 2014 (in thousands):
Sabine Pass LNG Senior Notes
As of both December 31, 2014 and 2013, Sabine Pass LNG had an aggregate principal amount of $1,665.5 million, before discount, of the 2016 Sabine Pass LNG Senior Notes and $420.0 million of the 2020 Sabine Pass LNG Senior Notes outstanding. Borrowings under the 2016 Sabine Pass LNG Senior Notes and 2020 Sabine Pass LNG Senior Notes bear interest at a fixed rate of 7.50% and 6.50%, respectively. The terms of the 2016 Sabine Pass LNG Senior Notes and the 2020 Sabine Pass LNG Senior Notes are substantially similar. Interest on the Sabine Pass LNG Senior Notes is payable semi-annually in arrears. Subject to permitted liens, the Sabine Pass LNG Senior Notes are secured on a first-priority basis by a security interest in all of Sabine Pass LNG’s equity interests and substantially all of its operating assets.
Sabine Pass LNG may redeem all or part of the 2016 Sabine Pass LNG Senior Notes at any time, and from time to time, at a redemption price equal to 100% of the principal plus any accrued and unpaid interest plus the greater of:
•
1.0% of the principal amount of the 2016 Sabine Pass LNG Senior Notes; or
•
the excess of: a) the present value at such redemption date of (i) the redemption price of the 2016 Sabine Pass LNG Senior Notes plus (ii) all required interest payments due on the 2016 Sabine Pass LNG Senior Notes (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50 basis points; over b) the principal amount of the 2016 Sabine Pass LNG Senior Notes, if greater.
Sabine Pass LNG may redeem all or part of the 2020 Sabine Pass LNG Senior Notes at any time on or after November 1, 2016, at fixed redemption prices specified in the indenture governing the 2020 Sabine Pass LNG Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. Sabine Pass LNG may also, at its option, redeem all or part of the 2020 Sabine Pass LNG Senior Notes at any time prior to November 1, 2016, at a “make-whole” price set forth in the indenture governing the 2020 Sabine Pass LNG Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. At any time before November 1, 2015, Sabine Pass LNG may redeem up to 35% of the aggregate principal amount of the 2020 Sabine Pass LNG Senior Notes at a redemption price of 106.5% of the principal amount of the 2020 Sabine Pass LNG Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the redemption date, in an amount not to exceed the net proceeds of one or more completed equity offerings as long as Sabine Pass LNG redeems the 2020 Sabine Pass LNG Senior Notes within 180 days of the closing date for such equity offering and at least 65% of the aggregate principal amount of the 2020 Sabine Pass LNG Senior Notes originally issued remains outstanding after the redemption.
Under the Sabine Pass LNG Indentures, except for permitted tax distributions, Sabine Pass LNG may not make distributions until certain conditions are satisfied as described in Note 3-Restricted Cash and Cash Equivalents. During the years ended December 31, 2014, 2013 and 2012, Sabine Pass LNG made distributions of $346.9 million, $348.9 million and $333.5 million, respectively, after satisfying all the applicable conditions in the Sabine Pass LNG Indentures.
Sabine Pass Liquefaction Senior Notes
In February 2013 and April 2013, Sabine Pass Liquefaction issued an aggregate principal amount of $2.0 billion, before premium, of the 2021 Sabine Pass Liquefaction Senior Notes. In April 2013 and May 2014, Sabine Pass Liquefaction issued an
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aggregate principal amount of $1.5 billion, before premium, of the 2023 Sabine Pass Liquefaction Senior Notes. Borrowings under the 2021 Sabine Pass Liquefaction Senior Notes and 2023 Sabine Pass Liquefaction Senior Notes bear interest at a fixed rate of 5.625%. In November 2013, Sabine Pass Liquefaction issued an aggregate principal amount of $1.0 billion of the 2022 Sabine Pass Liquefaction Senior Notes. Borrowings under the 2022 Sabine Pass Liquefaction Senior Notes bear interest at a fixed rate of 6.25%. In May 2014, Sabine Pass Liquefaction issued an aggregate principal amount of $2.0 billion of the 2024 Sabine Pass Liquefaction Senior Notes. Borrowings under the 2024 Sabine Pass Liquefaction Senior Notes bear interest at a fixed rate of 5.75%. Interest on the Sabine Pass Liquefaction Senior Notes is payable semi-annually in arrears.
The terms of the 2021 Sabine Pass Liquefaction Senior Notes, the 2022 Sabine Pass Liquefaction Senior Notes, the 2023 Sabine Pass Liquefaction Senior Notes and the 2024 Sabine Pass Liquefaction Senior Notes are governed by a common indenture (the “Sabine Pass Liquefaction Indenture”). The Sabine Pass Liquefaction Indenture contains customary terms and events of default and certain covenants that, among other things, limit Sabine Pass Liquefaction’s ability and the ability of Sabine Pass Liquefaction’s restricted subsidiaries to incur additional indebtedness or issue preferred stock, make certain investments or pay dividends or distributions on capital stock or subordinated indebtedness or purchase, redeem or retire capital stock, sell or transfer assets, including capital stock of Sabine Pass Liquefaction’s restricted subsidiaries, restrict dividends or other payments by restricted subsidiaries, incur liens, enter into transactions with affiliates, consolidate, merge, sell or lease all or substantially all of Sabine Pass Liquefaction’s assets and enter into certain LNG sales contracts. Subject to permitted liens, the Sabine Pass Liquefaction Senior Notes are secured on a pari passu first-priority basis by a security interest in all of the membership interests in Sabine Pass Liquefaction and substantially all of Sabine Pass Liquefaction’s assets. Sabine Pass Liquefaction may not make any distributions until, among other requirements, substantial completion of Trains 1 and 2 has occurred, deposits are made into debt service reserve accounts and a debt service coverage ratio for the prior 12-month period and a projected debt service coverage ratio for the upcoming 12-month period of 1.25:1.00 are satisfied.
At any time prior to November 1, 2020, with respect to the 2021 Sabine Pass Liquefaction Senior Notes; December 15, 2021, with respect to the 2022 Sabine Pass Liquefaction Senior Notes; January 15, 2023, with respect to the 2023 Sabine Pass Liquefaction Senior Notes; or February 15, 2024, with respect to the 2024 Sabine Pass Liquefaction Senior Notes, Sabine Pass Liquefaction may redeem all or part of such series of the Sabine Pass Liquefaction Senior Notes at a redemption price equal to the “make-whole” price set forth in the Sabine Pass Liquefaction Indenture, plus accrued and unpaid interest, if any, to the date of redemption. Sabine Pass Liquefaction may also at any time on or after November 1, 2020, with respect to the 2021 Sabine Pass Liquefaction Senior Notes; December 15, 2021, with respect to the 2022 Sabine Pass Liquefaction Senior Notes; January 15, 2023, with respect to the 2023 Sabine Pass Liquefaction Senior Notes; or February 15, 2024, with respect to the 2024 Sabine Pass Liquefaction Senior Notes, redeem all or part of such series of the Sabine Pass Liquefaction Senior Notes at a redemption price equal to 100% of the principal amount of such series of the Sabine Pass Liquefaction Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.
2013 Liquefaction Credit Facilities
In May 2013, Sabine Pass Liquefaction entered into the 2013 Liquefaction Credit Facilities aggregating $5.9 billion. The 2013 Liquefaction Credit Facilities are being used to fund a portion of the costs of developing, constructing and placing into operation the first four Trains of the Sabine Pass Liquefaction Project. The 2013 Liquefaction Credit Facilities will mature on the earlier of May 28, 2020 or the second anniversary of the completion date of the first four Trains of the Sabine Pass Liquefaction Project, as defined in the 2013 Liquefaction Credit Facilities. Borrowings under the 2013 Liquefaction Credit Facilities may be refinanced, in whole or in part, at any time without premium or penalty, except for interest rate hedging and interest rate breakage costs. Sabine Pass Liquefaction made an initial $100.0 million borrowing under the 2013 Liquefaction Credit Facilities in June 2013 after meeting the required conditions precedent, and in May 2014, Sabine Pass Liquefaction repaid its borrowings under the 2013 Liquefaction Credit Facilities upon the issuance of the Additional 2023 Sabine Pass Liquefaction Senior Notes and the 2024 Sabine Pass Liquefaction Senior Notes. As of December 31, 2014 and 2013, Sabine Pass Liquefaction had $2.7 billion and $4.9 billion, respectively, of available commitments under the 2013 Liquefaction Credit Facilities.
Borrowings under the 2013 Liquefaction Credit Facilities bear interest at a variable rate per annum equal to, at Sabine Pass Liquefaction’s election, the London Interbank Offered Rate (“LIBOR”) or the base rate, plus the applicable margin. The applicable margins for LIBOR loans range from 2.3% to 3.0% prior to the completion of Train 4 and from 2.3% to 3.25% after such completion, depending on the applicable 2013 Liquefaction Credit Facility. Interest on LIBOR loans is due and payable at the end of each LIBOR period. The 2013 Liquefaction Credit Facilities required Sabine Pass Liquefaction to pay certain up-front fees to the agents and lenders in the aggregate amount of approximately $144 million and provide for a commitment fee calculated at a rate per annum equal to 40% of the applicable margin for LIBOR loans, multiplied by the average daily amount of the undrawn commitment
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due quarterly in arrears. Annual administrative fees must also be paid to the agent and the trustee. The principal of the loans made under the 2013 Liquefaction Credit Facilities must be repaid in quarterly installments, commencing with the earlier of the last day of the first full calendar quarter after the Train 4 completion date, as defined in the 2013 Liquefaction Credit Facilities, or September 30, 2018. Scheduled repayments are based upon an 18-year amortization profile, with the remaining balance due upon the maturity of the 2013 Liquefaction Credit Facilities.
Under the terms and conditions of the 2013 Liquefaction Credit Facilities, all cash held by Sabine Pass Liquefaction is controlled by a collateral agent. These funds can only be released by the collateral agent upon satisfaction of certain terms and conditions related to the use of proceeds, and are classified as restricted on our Consolidated Balance Sheets.
The 2013 Liquefaction Credit Facilities contain conditions precedent for any subsequent borrowings, as well as customary affirmative and negative covenants. The obligations of Sabine Pass Liquefaction under the 2013 Liquefaction Credit Facilities are secured by substantially all of the assets of Sabine Pass Liquefaction as well as all of the membership interests in Sabine Pass Liquefaction on a pari passu basis with the Sabine Pass Liquefaction Senior Notes.
Under the terms of the 2013 Liquefaction Credit Facilities, Sabine Pass Liquefaction is required to hedge not less than 75% of the variable interest rate exposure of its projected outstanding borrowings, calculated on a weighted average basis in comparison to its anticipated draw of principal. See Note 5- Derivative Instruments.
In November 2013, in conjunction with Sabine Pass Liquefaction’s issuance of the 2022 Sabine Pass Liquefaction Senior Notes, Sabine Pass Liquefaction terminated approximately $885 million of commitments under the 2013 Liquefaction Credit Facilities. This termination resulted in a write-off of debt issuance costs and deferred commitment fees associated with the 2013 Liquefaction Credit Facilities of $43.3 million in November 2013.
In May 2014, in conjunction with Sabine Pass Liquefaction’s issuance of the 2024 Sabine Pass Liquefaction Senior Notes and the Additional 2023 Sabine Pass Liquefaction Senior Notes, Sabine Pass Liquefaction terminated approximately $2.1 billion of commitments under the 2013 Liquefaction Credit Facilities. This termination resulted in a write-off of debt issuance costs and deferred commitment fees associated with the 2013 Liquefaction Credit Facilities of $114.3 million in May 2014.
2012 Liquefaction Credit Facility
In July 2012, Sabine Pass Liquefaction entered into the 2012 Liquefaction Credit Facility with a syndicate of lenders. The 2012 Liquefaction Credit Facility was intended to be used to fund a portion of the costs of developing, constructing and placing into operation Trains 1 and 2 of the Sabine Pass Liquefaction Project. Borrowings under the 2012 Liquefaction Credit Facility were based on LIBOR plus 3.50% during construction and LIBOR plus 3.75% during operations. Sabine Pass Liquefaction was also required to pay commitment fees on the undrawn amount. In May 2013, the 2012 Liquefaction Credit Facility was amended and restated with the 2013 Liquefaction Credit Facilities and $100.0 million of outstanding borrowings under the 2012 Liquefaction Credit Facility were repaid in full.
Under the terms of the 2012 Liquefaction Credit Facility, Sabine Pass Liquefaction was required to hedge not less than 75% of the variable interest rate exposure of its projected outstanding borrowings, calculated on a weighted average basis in comparison to its anticipated draw of principal. See Note 5- Derivative Instruments.
In conjunction with the issuance of the 2021 Sabine Pass Liquefaction Senior Notes in February 2013 and the issuances of $500.0 million of additional 2021 Sabine Pass Liquefaction Senior Notes and 2023 Sabine Pass Liquefaction Senior Notes in April 2013, approximately $1.4 billion of commitments under the 2012 Liquefaction Credit Facility were terminated. The termination of these commitments in April 2013 and the amendment and restatement of the 2012 Liquefaction Credit Facility with the 2013 Liquefaction Credit Facilities in May 2013 resulted in a write-off of debt issuance costs and deferred commitment fees associated with the 2012 Liquefaction Credit Facility of $88.3 million during the year ended December 31, 2013.
2021 Convertible Unsecured Notes
In November 2014, we issued an aggregate principal amount of $1.0 billion unsecured convertible notes due 2021 (the “2021 Convertible Unsecured Notes”) on a private placement basis in reliance on the exemption from registration provided for under Section 4(a)(2) of the Securities Act and Regulation S promulgated thereunder. The 2021 Convertible Unsecured Notes bear interest at a rate of 4.875% per annum, which is payable in kind (“PIK”) semi-annually in arrears by increasing the principal
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amount of the 2021 Convertible Unsecured Notes outstanding. One year after the closing date, the 2021 Convertible Unsecured Notes will be convertible at the option of the holder into our common stock at an initial conversion price of $93.64, provided that our closing price of common stock is greater than or equal to $93.64 on the conversion date. The conversion rate is subject to adjustment upon the occurrence of certain specified events. We have the option to satisfy the conversion obligation with cash, common stock or a combination thereof.
Under GAAP, certain convertible debt instruments that may be settled in cash upon conversion are required to be separately accounted for as liability (debt) and equity (conversion option) components of the instrument in a manner that reflects the issuer’s non-convertible debt borrowing rate. We determined that the fair value of the debt component was $808.8 million and the residual value of the equity component was $191.2 million as of the issuance date. The debt component is accreted to the total principal amount due at maturity by amortizing the debt discount. The effective rate of interest to amortize the debt discount was approximately 9.16% as of December 31, 2014, and the remaining period over which the debt discount will be amortized was 6.4 years.
Interest expense, before capitalization, related to the 2021 Convertible Unsecured Notes consisted of the following (in thousands):
In connection with the issuance of the 2021 Convertible Unsecured Notes, we have agreed, if permitted by applicable law and approved by the Securities and Exchange Commission (“SEC”), to use commercially reasonable efforts to file with the SEC and cause to become effective registration statements relating to offers to exchange the 2021 Convertible Unsecured Notes for like aggregate principal amounts of SEC-registered notes with terms identical in all material respects to the 2021 Convertible Unsecured Notes (other than with respect to restrictions on transfer or for references to restrictive legends), by November 30, 2015. If the SEC does not approve registration of the exchange offer or an exchange offer would not be permitted by applicable laws, we have agreed to use our reasonable best efforts to prepare and file shelf registration statements to cover resales of the 2021 Convertible Unsecured Notes. If we fail to satisfy these obligations, we may be required to pay additional interest to holders of the 2021 Convertible Unsecured Notes under certain circumstances.
2017 CTPL Term Loan
In May 2013, CTPL entered into the 2017 CTPL Term Loan, which is being used to fund modifications to the Creole Trail Pipeline and for general business purposes. CTPL incurred $10.0 million of direct lender fees that were recorded as a debt discount. The 2017 CTPL Term Loan matures in 2017 when the full amount of the outstanding principal obligations must be repaid. CTPL’s loans may be repaid, in whole or in part, at any time without premium or penalty. As of December 31, 2014, CTPL had borrowed the full amount of $400.0 million available under the 2017 CTPL Term Loan.
Borrowings under the 2017 CTPL Term Loan bear interest at a variable rate per annum equal to, at CTPL’s election, LIBOR or the base rate, plus the applicable margin. The applicable margin for LIBOR loans is 3.25%. Interest on LIBOR loans is due and payable at the end of each LIBOR period.
Under the terms and conditions of the 2017 CTPL Term Loan, all cash reserved to pay interest during construction is controlled by a collateral agent. These funds can only be released by the collateral agent upon satisfaction of certain terms and conditions, and are classified as restricted on our Consolidated Balance Sheets. CTPL is also required to pay annual fees to the administrative and collateral agents.
The 2017 CTPL Term Loan contains customary affirmative and negative covenants. The obligations of CTPL under the 2017 CTPL Term Loan are secured by a first priority lien on substantially all of the personal property of CTPL and all of the general partner and limited partner interests in CTPL.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
Cheniere Partners has guaranteed (i) the obligations of CTPL under the 2017 CTPL Term Loan if the maturity of the CTPL loans is accelerated following the termination by Sabine Pass Liquefaction of a transportation precedent agreement in limited circumstances and (ii) the obligations of Cheniere Energy Investments, LLC (“Cheniere Investments”), Cheniere Partners’ wholly owned subsidiary, in connection with its obligations under an equity contribution agreement (a) to pay operating expenses of CTPL until CTPL receives revenues under a service agreement with Sabine Pass Liquefaction and (b) to fund interest payments on the CTPL loans after the funds in an interest reserve account have been exhausted.
Sabine Pass Liquefaction LC Agreement
In April 2014, Sabine Pass Liquefaction entered into a $325.0 million senior letter of credit and reimbursement agreement (the “Sabine Pass Liquefaction LC Agreement”) that it uses for the issuance of letters of credit for certain working capital requirements related to the Sabine Pass Liquefaction Project. Sabine Pass Liquefaction pays (a) a commitment fee in an amount equal to an annual rate of 0.75% of an amount equal to the unissued portion of letters of credit available pursuant to the Sabine Pass Liquefaction LC Agreement and (b) a letter of credit fee equal to an annual rate of 2.5% of the undrawn portion of all letters of credit issued under the Sabine Pass Liquefaction LC Agreement. If draws are made upon any letters of credit issued under the Sabine Pass Liquefaction LC Agreement, the amount of the draw will be deemed a loan issued to Sabine Pass Liquefaction. Sabine Pass Liquefaction is required to pay the full amount of this loan on or prior to the business day immediately succeeding the deemed issuance of the loan. These loans bear interest at a rate of 2.0% plus the base rate as defined in the Sabine Pass Liquefaction LC Agreement. As of December 31, 2014, Sabine Pass Liquefaction had issued letters of credit in an aggregate amount of $9.5 million and no draws had been made upon any letters of credit issued under the Sabine Pass Liquefaction LC Agreement.
Fair Value Disclosures
The following table (in thousands) shows the carrying amount and estimated fair value of our long-term debt:
(1)
The Level 2 estimated fair value was based on quotations obtained from broker-dealers who make markets in these and similar instruments based on the closing trading prices on December 31, 2014 and 2013, as applicable.
(2)
The Level 3 estimated fair value approximates the carrying amount because the interest rates are variable and reflective of market rates and Sabine Pass Liquefaction has the ability to call this debt at any time without penalty.
(3)
The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including our stock price and interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market.
(4)
The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and CTPL has the ability to call this debt at any time without penalty.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
NOTE 10-INCOME TAXES
Income tax provision included in our reported net loss consisted of the following (in thousands):
The reconciliation of the federal statutory income tax rate to our effective income tax rate is as follows:
Significant components of our deferred tax assets and liabilities at December 31, 2014 and 2013 are as follows (in thousands):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
At December 31, 2014, we had federal and state net operating loss (“NOL”) carryforwards of approximately $3.5 billion. This excludes the NOL carryforwards related to unrecognized tax benefits and stock compensation windfalls that have not been recognized under GAAP. These NOL carryforwards will expire between 2028 and 2034.
Due to our history of NOLs, current year NOLs and significant risk factors related to our ability to generate taxable income, we have established a valuation allowance to fully offset our net deferred tax assets as of December 31, 2014 and 2013. We will continue to evaluate our ability to release the valuation allowance in the future. The change in the net deferred tax asset valuation allowance was $136.1 million for the year ended December 31, 2014.
Changes in the balance of unrecognized tax benefits are as follows (in thousands):
Our effective tax rate will not be affected if the unrecognized federal income tax benefits provided above were recognized. Currently, we do not recognize any accrued liabilities, interest and penalties associated with the unrecognized tax benefits provided above in our Consolidated Statements of Operations or our Consolidated Balance Sheets. Any applicable interest and penalties related to unrecognized tax benefits would be recorded to our income tax provision.
We experienced an ownership change within the provisions of Internal Revenue Code (“IRC”) Section 382 in 2008, 2010 and 2012. An analysis of the annual limitation on the utilization of our NOLs was performed in accordance with IRC Section 382. It was determined that IRC Section 382 will not limit the use of our NOLs in full over the carryover period. We will continue to monitor trading activity in our shares which may cause an additional ownership change which could ultimately affect our ability to fully utilize our existing tax NOL carryforwards.
We are subject to taxation in the U.S., United Kingdom, Chile, Singapore and various state jurisdictions. The federal tax returns for the years before 2010 remain open to examination for the purpose of determining the amount of remaining tax NOL and other carryforwards. The federal tax returns for the years 2011 through 2014 remain open for all purposes of examination by the IRS and other taxing authorities.
Accounting for share-based compensation provides that when settlement of a share based award contributes to an NOL carryforward, neither the associated excess tax benefit nor the credit to additional paid-in capital (“APIC”) should be recorded until the share-based award deduction reduces income tax payable. Upon utilization of the loss in future periods, a benefit of $130.5 million will be reflected in APIC.
NOTE 11-SHARE-BASED COMPENSATION
We have granted stock, restricted stock, phantom units and options to purchase common stock to employees, outside directors and a consultant under the Cheniere Energy, Inc. Amended and Restated 1997 Stock Option Plan (the “1997 Plan”), Amended and Restated 2003 Stock Incentive Plan, as amended (the “2003 Plan”), and 2011 Incentive Plan, as amended (the “2011 Plan”).
The 1997 Plan provides for the issuance of stock options to purchase up to 5.0 million shares of our common stock, all of which have been granted. Non-qualified stock options were granted to employees, contract service providers and outside directors. The 2003 Plan and 2011 Plan provide for the issuance of 21.0 million shares and 35.0 million shares, respectively, of our common stock that may be in the form of non-qualified stock options, incentive stock options, purchased stock, restricted (non-vested) stock, bonus (unrestricted) stock, stock appreciation rights, phantom units and other share-based performance awards deemed by the Compensation Committee of our Board of Directors (the “Compensation Committee”) to be consistent with the purposes of the 2003 Plan and 2011 Plan. As of December 31, 2014, all of the shares under the 2003 Plan have been granted and approximately 27 million shares, net of cancellations, have been granted under the 2011 Plan.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
For the years ended December 31, 2014, 2013 and 2012, the total share-based compensation expense, net of capitalization, recognized in our net loss was $102.0 million, $271.4 million and $58.7 million, respectively, and for the same periods we capitalized as part of the cost of capital assets $8.2 million, $12.5 million and $2.4 million, respectively. We did not recognize any cumulative adjustments in our compensation expense for the years ended December 31, 2014, 2013 and 2012.
The total unrecognized compensation cost at December 31, 2014 relating to non-vested share-based compensation arrangements granted under the 1997 Plan, 2003 Plan and 2011 Plan was $172.1 million, which is expected to be recognized over a weighted average period of 2.8 years.
During the year ended December 31, 2014, we recognized $10.8 million of share-based compensation expense related to the modification of long-term commercial bonus awards resulting from an employee termination.
We have disclosed the deferred tax benefit realized from share-based compensation exercised during the annual period in Note 10-Income Taxes. A valuation allowance equal to the deferred tax asset has been established due to the uncertainty of realizing the tax benefits related to this deferred tax asset.
Restricted Stock
Restricted stock awards are awards of common stock that are subject to restrictions on transfer and to a risk of forfeiture if the recipient terminates employment with the Company prior to the lapse of the restrictions. For the years ended December 31, 2014, 2013 and 2012, we issued 549,774 shares,18,860,000 shares and 10,293,000 shares, respectively, of restricted stock awards to our employees, executives, directors and a consultant. These awards vest based on service conditions (one, three or four-year service periods), performance conditions and/or market conditions. The amortization of the value of restricted stock grants is accounted for as a charge to compensation expense or capitalized, depending on the employee, with a corresponding increase to additional paid-in-capital over the requisite service period.
Grants of restricted stock to employees and non-employee directors that vest based on service and/or performance conditions are measured at the closing quoted market price of the Company’s common stock on the grant date. For restricted stock awards granted to non-employees that vest based on service and/or performance conditions, the Company records compensation cost equal to the fair value of the award at the measurement date, which is determined to be the earlier of the performance commitment date or the service completion date. In addition, compensation cost for unvested restricted stock awards to non-employees is adjusted quarterly for any changes in the Company’s stock price.
Grants of restricted stock to employees and non-employees based on market conditions are measured using valuations based on Monte Carlo simulations. There were no awards granted with market conditions in 2014 or 2012. For the awards granted in 2013 with market conditions, we used the following variables in our Monte Carlo simulations:
•
Expected Volatility 44% - 62%
•
Risk Free Rate 2.80% - 2.83%
•
Cost of Equity 16.50% - 16.60%
In July 2012, we met the criteria to determine the long-term commercial bonus pool that was established by the Compensation Committee in the 2011-2013 Bonus Plan in relation to Trains 1 and 2 of the Sabine Pass Liquefaction Project. In August 2012, the Compensation Committee approved a long-term commercial bonus pool, which consisted of approximately $60 million in cash awards and 10 million restricted shares of common stock to be issued under the 2011 Plan. The first restricted stock award installment vested in August 2012 when Sabine Pass Liquefaction issued its full notice to proceed (“NTP”) to Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) under the lump sum turnkey contract Sabine Pass Liquefaction entered into with Bechtel for the engineering, procurement and construction of Trains 1 and 2 of the Sabine Pass Liquefaction Project. The restricted stock awards vest in five installments as follows:
•
35% when NTP is issued;
•
10% on the first anniversary of the issuance of NTP;
•
15% on the second anniversary of the issuance of NTP;
•
15% on the third anniversary of the issuance of NTP; and
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•
25% on the fourth anniversary of the issuance of NTP.
In general, employees must be employed at the time of each vesting to receive the awards or will otherwise forfeit such awards. Vesting and payment of the awards would accelerate in full upon (i) termination of employment by the Company without “Cause” or, solely in the case of executive officers, termination of employment by the employee for “Good Reason” (each as defined in the restricted stock award agreement), (ii) the employee’s death or disability, or (iii) the occurrence of a change of control.
On December 12, 2012, pursuant to the 2011-2013 Bonus Plan, the Compensation Committee approved a Long-Term Bonus Pool for 2012 for all employees of the Company consisting of a total of 18 million shares of restricted stock. The Long-Term Commercial Bonus Awards for Trains 3 and 4 of the Sabine Pass Liquefaction Project were granted to employees in February 2013 under the 2003 Plan and 2011 Plan. A portion of each employee’s Long-Term Commercial Bonus Award for Trains 3 and 4 of the Sabine Pass Liquefaction Project was granted as a milestone award (“Milestone Award”), with vesting of the Milestone Award conditional on certain performance milestones relating to financing and constructing Trains 3 and 4 of the Sabine Pass Liquefaction Project, and a portion was granted as a stock price award (“Stock Price Award”), with vesting of the Stock Price Award conditional on the achievement of minimum average Company stock price hurdles.
On May 22, 2013, the $25 stock price hurdle was achieved. Following certification by a subcommittee of the Compensation Committee, 50% of the Stock Price Awards vested. On December 6, 2013, the $35 stock price hurdle was achieved. Following certification by a subcommittee of the Compensation Committee, the remaining 50% of the Stock Price Awards vested.
On May 28, 2013, the first performance milestone was achieved when Sabine Pass Liquefaction completed the financing for, and issued notice to proceed with construction under, the lump sum turnkey contract that Sabine Pass Liquefaction entered into with Bechtel for the engineering, procurement and construction of Trains 3 and 4 of the Sabine Pass Liquefaction Project (the “EPC Contract (Trains 3 and 4)”). Following certification of the achievement of the performance milestone by a subcommittee of the Compensation Committee, 30% of the Milestone Awards vested.
On October 1, 2014, the second performance milestone was achieved upon Sabine Pass Liquefaction’s payment of 60% of the original contract price of the EPC Contract (Trains 3 and 4). Following certification of the achievement of the performance milestone by a subcommittee of the Compensation Committee, 20% of the Milestone Awards vested.
The remaining Milestone Awards will vest based on the achievement of the following performance milestones:
•
20% upon substantial completion, as defined in the EPC Contract (Trains 3 and 4), of Train 4 of the Sabine Pass Liquefaction Project; and
•
30% on the first anniversary of substantial completion of Train 4 of the Sabine Pass Liquefaction Project.
The table below provides a summary of the status of our restricted stock under the 2003 Plan and 2011 Plan as of December 31, 2014 (in thousands, except for per share information):
The weighted average grant date fair values per share of restricted stock granted during the years ended December 31, 2014, 2013 and 2012 were $60.09, $21.89 and $14.06, respectively. The total grant date fair value per share of shares vested during the years ended December 31, 2014, 2013 and 2012 were $18.99, $19.40 and $12.76, respectively.
Phantom Units
Phantom units are incentive based equity awards issued to employees over a vesting period that entitle the grantee to receive the cash equivalent to the value of a share of our common stock upon each vesting. Phantom units are not eligible to receive quarterly distributions. The Company records compensation cost equal to the fair value of the award at the measurement date,
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
which is determined to be the earlier of the performance commitment date or the service completion date. In addition, compensation cost for unvested phantom unit awards is adjusted quarterly for any changes in the Company’s stock price. During the year ended December 31, 2014, we granted approximately 79,000 phantom units to employees and recognized $0.2 million of share-based compensation related to these grants.
Stock Options
Stock options to employees are valued at the date of grant using a Black-Scholes valuation model and the cost is recognized over the option vesting period. We did not issue any options to purchase shares of our common stock and did not declare dividends on our common stock during the years ended December 31, 2014, 2013 and 2012.
The table below provides a summary of option activity under the 1997 Plan, 2003 Plan and 2011 Plan as of December 31, 2014:
The weighted average grant-date fair value of options granted during each of the years ended December 31, 2014, 2013 and 2012 was zero. The total intrinsic value of options exercised during the years ended December 31, 2014, 2013 and 2012 was $11.9 million, $2.0 million and $0.7 million, respectively.
We received $10.8 million, $3.7 million and $0.8 million in the years ended December 31, 2014, 2013 and 2012, respectively, of proceeds from the exercise of stock options.
NOTE 12-EMPLOYEE BENEFIT PLAN
In 2005, we established a defined contribution plan (“401(k) Plan”). The 401(k) Plan allows eligible employees to contribute up to 100% of their compensation up to the IRS maximum. We match each employee’s salary deferrals (contributions) up to six percent of compensation and may make additional contributions at our discretion. Effective January 1, 2007, employees are immediately vested in the contributions made by us. Our contributions to the 401(k) Plan were $3.6 million, $2.3 million and $1.4 million for the years ended December 31, 2014, 2013 and 2012, respectively. We have made no discretionary contributions to the 401(k) Plan to date.
NOTE 13-LEASES
During the years ended December 31, 2014, 2013 and 2012, we recognized rental expense for all operating leases of $19.1 million, $13.9 million and $12.9 million, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
Future Annual Minimum Lease Payments
Future annual minimum lease payments, excluding inflationary adjustments, are as follows (in thousands):
(1)
Includes certain lease option renewals as they are reasonably assured.
(2)
Operating leases primarily relate to LNG vessel time charters, land site and tug leases. Lease payments for Sabine Pass LNG’s tug boat lease represent its lease payment obligation and do not take into account the payments Sabine Pass LNG will receive from third-party TUA customers that effectively offset $16.3 million, or two-thirds, of Sabine Pass LNG’s lease payment obligations, as discussed below.
Land Site Leases
We recognized $3.0 million, $2.7 million and $2.3 million of LNG terminal operating expense on our Consolidated Statements of Operations in 2014, 2013 and 2012, respectively, under the following land site leases:
In January 2005, Sabine Pass LNG exercised its options and entered into three land leases for the site of the Sabine Pass LNG terminal. The leases have an initial term of 30 years, with options to renew for six 10-year extensions with similar terms as the initial term. In February 2005, two of the three leases were amended, thereby increasing the total acreage under lease to 853 acres. In July 2012, Sabine Pass LNG entered into an additional land lease, thereby increasing the total acreage under lease to 883 acres. The annual lease payments are adjusted for inflation every five years based on a consumer price index, as defined in the lease agreements.
In November 2011, Sabine Pass Liquefaction entered into a land lease of 80.7 acres to be used as the laydown area during the construction of the Sabine Pass Liquefaction Project. The lease has an initial term of 5 years, with options to renew for five 1-year extensions with similar terms as the initial term. In December 2011, Sabine Pass Liquefaction entered into a land lease of 80.6 acres to be used for the site of the Sabine Pass Liquefaction Project. The lease has an initial term of 30 years, with options to renew for six 10-year extensions with similar terms as the initial term. The annual lease payment is adjusted for inflation every 5 years based on a consumer price index, as defined in the lease agreement.
In January 2013, Corpus Christi Liquefaction entered into a land lease of 110 acres to be used as the laydown area during the construction of the Corpus Christi Liquefaction Project. The lease has an initial term of one year, eleven months, with an option to renew for an additional period of four years, eleven months with similar terms as the initial term.
Tug Boat Agreements
In the second quarter of 2009, Sabine Pass Tug Services, LLC (“Tug Services”), Cheniere Partners’ wholly owned subsidiary, entered into a Marine Services Agreement (the “Tug Agreement”) for the use of tug boats and marine services for the Sabine Pass LNG terminal. The term of the Tug Agreement commenced in January 2008 for a period of 10 years, with an option to renew two additional, consecutive terms of 5 years each. We determined that the Tug Agreement contains a lease for the tugs specified in the Tug Agreement. In addition, we have concluded that the tug boat lease contained in the Tug Agreement is an operating lease, and as such, the equipment component of the Tug Agreement will be charged to expense over the term of the Tug Agreement as it becomes payable.
In the second quarter of 2009, Tug Services entered into a Tug Sharing Agreement with Sabine Pass LNG’s three TUA customers to provide their LNG cargo vessels with tug boat and marine services at the Sabine Pass LNG terminal and effectively
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
offset the cost of the tug boat lease. The Tug Sharing Agreement provides for each of our customers to pay Tug Services an annual service fee.
LNG Vessel Time Charters
In June 2013, Cheniere Marketing entered into three LNG vessel leases with subsidiaries of two ship owners, Dynagas, Ltd. (“Dynagas”) and Teekay LNG Operating LLC (“Teekay”), for the purpose of securing shipping capacity for its SPA with Sabine Pass Liquefaction. The leases have an initial term of 5 years with the option to renew the lease with Dynagas for a 2-year extension with similar terms as the initial term. In accordance with accounting literature on determining whether an arrangement contains a lease, we determined that the LNG vessel leases are operating leases and, as such, the equipment component of the LNG vessel leases is charged to expense over the term of the LNG vessel leases as it becomes payable.
Cheniere Marketing expects to receive delivery of the vessel leased from Dynagas in June 2015 and the vessels leased from Teekay in January 2016 and June 2016, respectively.
NOTE 14-COMMITMENTS AND CONTINGENCIES
LNG Terminal Commitments and Contingencies
Obligations under LNG TUAs
Sabine Pass LNG has entered into third-party TUAs with Total and Chevron to provide berthing for LNG vessels and for the unloading, storage and regasification of LNG at the Sabine Pass LNG terminal.
Obligations under Bechtel EPC Contracts
Sabine Pass Liquefaction has entered into lump sum turnkey contracts for the engineering, procurement and construction (“EPC”) of Trains 1 and 2 (the “EPC Contract (Trains 1 and 2)”) and the EPC Contract of Trains 3 and 4 (the “EPC Contract (Trains 3 and 4)”) with Bechtel in November 2011 and December 2012, respectively.
The EPC Contract (Trains 1 and 2) provides that Sabine Pass Liquefaction will pay Bechtel a contract price of $3.9 billion, which is subject to adjustment by change order. Sabine Pass Liquefaction has the right to terminate the EPC Contract (Trains 1 and 2) for its convenience, in which case Bechtel will be paid (i) the portion of the contract price for the work performed, (ii) costs reasonably incurred by Bechtel on account of such termination and demobilization, and (iii) a lump sum of up to $30.0 million depending on the termination date.
The EPC Contract (Trains 3 and 4) provides for (i) the procurement, engineering, design, installation, training, commissioning and placing into service of Trains 3 and 4 of the Sabine Pass Liquefaction Project and related facilities and (ii) certain modifications and improvements to Train 1, Train 2 and the Sabine Pass LNG terminal. The EPC Contract (Trains 3 and 4) provides that Sabine Pass Liquefaction will pay Bechtel a contract price of $3.8 billion, which is subject to adjustment by change order. Sabine Pass Liquefaction has the right to terminate the EPC Contract (Trains 3 and 4) for its convenience, in which case Bechtel will be paid (i) the portion of the contract price for the work performed, (ii) costs reasonably incurred by Bechtel on account of such termination and demobilization, and (iii) a lump sum of up to $30.0 million depending on the termination date.
In December 2013, Corpus Christi Liquefaction entered into lump sum turnkey contracts for the engineering, procurement and construction of Trains and related facilities for the Corpus Christi Liquefaction Project. The Corpus Christi Liquefaction stage 1 EPC contract (the “Stage 1 EPC Contract”) with Bechtel includes two Trains, two tanks, one complete berth and a second partial berth. The Corpus Christi Liquefaction stage 2 EPC contract (the “Stage 2 EPC Contract”) with Bechtel includes one Train, one additional tank and completion of the second berth. The contract price of the Stage 1 EPC Contract is approximately $7.1 billion, and the contract price for the Stage 2 EPC Contract is approximately $2.4 billion. Corpus Christi Liquefaction has the right to terminate each of these EPC contracts for its convenience, in which case Bechtel will be paid costs reasonably incurred by Bechtel on account of such termination and demobilization. In addition, upon termination Bechtel will be paid the portion of the contract price for the work performed and a lump sum of $2.5 million if such EPC contract is terminated prior to issuance of the notice to proceed and up to $30.0 million depending on the termination date if such EPC contract is terminated after issuance of the notice to proceed.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
Obligations under SPAs
Sabine Pass Liquefaction has entered into third-party SPAs with four customers which obligates Sabine Pass Liquefaction to purchase natural gas in sufficient quantities, liquefy the natural gas purchased, and deliver 834.0 million MMBtu per year of LNG to the customers’ vessels, subject to completion of construction of each of the first four Trains of the Sabine Pass Liquefaction Project as specified in the customers’ SPAs. In addition, Sabine Pass Liquefaction has entered into third-party SPAs with two customers to purchase natural gas in sufficient quantities, liquefy the natural gas purchased, and deliver 196.0 million MMBtu per year of LNG to the customers’ vessels, subject to completion of regulatory approvals, securing adequate financing, reaching a positive final investment decision to construct the relevant infrastructure, and construction of the fifth Train of the Sabine Pass Liquefaction Project.
Corpus Christi Liquefaction has entered into third-party SPAs which obligates Corpus Christi Liquefaction to purchase natural gas in sufficient quantities, liquefy the natural gas purchased, and deliver 438.7 million MMBtu per year of LNG to the customers’ vessels, subject to completion of regulatory approvals, securing adequate financing, reaching a final investment decision to construct the relevant infrastructure, and construction of the first Train at the Corpus Christi Liquefaction Project.
Obligations under Term Gas Supply Contracts
Sabine Pass Liquefaction has entered into index-based physical natural gas supply contracts to secure natural gas feedstock for the Sabine Pass Liquefaction Project. The terms of these contracts range from approximately one to seven years and commence upon the occurrence of conditions precedent, including the date of first commercial operation of specified Trains of the Sabine Pass Liquefaction Project. As of December 31, 2014, the forward notional natural gas buy position of Sabine Pass Liquefaction’s Term Gas Supply Derivatives was approximately 1,249.4 million MMBtu.
Restricted Net Assets
At December 31, 2014, our restricted net assets of consolidated subsidiaries were approximately $2,641 million.
Other Commitments
In the ordinary course of business, we have entered into certain multi-year licensing and service agreements, none of which are considered material to our financial position.
Legal Proceedings
During the second quarter of 2014, four lawsuits were filed in the Court of Chancery of the State of Delaware (the “Court”) against us and/or certain of our present and former officers and directors that challenge the manner in which abstentions were treated in connection with the stockholder vote on Amendment No. 1 to the Cheniere Energy, Inc. 2011 Incentive Plan (“Amendment No. 1”), pursuant to which, among other things, the number of shares of common stock available for issuance under the Cheniere Energy, Inc. 2011 Incentive Plan (the “2011 Plan”) was increased from 10 million to 35 million shares. The lawsuits contend that abstentions should have been counted as “no” votes in tabulating the outcome of the vote and that the stockholders did not approve Amendment No. 1 when abstentions are counted as such. The lawsuits further contend that portions of the Amended and Restated Bylaws of Cheniere Energy, Inc. adopted on April 3, 2014 are invalid and that certain disclosures relating to these matters made by us are misleading. The lawsuits assert claims for breach of contract and breach of fiduciary duty (both on a class and a derivative basis) and claims for unjust enrichment (on a derivative basis). The lawsuits seek, among other things, a declaration that the February 1, 2013 stockholder vote on Amendment No. 1 is void, disgorgement of all compensation distributed as a result of Amendment No. 1, voiding the awards made from the shares reserved pursuant to Amendment No. 1 and monetary damages. On June 16, 2014, we filed a verified application with the Court pursuant to 8 Del. C. § 205 (the “Section 205 Action”) in which we asked the Court to declare valid the issuance, pursuant to the 2011 Plan, of the 25 million additional shares of our common stock covered by Amendment No. 1, whether occurring in the past or the future.
The parties to the above-referenced lawsuits and the Section 205 Action have entered into a Stipulation and Agreement of Compromise, Settlement and Release dated December 12, 2014 (the “Stipulation”), subject to its terms and conditions, including receipt, among other things, of Court approval, to resolve the litigation.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
We have also agreed that plaintiffs’ counsel is entitled to a fee in connection with the resolution of the stockholder lawsuits, which will be paid by us, our successors in interest and/or our insurers. On February 10, 2015, plaintiffs filed an application with the Court, accompanied by a memorandum of law and expert reports, requesting an award of fees and expenses in the amount of approximately $43 million. If no agreement is reached between us and plaintiffs, we are entitled to contest the amount of fees sought by plaintiffs. The amount of the fee has not yet been determined. We have notified our insurance carriers of the claim. No assurance can be made as to whether any amounts ultimately will be recovered from the insurance carriers.
We have accrued our best estimate of probable loss in accrued liabilities on our Consolidated Balance Sheets. We estimate that the ultimate resolution of the matter could result in a total loss of up to approximately $43 million. As the approval process for the Stipulation and plaintiffs' fee award progresses, additional information could become known and we may be required to recognize additional general and administrative expense, and that amount could be material to our consolidated financial position, results of operations or cash flows.
NOTE 15-BUSINESS SEGMENT INFORMATION
We have two reportable segments: LNG terminal reporting segment and LNG and natural gas marketing reporting segment. We determine our reportable segments by identifying each segment that engaged in business activities from which it may earn revenues and incur expenses, had operating results regularly reviewed by the entities’ chief operating decision maker for purposes of resource allocation and performance assessment, and had discrete financial information. Substantially all of our revenues from external customers and long-lived assets are attributed to or located in the United States.
Our LNG terminal reporting segment consists of the Sabine Pass and Corpus Christi LNG terminals. We own and operate the Sabine Pass LNG terminal located on the Sabine Pass shipping channel in Louisiana through our ownership interest in and management agreements with Cheniere Partners. We own 100% of the general partner interest in Cheniere Partners and 80.1% of the common shares of Cheniere Holdings, which owns a 55.9% limited partner interest in Cheniere Partners. We are also developing a natural gas liquefaction facility near Corpus Christi, Texas.
Our LNG and natural gas marketing reporting segment consists of Cheniere Marketing, LLC (“Cheniere Marketing”) marketing LNG and natural gas on its own behalf and assisting Cheniere Investments in an effort to utilize the regasification capacity held at the Sabine Pass LNG terminal. Cheniere Marketing is developing a platform for LNG sales to international markets with professional staff based in the United States, United Kingdom, Singapore and Chile.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
The following table summarizes revenues (losses), loss from operations and total assets for each of our reporting segments (in thousands):
(1)
Includes corporate activities, business development, oil and gas exploration, development and exploitation, strategic activities and certain intercompany eliminations. These activities have been included in the corporate and other column due to the lack of a material impact that these activities have on our Consolidated Financial Statements.
(2)
Substantially all of the LNG terminal revenues relate to regasification capacity reservation fee payments made by Total Gas & Power North America, Inc. and Chevron U.S.A. Inc. LNG and natural gas marketing and trading revenue consists primarily of the domestic marketing of natural gas imported into the Sabine Pass LNG terminal.
(3)
Intersegment revenues primarily related to our LNG terminal segment are from tug revenues from Cheniere Marketing. These LNG terminal segment intersegment revenues are eliminated with intersegment losses in our Consolidated Statements of Operations.
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(4)
Intersegment revenues (losses) related to our LNG and natural gas marketing segment are primarily a result of international revenue allocations using a cost plus transfer pricing methodology and from Cheniere Marketing’s tug costs. These LNG and natural gas marketing segment intersegment revenues (losses) are eliminated with intersegment revenues (losses) in our Consolidated Statements of Operations.
(5)
Items to reconcile loss from operations and loss before income taxes and non-controlling interest include consolidated other income (expense) amounts as presented on our Consolidated Statements of Operations primarily related to our LNG terminal segment.
NOTE 16-SUPPLEMENTAL CASH FLOW INFORMATION
The following table provides supplemental disclosure of cash flow information (in thousands):
NOTE 17-SUBSEQUENT EVENTS
Convertible Notes
On January 16, 2015, Cheniere CCH HoldCo II, LLC, our wholly owned direct subsidiary, entered into a note purchase agreement with EIG Management Company, LLC (“EIG”) to purchase $1.5 billion of convertible notes, which is scheduled to close once we reach a positive final investment decision on the Corpus Christi Liquefaction Project. The net proceeds would be used to fund a portion of the costs of developing, constructing and placing into service the Corpus Christi Liquefaction Project.
Contingent Interest Rate Derivatives
In February 2015, Cheniere Corpus Christi Holdings, LLC (“Cheniere Corpus Christi Holdings”) entered into contingent interest rate derivatives (“Contingent Interest Rate Derivatives”) to protect against volatility of future cash flows and hedge a portion of the variable interest payments on upcoming debt facilities that will be used to pay for a portion of the costs of developing, constructing and placing into service the Corpus Christi Liquefaction Project. The Contingent Interest Rate Derivatives are conditional upon certain conditions including reaching a final investment decision to commence construction of the Corpus Christi Liquefaction Project. We will contemplate making this final investment decision based upon, among other things, entering into acceptable commercial arrangements, receiving regulatory authorizations and obtaining adequate financing to construct the facility. Upon reaching a final investment decision to commence construction of the Corpus Christi Liquefaction Project, we estimate that we will pay $32.1 million to $45.5 million related to contingency and syndication premiums. Cheniere Corpus Christi Holdings has the following Contingent Interest Rate Derivatives outstanding:
CHENIERE ENERGY, INC. AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
QUARTERLY FINANCIAL DATA
(unaudited)
Quarterly Financial Data-(in thousands, except per share amounts)
(1)
The sum of the quarterly net loss per share-basic and diluted may not equal the full year amount as the computations of the weighted average common shares outstanding for basic and diluted shares outstanding for each quarter and the full year are performed independently.
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A.
CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
Based on their evaluation as of the end of the fiscal year ended December 31, 2014, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act are (i) accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and (ii) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
Our Management’s Report on Internal Control Over Financial Reporting is included in our Consolidated Financial Statements on page 62 and is incorporated herein by reference.
ITEM 9B.
ITEM 9B.
OTHER INFORMATION
Compliance Disclosure
Pursuant to Section 13(r) of the Exchange Act, if during the fiscal year ended December 31, 2014, we or any of our affiliates had engaged in certain transactions with Iran or with persons or entities designated under certain executive orders, we would be required to disclose information regarding such transactions in our Annual Report on Form 10-K as required under Section 219 of the Iran Threat Reduction and Syria Human Rights Act of 2012 (“ITRA”). During the fiscal year ended December 31, 2014, we did not engage in any transactions with Iran or with persons or entities related to Iran.
Blackstone CQP Holdco LP, an affiliate of The Blackstone Group L.P. (“Blackstone Group”), is a holder of approximately 29% of the outstanding equity interests of Cheniere Partners and has three representatives on the Board of Directors of Cheniere Partners’ general partner. Accordingly, Blackstone Group may be deemed an “affiliate” of Cheniere Partners, as that term is defined in Exchange Act Rule 12b-2. We have received notice from Blackstone that it may include in its Annual Report on Form 10-K for the fiscal year ended December 31, 2014 disclosures pursuant to ITRA regarding one of its portfolio companies that may be deemed to be an affiliate of Blackstone Group. Because of the broad definition of “affiliate” in Exchange Act Rule 12b-2, this portfolio company of Blackstone Group, through Blackstone Group’s ownership of Cheniere Partners, may also be deemed to be an affiliate of ours.
We have received notice from Blackstone Group that Travelport Limited (“Travelport”) has engaged in the following activities: as part of its global business in the travel industry, Travelport provides certain passenger travel-related GDS and airline IT services to Iran Air and airline IT services to Iran Air Tours. The gross revenues and net profits attributable to such activities by Travelport during the fiscal year ended December 31, 2014 have not been reported by Travelport. Blackstone Group has informed us that Travelport intends to continue these business activities with Iran Air and Iran Air Tours as such activities are either exempt from applicable sanctions prohibitions or specifically licensed by the Office of Foreign Assets Control.
In our Form 10-Q reports for the quarterly periods ended on March 31, 2014, June 30, 2014 and September 30, 2014, we disclosed, under “Item 5. Other Information-Compliance Disclosure” in each such report, as amended, activities as required by Section 13(r) of the Exchange Act as transactions or dealings with the government of Iran that have not been specifically authorized by a U.S. federal department or agency. Such disclosures are incorporated herein by reference.
PART III
Pursuant to paragraph 3 of General Instruction G to Form 10-K, the information required by Items 10 through 14 of Part III of this Report is incorporated by reference from Cheniere’s definitive proxy statement, which is to be filed pursuant to Regulation 14A within 120 days after the end of Cheniere’s fiscal year ended December 31, 2014.
PART IV
ITEM 15.
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)
Financial Statements, Schedules and Exhibits
(1)
Financial Statements-Cheniere Energy, Inc. and Subsidiaries:
Management’s Reports to the Stockholders of Cheniere Energy, Inc.
Reports of Independent Registered Public Accounting Firm-KPMG LLP
Report of Independent Registered Public Accounting Firm-Ernst & Young LLP
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Loss
Consolidated Statements of Stockholders’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Supplemental Information to Consolidated Financial Statements-Quarterly Financial Data
(2)
Financial Statement Schedules:
(3)
Exhibits:
Certain of the agreements filed as exhibits to this Form 10-K contain representations, warranties, covenants and conditions by the parties to the agreements that have been made solely for the benefit of the parties to the agreement. These representations, warranties, covenants and conditions:
•
should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;
•
may have been qualified by disclosures that were made to the other parties in connection with the negotiation of the agreements, which disclosures are not necessarily reflected in the agreements;
•
may apply standards of materiality that differ from those of a reasonable investor; and
•
were made only as of specified dates contained in the agreements and are subject to subsequent developments and changed circumstances.
Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time. These agreements are included to provide you with information regarding their terms and are not intended to provide any other factual or disclosure information about the Company or the other parties to the agreements. Investors should not rely on them as statements of fact.
*
Filed herewith
**
Furnished herewith
†
Management contract or compensatory plan or arrangement
SCHEDULE I-CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CHENIERE ENERGY, INC.
CONDENSED BALANCE SHEETS
(in thousands)
The accompanying notes are an integral part of these condensed financial statements.
SCHEDULE I-CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CHENIERE ENERGY, INC.
CONDENSED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS
(in thousands)
The accompanying notes are an integral part of these condensed financial statements.
SCHEDULE I-CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CHENIERE ENERGY, INC.
CONDENSED STATEMENTS OF CASH FLOWS
(in thousands)
The accompanying notes are an integral part of these condensed financial statements.
SCHEDULE I-CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CHENIERE ENERGY, INC.
NOTES TO CONDENSED FINANCIAL STATEMENTS
NOTE 1-SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The condensed financial statements represent the financial information required by Securities and Exchange Commission Regulation S-X 5-04 for Cheniere Energy, Inc. (“Cheniere”).
In the condensed financial statements, Cheniere’s investments in affiliates are presented under the equity method of accounting. Under this method, the assets and liabilities of affiliates are not consolidated. The investments in net assets of the affiliates are recorded in the balance sheets. The loss from operations of the affiliates is reported on a net basis as investment in affiliates (investment in and equity in net losses of affiliates).
A substantial amount of Cheniere’s operating, investing and financing activities are conducted by its affiliates. The condensed financial statements should be read in conjunction with Cheniere’s Consolidated Financial Statements.
NOTE 2-DEBT
As of December 31, 2014 and 2013, our debt consisted of the following (in thousands):
Note-Affiliate
In May 2007, we entered into a $391.7 million long-term note (“Note-Affiliate”) with Cheniere Subsidiary Holdings, LLC (“Cheniere Subsidiary”), a wholly owned subsidiary of Cheniere. Cheniere Subsidiary received the $391.7 million net proceeds from a $400.0 million credit agreement entered into in May 2007. Borrowings under the Note-Affiliate bear interest equal to the terms of Cheniere Subsidiary’s credit agreement at a fixed rate of 9¾% per annum. Interest is calculated on the unpaid principal amount of the Note-Affiliate outstanding and is payable quarterly in arrears on March 31, June 30, September 30 and December 31 of each year. In August 2008, the Note-Affiliate was replaced with a global intercompany note entered into by all Cheniere subsidiaries that were parties to the $250.0 million credit agreement entered into in August 2008. Each subsidiary is both a maker and a payee under the global intercompany note, and balances between subsidiaries are as recorded on Cheniere’s books and records. The $391.7 million of proceeds from the Note-Affiliate were used for general corporate purposes, including our repurchase, completed during 2007, of approximately 9 million shares of our outstanding common stock pursuant to the exercise of the call options acquired in the issuer call spread purchased by us in connection with the issuance of the $325.0 million convertible senior unsecured notes due August 2012. In January 2012, we decreased a portion of the Note-Affiliate principal balance with offsetting intercompany receivables that resulted in a new principal balance of $93.7 million.
NOTE 3-GUARANTEES
Guarantees on Behalf of Cheniere Marketing, LLC
Many of Cheniere Marketing, LLC’s natural gas purchase, sale, transportation and shipping agreements have been guaranteed by Cheniere. As of December 31, 2014, these guaranteed contracts have zero amount of exposure to the potential of future payments and there was zero carrying amount of liability related to these guaranteed contracts.
Guarantee on behalf of Sabine Pass Tug Services, LLC
Sabine Pass Tug Services, LLC (“Tug Services”), a wholly owned subsidiary of Cheniere Energy Partners, L.P., entered into a Marine Services Agreement (“Tug Agreement”) for three tugs with Alpha Marine Services, LLC. The initial term of the Tug Agreement ends on the tenth anniversary of the service date, with Tug Services having the option for two additional extension terms of five years each. This contract has been guaranteed by Cheniere for up to $5.0 million.
SCHEDULE I-CONDENSED FINANCIAL INFORMATION OF REGISTRANT
NOTE 4 -SUPPLEMENTAL CASH FLOW INFORMATION
(1)
Amounts represent equity losses of affiliates and non-controlling interest not funded by Cheniere.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
CHENIERE ENERGY, INC.
(Registrant)
By:
/s/ Charif Souki
Charif Souki
Chief Executive Officer, President and
Chairman of the Board
Date:
February 19, 2015
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.